John R. Kasich, Governor

Mary Taylor, Lt. Governor

Scott J. Nally, Director

50 West Town Street • Suite 700 • P.O. Box 1049 • Columbus, OH 43216-1049

www.epa.ohio.gov • (614) 644-3020 • (614) 644-3184 (fax)

6/18/2013

William Martin

Oregon Clean Energy Center

20 Park Plaza, Suite 456

Boston, MA 02216

RE: FINALAIR POLLUTION PERMIT-TO-INSTALL

Facility ID: 0448020102

Permit Number: P0110840

Permit Type: Initial Installation

County: Lucas

Dear Permit Holder:

Enclosed please find a final Ohio Environmental Protection Agency (EPA)Air Pollution Permit-to-Install (PTI) 

which will allow you to install or modify the described emissions unit(s) in a manner indicated in the permit. 

Because this permit contains several conditions and restrictions, we urge you to read it carefully. Because this 

permit contains conditions and restrictions, please read it very carefully. In this letter you will find the 

information on the following topics:

 How to appeal this permit

 How to save money, reduce pollution and reduce energy consumption

 How to give us feedback on your permitting experience

 How to get an electronic copy of your permit

How to appeal this permit

The issuance of this PTI is a final action of the Director and may be appealed to the Environmental Review 

Appeals Commission pursuant to Section 3745.04 of the Ohio Revised Code. The appeal must be in writing 

and set forth the action complained of and the grounds upon which the appeal is based. The appeal must be 

filed with the Commission within thirty (30) days after notice of the Director's action. The appeal must be 

accompanied by a filing fee of $70.00, made payable to “Ohio Treasurer Josh Mandel," which the Commission, 

in its discretion, may reduce if by affidavit you demonstrate that payment of the full amount of the fee would 

cause extreme hardship. Notice of the filing of the appeal shall be filed with the Director within three (3) days 

of filing with the Commission. Ohio EPA requests that a copy of the appeal be served upon the Ohio Attorney 

General’s Office, Environmental Enforcement Section. An appeal may be filed with the Environmental Review 

Appeals Commission at the following address:

Environmental Review Appeals Commission

77 South High Street, 17th Floor

Columbus, OH 43215

Certified Mail

Yes TOXIC REVIEW

Yes PSD

Yes SYNTHETIC MINOR TO AVOID MAJOR NSR

Yes CEMS

Yes MACT/GACT

Yes NSPS

No NESHAPS

No NETTING

No MAJOR NON-ATTAINMENT

Yes MODELING SUBMITTED

Yes MAJOR GHG

No SYNTHETIC MINOR TO AVOID MAJOR GHG
How to save money, reduce pollution and reduce energy consumption

The Ohio EPA is encouraging companies to investigate pollution prevention and energy conservation. Not 

only will this reduce pollution and energy consumption, but it can also save you money. If you would like to 

learn ways you can save money while protecting the environment, please contact our Office of Compliance 

Assistance and Pollution Prevention at (614) 644-3469. Additionally, all or a portion of the capital expenditures 

related to installing air pollution control equipment under this permit may be eligible for financing and State tax 

exemptions through the Ohio Air Quality Development Authority (OAQDA) under Ohio Revised Code Section 

3706. For more information, see the OAQDA website: www.ohioairquality.org/clean_air

How to give us feedback on your permitting experience

Please complete a survey at www.epa.ohio.gov/dapc/permitsurvey.aspx and give us feedback on your 

permitting experience. We value your opinion.

How to get an electronic copy of your permit

This permit can be accessed electronically via the eBusiness Center: Air Services in Microsoft Word format or 

in Adobe PDF on the Division of Air Pollution Control (DAPC) Web page, www.epa.ohio.gov/dapc by clicking 

the "Search for Permits" link under the Permitting topic on the Programs tab. 

If you have any questions, please contact Toledo Department of Environmental Services at (419)936-3015 or 

the Office of Compliance Assistance and Pollution Prevention at (614) 644-3469.

Sincerely,

Michael W. Ahern, Manager

Permit Issuance and Data Management Section, DAPC

Cc: U.S. EPA

TDES; Michigan; Indiana; Canada
FINAL

Division of Air Pollution Control

Permit-to-Install

for

Oregon Clean Energy Center

Facility ID: 0448020102

Permit Number: P0110840

Permit Type: Initial Installation

Issued: 6/18/2013

Effective: 6/18/2013

Division of Air Pollution Control

Permit-to-Install

for

Oregon Clean Energy Center

Table of Contents

Authorization ..................................................................................................................................................... 1

A. Standard Terms and Conditions .................................................................................................................. 3

1. Federally Enforceable Standard Terms and Conditions ......................................................................... 4

2. Severability Clause ................................................................................................................................ 4

3. General Requirements........................................................................................................................... 4

4. Monitoring and Related Record Keeping and Reporting Requirements.................................................. 5

5. Scheduled Maintenance/Malfunction Reporting ..................................................................................... 6

6. Compliance Requirements..................................................................................................................... 6

7. Best Available Technology..................................................................................................................... 7

8. Air Pollution Nuisance............................................................................................................................ 7

9. Reporting Requirements ........................................................................................................................ 7

10. Applicability............................................................................................................................................ 8

11. Construction of New Sources(s) and Authorization to Install .................................................................. 8

12. Permit-To-Operate Application............................................................................................................... 9

13. Construction Compliance Certification ................................................................................................... 9

14. Public Disclosure ................................................................................................................................... 9

15. Additional Reporting Requirements When There Are No Deviations of Federally Enforceable Emission 

Limitations, Operational Restrictions, or Control Device Operating Parameter Limitations ................... 10

16. Fees..................................................................................................................................................... 10

17. Permit Transfers .................................................................................................................................. 10

18. Risk Management Plans ...................................................................................................................... 10

19. Title IV Provisions ................................................................................................................................ 10

B. Facility-Wide Terms and Conditions........................................................................................................... 11

C. Emissions Unit Terms and Conditions ....................................................................................................... 13

1. B001, Auxiliary Boiler........................................................................................................................... 14

2. P003, Emergency Generator................................................................................................................ 24

3. P004, Emergency Fire Pump ............................................................................................................... 34

4. P005, Wet Cooling Tower .................................................................................................................... 44

5. Emissions Unit Group -P001 and P002: CTG #1 and CTG #2 ............................................................ 48

Final Permit-to-Install

Oregon Clean Energy Center

Permit Number: P0110840

Facility ID: 0448020102

Effective Date:6/18/2013

Page 1 of 86

Authorization

Facility ID: 0448020102

Facility Description: 800 MW combined cycle gas turbine (CCGT) facility

Application Number(s): A0045417, A0046584, A0047327

Permit Number: P0110840

Permit Description: Installation of a natural gas-fired combined cycle combustion turbine power plant.

Permit Type: Initial Installation

Permit Fee: $6,050.00

Issue Date: 6/18/2013

Effective Date: 6/18/2013

This document constitutes issuance to:

Oregon Clean Energy Center

816 Lallendorf Rd

Oregon, OH 43616

of a Permit-to-Install for the emissions unit(s) identified on the following page.

Ohio Environmental Protection Agency (EPA) District Office or local air agency responsible for processing and 

administering your permit:

Toledo Department of Environmental Services

348 South Erie Street

Toledo, OH 43604

(419)936-3015

The above named entity is hereby granted a Permit-to-Install for the emissions unit(s) listed in this section 

pursuant to Chapter 3745-31 of the Ohio Administrative Code. Issuance of this permit does not constitute 

expressed or implied approval or agreement that, if constructed or modified in accordance with the plans 

included in the application, the emissions unit(s) of environmental pollutants will operate in compliance with 

applicable State and Federal laws and regulations, and does not constitute expressed or implied assurance 

that if constructed or modified in accordance with those plans and specifications, the above described 

emissions unit(s) of pollutants will be granted the necessary permits to operate (air) or NPDES permits as 

applicable.

This permit is granted subject to the conditions attached hereto.

Ohio Environmental Protection Agency

Scott J. Nally

Director
Final Permit-to-Install

Oregon Clean Energy Center

Permit Number: P0110840

Facility ID: 0448020102

Effective Date:6/18/2013

Page 2 of 86

Authorization (continued)

Permit Number: P0110840

Permit Description: Installation of a natural gas-fired combined cycle combustion turbine power plant.

Permits for the following Emissions Unit(s) or groups of Emissions Units are in this document as indicated 

below:

Emissions Unit ID: B001

Company Equipment ID: Auxiliary Boiler

Superseded Permit Number:

General Permit Category and Type: Not Applicable

Emissions Unit ID: P003

Company Equipment ID: Emergency Generator

Superseded Permit Number:

General Permit Category and Type: Not Applicable

Emissions Unit ID: P004

Company Equipment ID: Emergency Fire Pump

Superseded Permit Number:

General Permit Category and Type: Not Applicable

Emissions Unit ID: P005

Company Equipment ID: Wet Cooling Tower

Superseded Permit Number:

General Permit Category and Type: Not Applicable

Group Name: P001 and P002

Emissions Unit ID: P001

Company Equipment ID: CTG #1

Superseded Permit Number:

General Permit Category andType: Not Applicable

Emissions Unit ID: P002

Company Equipment ID: CTG #2

Superseded Permit Number:

General Permit Category andType: Not Applicable
Final Permit-to-Install

Oregon Clean Energy Center

Permit Number: P0110840

Facility ID: 0448020102

Effective Date:6/18/2013

Page 3 of 86

A. Standard Terms and Conditions
Final Permit-to-Install

Oregon Clean Energy Center

Permit Number: P0110840

Facility ID: 0448020102

Effective Date:6/18/2013

Page 4 of 86

1. Federally Enforceable Standard Terms and Conditions

a) All Standard Terms and Conditions are federally enforceable, with the exception of those listed 

below which are enforceable under State law only:

(1) Standard Term and Condition A.2.a), Severability Clause

(2) Standard Term and Condition A.3.c) through A. 3.e)General Requirements

(3) Standard Term and Condition A.6.c) and A. 6.d), Compliance Requirements

(4) Standard Term and Condition A.9., Reporting Requirements

(5) Standard Term and Condition A.10., Applicability

(6) Standard Term and Condition A.11.b) through A.11.e), Construction of New Source(s) 

and Authorization to Install

(7) Standard Term and Condition A.14., Public Disclosure

(8) Standard Term and Condition A.15., Additional Reporting Requirements When There 

Are No Deviations of Federally Enforceable Emission Limitations, Operational 

Restrictions, or Control Device Operating Parameter Limitations

(9) Standard Term and Condition A.16., Fees

(10) Standard Term and Condition A.17., Permit Transfers

2. Severability Clause

a) A determination that any term or condition of this permit is invalid shall not invalidate the force or 

effect of any other term or condition thereof, except to the extent that any other term or condition 

depends in whole or in part for its operation or implementation upon the term or condition 

declared invalid.

b) All terms and conditions designated in parts B and C of this permit are federally enforceable as 

a practical matter, if they are required under the Act, or any of its applicable requirements, 

including relevant provisions designed to limit the potential to emit of a source, are enforceable 

by the Administrator of the U.S. EPA and the State and by citizens (to the extent allowed by 

section 304 of the Act) under the Act. Terms and conditions in parts B and C of this permit shall 

not be federally enforceable and shall be enforceable under State law only, only if specifically 

identified in this permit as such.

3. General Requirements

a) The permittee must comply with all terms and conditions of this permit. Any noncompliance with 

the federally enforceable terms and conditions of this permit constitutes a violation of the Act, 

and is grounds for enforcement action or for permit revocation, revocation and re-issuance, or 

modification.
Final Permit-to-Install

Oregon Clean Energy Center

Permit Number: P0110840

Facility ID: 0448020102

Effective Date:6/18/2013

Page 5 of 86

b) It shall not be a defense for the permittee in an enforcement action that it would have been 

necessary to halt or reduce the permitted activity in order to maintain compliance with the 

federally enforceable terms and conditions of this permit.

c) This permit may be modified, revoked, or revoked and reissued, for cause. The filing of a 

request by the permittee for a permit modification, revocation and reissuance, or revocation, or 

of a notification of planned changes or anticipated noncompliance does not stay any term and 

condition of this permit.

d) This permit does not convey any property rights of any sort, or any exclusive privilege.

e) The permittee shall furnish to the Director of the Ohio EPA, or an authorized representative of 

the Director, upon receipt of a written request and within a reasonable time, any information that 

may be requested to determine whether cause exists for modifying or revoking this permit or to 

determine compliance with this permit. Upon request, the permittee shall also furnish to the 

Director or an authorized representative of the Director, copies of records required to be kept by 

this permit. For information claimed to be confidential in the submittal to the Director, if the 

Administrator of the U.S. EPA requests such information, the permittee may furnish such 

records directly to the Administrator along with a claim of confidentiality.

4. Monitoring and Related Record Keeping and Reporting Requirements

a) Except as may otherwise be provided in the terms and conditions for a specific emissions unit, 

the permittee shall maintain records that include the following, where applicable, for any 

required monitoring under this permit:

(1) The date, place (as defined in the permit), and time of sampling or measurements.

(2) The date(s) analyses were performed.

(3) The company or entity that performed the analyses.

(4) The analytical techniques or methods used.

(5) The results of such analyses.

(6) The operating conditions existing at the time of sampling or measurement. 

b) Each record of any monitoring data, testing data, and support information required pursuant to 

this permit shall be retained for a period of five years from the date the record was created. 

Support information shall include, but not be limited to all calibration and maintenance records 

and all original strip-chart recordings for continuous monitoring instrumentation, and copies of all 

reports required by this permit. Such records may be maintained in computerized form.

c) Except as may otherwise be provided in the terms and conditions for a specific emissions unit, 

the permittee shall submit required reports in the following manner:

(1) Reports of any required monitoring and/or recordkeeping of federally enforceable 

information shall be submitted to the Toledo Department of Environmental Services.
Final Permit-to-Install

Oregon Clean Energy Center

Permit Number: P0110840

Facility ID: 0448020102

Effective Date:6/18/2013

Page 6 of 86

(2) Quarterly written reports of (i) any deviations from federally enforceable 

emissionlimitations, operationalrestrictions, 

andcontroldeviceoperatingparameterlimitations, excluding deviations resulting from 

malfunctions reported in accordance with OAC rule 3745-15-06, that have been detected 

by the testing, monitoring and recordkeeping requirements specified in this permit, (ii) 

the probable cause of such deviations, and (iii) any corrective actions or preventive 

measures taken, shall be made to the Toledo Department of Environmental Services. 

The written reports shall be submitted (i.e., postmarked) quarterly, by January 31, April 

30, July 31, and October 31 of each year and shall cover the previous calendar quarters. 

See A.15. below if no deviations occurred during the quarter.

(3) Written reports, which identify any deviations from the federally enforceable monitoring, 

recordkeeping, andreportingrequirements contained in this permit shall be submitted 

(i.e., postmarked) to the Toledo Department of Environmental Services every six 

months, by January 31 and July 31 of each year for the previous six calendar months. 

If no deviations occurred during a six-month period, the permittee shall submit a semiannual report, which states that no deviations occurred during that period.

(4) This permit is for an emissions unit located at a Title V facility. Each written report shall 

be signed by a responsible official certifying that, based on information and belief formed 

after reasonable inquiry, the statements and information in the report are true, accurate, 

and complete.

d) The permittee shall report actual emissions pursuant to OAC Chapter 3745-78 for the purpose 

of collecting Air Pollution Control Fees.

5. Scheduled Maintenance/Malfunction Reporting

Any scheduled maintenance of air pollution control equipment shall be performed in accordance with 

paragraph (A) of OAC rule 3745-15-06. The malfunction, i.e., upset, of any emissions units or any 

associated air pollution control system(s) shall be reported to the Toledo Department of Environmental 

Services in accordance with paragraph (B) of OAC rule 3745-15-06. (The definition of an upset 

condition shall be the same as that used in OAC rule 3745-15-06(B)(1) for a malfunction.) The verbal 

and written reports shall be submitted pursuant to OAC rule 3745-15-06.

Except as provided in that rule, any scheduled maintenance or malfunction necessitating the shutdown 

or bypassing of any air pollution control system(s) shall be accompanied by the shutdown of the 

emission unit(s) that is (are) served by such control system(s).

6. Compliance Requirements

a) The emissions unit(s) identified in this Permit shall remain in full compliance with all applicable 

State laws and regulations and the terms and conditions of this permit.

b) Any document (including reports) required to be submitted and required by a federally 

applicable requirement in this permit shall include a certification by a responsible official that, 

based on information and belief formed after reasonable inquiry, the statements in the 

document are true, accurate, and complete.
Final Permit-to-Install

Oregon Clean Energy Center

Permit Number: P0110840

Facility ID: 0448020102

Effective Date:6/18/2013

Page 7 of 86

c) Upon presentation of credentials and other documents as may be required by law, the permittee 

shall allow the Director of the Ohio EPA or an authorized representative of the Director to:

(1) At reasonable times, enter upon the permittee's premises where a source is located or 

the emissions-related activity is conducted, or where records must be kept under the 

conditions of this permit.

(2) Have access to and copy, at reasonable times, any records that must be kept under the 

conditions of this permit, subject to the protection from disclosure to the public of 

confidential information consistent with ORC section 3704.08.

(3) Inspect at reasonable times any facilities, equipment (including monitoring and air 

pollution control equipment), practices, or operations regulated or required under this 

permit.

(4) As authorized by the Act, sample or monitor at reasonable times substances or 

parameters for the purpose of assuring compliance with the permit and applicable 

requirements.

d) The permittee shall submit progress reports to the Toledo Department of Environmental 

Services concerning any schedule of compliance for meeting an applicable requirement. 

Progress reports shall be submitted semiannually or more frequently if specified in the 

applicable requirement or by the Director of the Ohio EPA. Progress reports shall contain the 

following:

(1) Dates for achieving the activities, milestones, or compliance required in any schedule of 

compliance, and dates when such activities, milestones, or compliance were achieved.

(2) An explanation of why any dates in any schedule of compliance were not or will not be 

met, and any preventive or corrective measures adopted.

7. Best Available Technology

As specified in OAC Rule 3745-31-05, new sources that must employ Best Available Technology (BAT)

shall comply with the Applicable Emission Limitations/Control Measures identified as BAT for each 

subject emissions unit.

8. Air Pollution Nuisance

The air contaminants emitted by the emissions units covered by this permit shall not cause a public 

nuisance, in violation of OAC rule 3745-15-07.

9. Reporting Requirements

The permittee shall submit required reports in the following manner:

a) Reports of any required monitoring and/or recordkeeping of state-only enforceable information 

shall be submitted to the Toledo Department of Environmental Services.

b) Except as otherwise may be provided in the terms and conditions for a specific emissions unit, 

quarterly written reports of (a) any deviations (excursions) from state-only required emission 
Final Permit-to-Install

Oregon Clean Energy Center

Permit Number: P0110840

Facility ID: 0448020102

Effective Date:6/18/2013

Page 8 of 86

limitations, operational restrictions, and control device operating parameter limitations that have 

been detected by the testing, monitoring, and recordkeeping requirements specified in this 

permit, (b) the probable cause of such deviations, and (c) any corrective actions or preventive 

measures which have been or will be taken, shall be submitted to the Toledo Department of 

Environmental Services. If no deviations occurred during a calendar quarter, the permittee shall 

submit a quarterly report, which states that no deviations occurred during that quarter. The 

reports shall be submitted (i.e., postmarked) quarterly, by January 31, April 30, July 31, and 

October 31 of each year and shall cover the previous calendar quarters. (These quarterly 

reports shall exclude deviations resulting from malfunctions reported in accordance with OAC 

rule 3745-15-06.)

10. Applicability

This Permit-to-Install is applicable only to the emissions unit(s) identified in the Permit-to-Install. 

Separate application must be made to the Director for the installation or modification of any other 

emissions unit(s).

11. Construction of New Sources(s) and Authorization to Install

a) This permit does not constitute an assurance that the proposed source will operate in 

compliance with all Ohio laws and regulations. This permit does not constitute expressed or 

implied assurance that the proposed facility has been constructed in accordance with the 

application and terms and conditions of this permit. The action of beginning and/or completing 

construction prior to obtaining the Director's approval constitutes a violation of OAC rule 3745-

31-02. Furthermore, issuance of this permit does not constitute an assurance that the proposed 

source will operate in compliance with all Ohio laws and regulations. Issuance of this permit is 

not to be construed as a waiver of any rights that the Ohio Environmental Protection Agency (or 

other persons) may have against the applicant for starting construction prior to the effective date 

of the permit. Additional facilities shall be installed upon orders of the Ohio Environmental 

Protection Agency if the proposed facilities cannot meet the requirements of this permit or 

cannot meet applicable standards.

b) If applicable, authorization to install any new emissions unit included in this permit shall 

terminate within eighteen months of the effective date of the permit if the owner or operator has 

not undertaken a continuing program of installation or has not entered into a binding contractual 

obligation to undertake and complete within a reasonable time a continuing program of 

installation. This deadline may be extended by up to 12 months if application is made to the 

Director within a reasonable time before the termination date and the party shows good cause 

for any such extension.

c) The permittee may notify Ohio EPA of any emissions unit that is permanently shut down (i.e., 

the emissions unit has been physically removed from service or has been altered in such a way 

that it can no longer operate without a subsequent "modification" or "installation" as defined in 

OAC Chapter 3745-31) by submitting a certification from the authorized official that identifies the 

date on which the emissions unit was permanently shut down. Authorization to operate the 

affected emissions unit shall cease upon the date certified by the authorized official that the 

emissions unit was permanently shut down. At a minimum, notification of permanent shut down 

shall be made or confirmed by marking the affected emissions unit(s) as “permanently shut 

down” in Ohio EPA’s “Air Services” along with the date the emissions unit(s) was permanently 
Final Permit-to-Install

Oregon Clean Energy Center

Permit Number: P0110840

Facility ID: 0448020102

Effective Date:6/18/2013

Page 9 of 86

removed and/or disabled. Submitting the facility profile update will constitute notifying of the 

permanent shutdown of the affected emissions unit(s).

d) The provisions of this permit shall cease to be enforceable for each affected emissions unit after 

the date on which an emissions unit is permanently shut down (i.e., emissions unit has been 

physically removed from service or has been altered in such a way that it can no longer operate 

without a subsequent "modification" or "installation" as defined in OAC Chapter 3745-31). All 

records relating to any permanently shutdown emissions unit, generated while the emissions 

unit was in operation, must be maintained in accordance with law. All reports required by this 

permit must be submitted for any period an affected emissions unit operated prior to permanent 

shut down. At a minimum, the permit requirements must be evaluated as part of the reporting 

requirements identified in this permit covering the last period the emissions unit operated.

No emissions unit certified by the authorized official as being permanently shut down may 

resume operation without first applying for and obtaining a permit pursuant to OAC Chapter 

3745-31.

e) The permittee shall comply with any residual requirements related to this permit, such as the 

requirement to submit a deviation report, air fee emission report, or other any reporting required 

by this permit for the period the operating provisions of this permit were enforceable, or as 

required by regulation or law. All reports shall be submitted in a form and manner prescribed by 

the Director. All records relating to this permit must be maintained in accordance with law.

12. Permit-To-Operate Application

The permittee is required to apply for a Title V permit pursuant to OAC Chapter 3745-77. The 

permittee shall submit a complete Title V permit application or a complete Title V permit modification 

application within twelve (12) months after commencing operation of the emissions units covered by 

this permit. However, if the proposed new or modified source(s) would be prohibited by the terms and 

conditions of an existing Title V permit, a Title V permit modification must be obtained before the 

operation of such new or modified source(s) pursuant to OAC rule 3745-77-04(D) and OAC rule 3745-

77-08(C)(3)(d).

13. Construction Compliance Certification

The applicant shall identify the following dates in the online facility profile for each new emissions unit 

identified in this permit.

a) Completion of initial installation date shall be enteredupon completion of construction and prior 

to start-up.

b) Commence operation after installation or latest modification date shall be entered within 90 days 

after commencing operation of the applicable emissions unit.

14. Public Disclosure

The facility is hereby notified that this permit, and all agency records concerning the operation of this 

permitted source, are subject to public disclosure in accordance with OAC rule 3745-49-03.
Final Permit-to-Install

Oregon Clean Energy Center

Permit Number: P0110840

Facility ID: 0448020102

Effective Date:6/18/2013

Page 10 of 86

15. Additional Reporting Requirements When There Are No Deviations of Federally Enforceable

Emission Limitations, Operational Restrictions, or Control Device Operating Parameter 

Limitations

If no deviations occurred during a calendar quarter, the permittee shall submit a quarterly report, which 

states that no deviations occurred during that quarter. The reports shall be submitted quarterly (i.e., 

postmarked), by January 31, April 30, July 31, and October 31 of each year and shall cover the 

previous calendar quarters.

16. Fees

The permittee shall pay fees to the Director of the Ohio EPA in accordance with ORC section 3745.11 

and OAC Chapter 3745-78. The permittee shall pay all applicable permit-to-install fees within 30 days 

after the issuance of any permit-to-install. The permittee shall pay all applicable permit-to-operate fees 

within thirty days of the issuance of the invoice.

17. Permit Transfers

Any transferee of this permit shall assume the responsibilities of the prior permit holder. The new 

owner must update and submit the ownership information via the “Owner/Contact Change” functionality 

in Air Services once the transfer is legally completed.The change must be submitted through Air 

Services within thirty days of the ownership transfer date. 

18. Risk Management Plans

If the permittee is required to develop and register a risk management plan pursuant to section 112(r) of 

the Clean Air Act, as amended, 42 U.S.C. 7401 et seq. ("Act"), the permittee shall comply with the 

requirement to register such a plan.

19. Title IV Provisions

If the permittee is subject to the requirements of 40 CFR Part 72 concerning acid rain, the permittee 

shall ensure that any affected emissions unit complies with those requirements. Emissions exceeding 

any allowances that are lawfully held under Title IV of the Act, or any regulations adopted thereunder, 

are prohibited.
Final Permit-to-Install

Oregon Clean Energy Center

Permit Number: P0110840

Facility ID: 0448020102

Effective Date:6/18/2013

Page 11 of 86

B. Facility-Wide Terms and Conditions
Final Permit-to-Install

Oregon Clean Energy Center

Permit Number: P0110840

Facility ID: 0448020102

Effective Date:6/18/2013

Page 12 of 86

1. All the following facility-wide terms and conditions are federally enforceable with the exception of those 

listed below which are enforceable under state law only:

a) None.

2. The permittee shall ensure that any emissions unit(s) subject to the Clean Air Interstate Rule (CAIR) 

complies/comply with the requirements of the Ohio Administrative Code (OAC) Chapter 3745-109, 

which includes submitting timely permit applications.

3. The following emissions unit contained in this permit is subject to 40 CFR Part 60 Subpart A and Dc: 

B001. The complete NSPS requirements, including the NSPS General Provisions may be accessed 

via the internet from the electronic Code of Federal Regulations (e-CFR) website www.ecfr.gov or by 

contacting the appropriate Ohio EPA district or local air agency.

4. The following emissions unit contained in this permit is subject to 40 CFR Part 60 Subpart A and IIII: 

P003 and P004. The complete NSPS requirements, including the NSPS General Provisions may be 

accessed via the internet from the electronic Code of Federal Regulations (e-CFR) website 

www.ecfr.gov or by contacting the appropriate Ohio EPA district or local air agency.

5. The following emissions unit contained in this permit is subject to 40 CFR Part 60 Subpart A and KKKK: 

P001 and P002. The complete NSPS requirements, including the NSPS General Provisions may be 

accessed via the internet from the electronic Code of Federal Regulations (e-CFR) website 

www.ecfr.gov or by contacting the appropriate Ohio EPA district or local air agency.

6. The following emissions unit contained in this permit is subject to 40 CFR Part 63 Subpart A and ZZZZ: 

P003 and P004. The complete MACT requirements, including the MACT General Provisions may be 

accessed via the internet from the electronic Code of Federal Regulations (e-CFR) website 

www.ecfr.gov or by contacting the appropriate Ohio EPA district or local air agency.
Final Permit-to-Install

Oregon Clean Energy Center

Permit Number: P0110840

Facility ID: 0448020102

Effective Date:6/18/2013

Page 13 of 86

C. Emissions Unit Terms and Conditions
Final Permit-to-Install

Oregon Clean Energy Center

Permit Number: P0110840

Facility ID: 0448020102

Effective Date:6/18/2013

Page 14 of 86

1. B001, Auxiliary Boiler

Operations, Property and/or Equipment Description: 

99 mmBtu/hr natural gas fired boiler with low-NOx burners and flue gas re-circulation

a) The following emissions unit terms and conditions are federally enforceable with the exception 

of those listed below which are enforceable under state law only.

(1) None.

b) Applicable Emissions Limitations and/or Control Requirements

(1) The specific operation(s), property, and/or equipment that constitute each emissions unit 

along with the applicable rules and/or requirements and with the applicable emissions 

limitations and/or control measures are identified below. Emissions from each unit shall 

not exceed the listed limitations, and the listed control measures shall be specified in 

narrative form following the table.

Applicable Rules/Requirements Applicable Emissions Limitations/Control 

Measures

a. OAC rule 3745-31-05(A)(3), as 

effective 11/30/2001

Sulfur dioxide (SO2) emissions shall not 

exceed 1.4E-03 pound per million Btu 

(lb/mmBtu) of heat input and 0.14 ton per 

year.

see b)(2)a. and b)(2)b.

b. OAC rule 3745-31-05(A)(3)(a)(ii), as 

effective 12/01/2006

see b)(2)c.

c. OAC rule 3745-31-10 through 20 Carbon monoxide (CO) emissions shall 

not exceed 0.055 pound per million Btu 

(lb/mmBtu) of heat input, 5.45 pounds per 

hour (lbs/hr), and 5.45 tons per rolling, 

12-month period.

Nitrogen Oxides (NOx) emissions shall 

not exceed 0.020 lb/mmBtu of heat input, 

1.98 lbs/hr, and 1.98 tons per rolling, 12-

month period.

Particulate matter emissions less than 10 

microns in diameter (PM10) and 

particulate matter less than 2.5 microns in 

diameter (PM2.5) shall not exceed 0.008 

lb/mmBtu of heat input, 0.79 lb/hr, and 

0.79 ton per rolling, 12-month period.

Volatile organic compound (VOC) 

emissions shall not exceed 0.006 
Final Permit-to-Install

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Permit Number: P0110840

Facility ID: 0448020102

Effective Date:6/18/2013

Page 15 of 86

Applicable Rules/Requirements Applicable Emissions Limitations/Control 

Measures

lb/mmBtu of heat input, 0.59 lb/hr and 

0.59 ton per rolling, 12-month period.

Sulfuric acid mist (H2SO4) emissions shall 

not exceed 1.1E-04 lb/mmBtu, 0.011 

lb/hr, and 0.011 ton per rolling, 12-month 

period.

Carbon dioxide equivalent (CO2e) 

emissions shall not exceed 11,671 tons 

per rolling, 12-month period.

Visible particulate emissions from the 

stack serving this emissions unit shall not 

exceed 10 percent opacity as a 6-minute 

average.

see b)(2)d., b)(2)e., and b)(2)k.

d. OAC rule 3745-17-07(A) see b)(2)f.

e. OAC rule 3745-17-10(B)(1) see b)(2)f.

f. OAC rule 3745-110-03(J)(16) exemption - see b)(2)l.

g. 40 CFR Part 60, Subpart A see b)(2)g.

h. 40 CFR Part 60, Subpart Dc see b)(2)h. and b)(2)i.

i. 40 CFR Part 63, Subpart JJJJJJ see b)(2)j.

(2) Additional Terms and Conditions

a. Compliance with the requirements of this rule for CO, NOx, PM10/PM2.5, and VOC 

emissions includes compliance with the requirements of OAC rule 3745-31-10 

through 20.

b. The permittee has satisfied the Best Available Technology (BAT) requirements 

pursuant to Ohio Administrative Code (OAC) paragraph 3745-31-05(A)(3), as 

effective November 30, 2001, in this permit. On December 1, 2006, paragraph 

(A)(3) of OAC rule 3745-31-05 was revised to conform to the Ohio Revised Code 

(ORC) changes effective August 3, 2006 (Senate Bill 265 changes), such that 

BAT is no longer required by State regulations for National Ambient Air Quality 

Standards (NAAQS) pollutant(s) less than ten tons per year. However, that rule 

revision has not yet been approved by U.S. EPA as a revision to Ohio’s State 

Implementation Plan (SIP). Therefore, until the SIP revision occurs and the U.S.

EPA approves the revisions to OAC rule 3745-31-05, the requirement to satisfy 

BAT still exists as part of the federally-approved SIP for Ohio. Once U.S. EPA 

approves the December 1, 2006 version of OAC rule 3745-31-05, then these 

emission limitations/control measures no longer apply.
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Page 16 of 86

c. This rule paragraph applies once U.S. EPA approves the December 1, 2006 

version of OAC rule 3745-31-05 as part of the State Implementation Plan.

The Best Available Technology (BAT) requirements under OAC rule 3745-31-

05(A)(3) do not apply to the CO, NOx, PM10/PM2.5, SO2, and VOC emissions from 

this air contaminant source since the uncontrolled potential to emit for CO, NOx, 

PM10/PM2.5, SO2, and VOC is less than 10 tons per year .

d. All particulate emissions are assumed to be less than 2.5 microns in diameter. 

The PM10/PM2.5 emissions limitations include both filterable and condensable 

particulate emissions.

e. The lb/mmBtu and lb/hr, emission limitations are based on the emissions unit's 

potentials to emit. Therefore, no monitoring, record keeping, and reporting 

requirements are necessary to ensure ongoing compliance with these emission 

limitations.

f. The emission limitation specified by this rule is less stringent than the limitation 

established by OAC rule 3745-31-10 through 20.

g. 40 CFR Part 60 subpart A provides applicability provisions, definitions, and other 

general provisions that are pertinent to emissions units affected by 40 CFR Part 

60.

h. This rule does not establish emission limitations for natural gas-fired boilers, but 

does require recordkeeping of gas usage per 40 CFR 60.48c(g).

i. This emissions unit is subject to the applicable provisions of Subpart Dc of the 

New Source Performance Standards (NSPS) as promulgated by the United 

States Environmental Protection Agency, 40 CFR Part 60. The application and 

enforcement of these standards are delegated to the Ohio EPA. The 

requirements of 40 CFR Part 60 are also federally enforceable.

j. This emissions unit is exempt from the requirements of this rule per 40 CFR 

63.11195(e) due to combusting only natural gas.

k. The maximum annual operating hours for this emissions unit shall not exceed 

2,000 hours per rolling, 12-month period.

To ensure enforceability during the first 12 calendar months of operation or the 

first 12 calendar months following the issuance of this permit, the permittee shall 

not exceed the operating hours levels specified in the following table:

Maximum Allowable

Month(s) Cumulative Operating Hours

1 720

1-2 1,440

1-3 2,000

1-4 2,000

1-5 2,000
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Effective Date:6/18/2013

Page 17 of 86

1-6 2,000

1-7 2,000

1-8 2,000

1-9 2,000

1-10 2,000

1-11 2,000

1-12 2,000

After the first 12 calendar months of operation or the first 12 calendar months 

following the issuance of this permit, compliance with the annual operating hours 

limitation shall be based upon a rolling, 12-month summation of the operating 

hours.

l. The permittee is exempt from the requirements of OAC rule 3745-110-03(A) 

through (F), since this permit restricts NOx emissions from this emissions unit to 

less than 25 tons per year.

c) Operational Restrictions

(1) The permittee shall burn only natural gas in this emissions unit.

d) Monitoring and/or Recordkeeping Requirements

(1) For each day during which the permittee burns a fuel other than natural gas, the 

permittee shall maintain a record of the type and quantity of fuel burned in this emissions 

unit.

(2) The permittee shall maintain monthly records of the following information:

a. the operating hours for each month; and

b. beginning after the first 12 calendar months of operation or the first 12 calendar 

months following the issuance of this permit, the rolling, 12-month summation of 

the operating hours.

Also, during the first 12 calendar months of operation or the first 12 calendar months 

following the issuance of this permit, the permittee shall record the cumulative operating 

hours for each calendar month.

(3) See 40 CFR Part 60, Subpart Dc (40 CFR 60.4200-4219). 

e) Reporting Requirements

(1) The permittee shall submit deviation (excursion) reports that identify each day when a 

fuel other than natural gas was burned in this emissions unit. Each report shall be 

submitted within 30 days after the deviation occurs.

(2) Pursuant to the 40 CFR Part 60.7 and 60.48c(a), the permittee is hereby advised of the 

requirement to report the following at the appropriate times:

a. construction date (no later than 30 days after such date);
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Facility ID: 0448020102

Effective Date:6/18/2013

Page 18 of 86

b. anticipated start-up date (not more than 60 days or less than 30 days prior to 

such date);

c. actual start-up date (within 15 days after such date); and

d. the design heat input capacity of the affected facility and identification of fuels to 

be combusted in the affected facility.

(3) The permittee shall submit quarterly deviation (excursion) reports that identify the 

following:

all exceedances of the rolling, 12-month limitation on the hours of operation for this 

emissions unit; and for the first 12 calendar months of operation or the first 12 calendar 

months following the issuance of this permit, all exceedances of the maximum allowable 

cumulative hours of operation;

The quarterly deviation (excursion) reports shall be submitted in accordance with the 

reporting requirements of the Standard Terms and Conditions of this permit.

(4) See 40 CFR Part 60, Subpart Dc (40 CFR 60.4200-4219).

(5) Unless other arrangements have been approved by the Director, all notifications and

reports shall be submitted through the Ohio EPA's eBusiness Center: Air Services 

online web portal.

f) Testing Requirements

(1) Compliance with the Emissions Limitations and/or Control Requirements specified in 

section b) of these terms and conditions shall be determined in accordance with the 

following methods:

a. Emission Limitation:

CO emissions shall not exceed 0.055 lb/mmBtu of heat input, 5.45 lbs/hr, and 

5.45 tons per rolling, 12-month period.

Applicable Compliance Method:

The lb/mmBtu emission limitation is based on manufacturer’s data. The hourly 

emission limitation was developed by multiplying the maximum heat input (99 

mmBtu/hr) by the CO emission factor supplied by the manufacturer (0.055 

lb/mmBtu) to determine the hourly emissions.

The annual emission limitation was developed by multiplying the hourly emission 

limitation (5.45 lbs/hr) by the maximum annual operating hours (2,000 hrs/yr) and 

dividing by 2,000 pounds per ton. Therefore, compliance with the annual 

limitation shall be demonstrated if compliance with the hourly limitation is shown.
Final Permit-to-Install

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Permit Number: P0110840

Facility ID: 0448020102

Effective Date:6/18/2013

Page 19 of 86

b. Emission Limitation:

NOx emissions shall not exceed 0.020 lb/mmBtu of heat input, 1.98 lbs/hr, and 

1.98 tons per rolling, 12-month period.

Applicable Compliance Method:

The lb/mmBtu limitation is based on manufacturer’s data. The hourly emission 

limitation was developed by multiplying the maximum heat input (99 mmBtu/hr) 

by the NOx emission factor supplied by the manufacturer (0.020 lb/mmBtu) to 

determine the hourly emissions.

The annual emission limitation was developed by multiplying the hourly emission 

limitation (1.98 lbs/hr) by the maximum annual operating hours (2,000 hrs/yr) and 

dividing by 2,000 pounds per ton. Therefore, compliance with the annual 

limitation shall be demonstrated if compliance with the hourly limitation is shown.

c. Emission Limitation:

PM10 and PM2.5 shall not exceed 0.008 lb/mmBtu of heat input, 0.79 lb/hr, and 

0.79 ton per rolling, 12-month period.

Applicable Compliance Method:

The lb/mmBtu limitation is based on manufacturer’s data. The hourly emission 

limitation was developed by multiplying the maximum heat input (99 mmBtu/hr) 

by the PM10/PM2.5 emission factor supplied by the manufacturer (0.008 lb/mmBtu) 

to determine the hourly emissions. 

If required, the permittee shall demonstrate compliance with the lb/mmBtu and 

hourly emission limitation using Methods 201 or 201A and 202 of 40 CFR Part 

51, Appendix M. Alternative U.S. EPA approved test methods may be used with 

prior approval from the Ohio EPA.

The annual emission limitation was developed by multiplying the hourly emission 

limitation (0.79 lb/hr) by the maximum annual operating hours (2,000 hrs/yr) and 

dividing by 2,000 pounds per ton. Therefore, compliance with the annual 

limitation shall be demonstrated if compliance with the hourly limitation is shown.

d. Emission Limitation:

SO2 emissions shall not exceed 1.4E-03 lb/mmBtu of heat input and 0.14 ton/yr.

Applicable Compliance Method:

The lb/mmBtu limitation was established based on using pipeline quality natural 

gas having a maximum sulfur content of 0.5 grains per 100 cubic feet according 

to the following calculation. Multiply the maximum sulfur content of natural gas 

(0.5 grain S/100 scf) by the molecular weight of SO2 (64.07 lb SO2/lb-mole) 

divide by the molecular weight of sulfur (32.06 lb S/lb-mole) divide by (7,000 

grains/lb), divide by (1,020 Btu/scf), and multiply by (106 Btu/mmBtu).
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Permit Number: P0110840

Facility ID: 0448020102

Effective Date:6/18/2013

Page 20 of 86

If required, the permittee shall demonstrate compliance with the lb/mmBtu and 

hourly emission limitation using Methods 1 thru 4 and 6C of 40 CFR Part 60, 

Appendix A. Alternative U.S. EPA approved test methods may be used with prior 

approval from the Ohio EPA.

The annual emission limitation was developed by multiplying the lb/mmBtu 

emission limitation (1.4E-03 lb/mmBtu) by the maximum heat input (99 

mmBtu/hr), multiplied by the maximum annual operating hours (2,000 hrs/yr) and 

dividing by 2,000 pounds per ton. Therefore, compliance with the annual 

limitation shall be demonstrated if compliance with the hourly limitation is shown.

e. Emission Limitation:

VOC emissions shall not exceed 0.006 lb/mmBtu of heat input, 0.59 lb/hr, and 

0.59 ton per rolling, 12-month period.

Applicable Compliance Method:

The lb/mmBtu limitation is based on manufacturer’s data. The hourly emission 

limitation was developed by multiplying the maximum heat input (99 mmBtu/hr) 

by the VOC emission factor supplied by the manufacturer (0.006 lb/mmBtu) to 

determine the hourly emissions.

If required, the permittee shall demonstrate compliance with the lb/mmBtu and 

hourly emission limitation Methods 1 through 4 and 18, 25 or 25A, as 

appropriate, of 40 CFR Part 60, Appendix A. Use of Method 18, 25 or 25A is to 

be selected based on the results of pre-survey stack sampling and U.S. EPA 

guidance documents. Alternative U.S. EPA approved test methods may be used 

with prior approval from the Ohio EPA.

The annual emission limitation was developed by multiplying the hourly emission 

limitation (0.59 lb/hr) by the maximum annual operating hours (2,000 hrs/yr) and 

dividing by 2,000 pounds per ton. Therefore, compliance with the annual 

limitation shall be demonstrated if compliance with the hourly limitation is 

maintained.

f. Emission Limitation:

Sulfuric acid mist (H2SO4) emissions shall not exceed 1.1E-04 lb/mmBtu, 0.011 

lb/hr, and 0.011 ton per rolling, 12-month period.

Applicable Compliance Method:

The lb/mmBtu emission limitation is based on the assumption that 5% of the SO2

emissions are converted to SO3 and then converted to H2SO4 when combined 

with water vapor by the following calculation.

1.4E-03 lb SO2/mmBtu(0.05)(98 lb H2SO4/lb-mole)(lb-mole/64 lb SO2) = 1.1E-04 

lb H2SO4/mmBtu
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Permit Number: P0110840

Facility ID: 0448020102

Effective Date:6/18/2013

Page 21 of 86

Multiply the lb H2SO4/mmBtu (0.11 lb/mmBtu) by the maximum heat input (99 

mmBtu/hr) to determine the maximum hourly H2SO4 emissions (0.11 lb/hr), and 

multiply by the maximum annual hours of operation (2,000 hrs/yr) divided by 

2,000 lbs/ton to determine the annual H2SO4 emissions (0.11 ton/yr).

If required, the permittee shall demonstrate compliance with the lb/mmBtu and 

lb/hr emissions limitations using Methods 1 thru 4 and 8 of 40 CFR Part 60, 

Appendix A.

g. Emission Limitation:

Carbon dioxide equivalent (CO2e) emissions shall not exceed 11,671 tons per 

rolling, 12-month period.

Applicable Compliance Method:

This emissions limitation was established to reflect the potential to emit for this 

emissions unit by calculating the sum of the product of the maximum natural gas 

usage (0.104 mmscf/hr) multiplied by the AP-42 emission factor for CO2, N2O, 

and CH4 from Table 1.4-2 dated 7/98 (120,000 lb/mmscf, 0.64 lb/mmscf, and 2.3 

lb/mmscf, respectively), multiplied by the global warming potential for CO2, N2O, 

and CH4 (1, 310, and 21, respectively from Table A-1 to Subpart A of 40 CFR 

98). Multiply the calculated sum by the natural gas heating value used in the 

application for this emissions unit (950 Btu/scf), divide by the average heating 

value used for AP-42 emission factors in Table 1.-42 dated 7/98 (1,020 Btu/scf), 

multiply by the maximum annual hours of operation (2,000 hrs/yr) and divide by 

2,000 pounds per ton. 

99



h

  120,000



 (1) + (0.64



)

(310)

+ 2.3



 (21)  



1020 2,000

h

h

  



2,000

= 11,671





Since the CO2e emissions are estimated to consist of more than 99% CO2, 

compliance with this emission limitation will be assumed provided that the lb/scf 

CO2 emission rate does not exceed 120,000 lb/mmscf.

 If required, the permittee shall conduct emissions testing using Methods 1, 2, 

3A and 4 of 40 CFR Part 60, Appendix A to determine the lb/scf CO2 emission 

rate.

h. Emission Limitation:

Visible emissions shall not exceed 10% opacity as a 6-minute average, except as 

provided by rule.
Final Permit-to-Install

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Permit Number: P0110840

Facility ID: 0448020102

Effective Date:6/18/2013

Page 22 of 86

Applicable Compliance Method:

If required, compliance with the stack visible particulate emissions limitation shall 

be determined through visible emissions observations performed in accordance 

with Method 9 of 40 CFR Part 60, Appendix A.

(2) The permittee shall conduct, or have conducted, emission testing for this emissions unit 

in accordance with the following requirements:

a. The emission testing shall be conducted within 60 days after achieving the 

maximum production rate at which the emissions unit will be operated, but not 

later than 180 days after initial startup of the emissions unit.

b. The emission testing shall be conducted to demonstrate compliance with the 

following emissions limitations:

i. CO emissions in lb/hr and lb/mmBtu; and

ii. NOx emissions in lb/hr and lb/mmBtu.

The emission testing shall also be conducted to determine the CO2 emission rate 

in lb/hr and lb/mmBtu.

c. The following test method(s) shall be employed to demonstrate compliance with 

the allowable mass emission rate(s):

for CO, Methods 1 thru 4 of 40 CFR Part 60, Appendix A; and

for NOx Methods 1 thru 4 and 7E of 40 CFR Part 60, Appendix A.

Alternative U.S. EPA approved test methods may be used with prior approval 

from the Ohio EPA.

d. The test(s) shall be conducted under those representative conditions that 

challenge to the fullest extent possible a facility’s ability to meet the applicable 

emissions limits and/or control requirements, unless otherwise specified or 

approved by the appropriate Ohio EPA District Office or local air agency. 

Although this generally consists of operating the emissions unit at its maximum 

material input/production rates and results in the highest emission rate of the 

tested pollutant, there may be circumstances where a lower emissions loading is 

deemed the most challenging control scenario. Failure to test under these 

conditions is justification for not accepting the test results as a demonstration of 

compliance.
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Facility ID: 0448020102

Effective Date:6/18/2013

Page 23 of 86

e. Not later than 30 days prior to the proposed test date(s), the permittee shall 

submit an "Intent to Test" notification to the appropriate Ohio EPA District Office 

or local air agency. The "Intent to Test" notification shall describe in detail the 

proposed test methods and procedures, the emissions unit operating 

parameters, the time(s) and date(s) of the test(s), and the person(s) who will be 

conducting the test(s). Failure to submit such notification for review and approval 

prior to the test(s) may result in the Ohio EPA District Office's or local air 

agency's refusal to accept the results of the emission test(s).

f. Personnel from the appropriate Ohio EPA District Office or local air agency shall 

be permitted to witness the test(s), examine the testing equipment, and acquire 

data and information necessary to ensure that the operation of the emissions unit 

and the testing procedures provide a valid characterization of the emissions from 

the emissions unit and/or the performance of the control equipment.

g. A comprehensive written report on the results of the emissions test(s) shall be 

signed by the person or persons responsible for the tests and submitted to the 

appropriate Ohio EPA District Office or local air agency within 30 days following 

completion of the test(s). The permittee may request additional time for the 

submittal of the written report, where warranted, with prior approval from the 

appropriate Ohio EPA District Office or local air agency.

g) Miscellaneous Requirements

(1) None.
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Permit Number: P0110840

Facility ID: 0448020102

Effective Date:6/18/2013

Page 24 of 86

2. P003, Emergency Generator

Operations, Property and/or Equipment Description: 

2,250 kW emergency diesel fired generator

a) The following emissions unit terms and conditions are federally enforceable with the exception 

of those listed below which are enforceable under state law only.

(1) None.

b) Applicable Emissions Limitations and/or Control Requirements

(1) The specific operation(s), property, and/or equipment that constitute each emissions unit 

along with the applicable rules and/or requirements and with the applicable emissions 

limitations and/or control measures are identified below. Emissions from each unit shall 

not exceed the listed limitations, and the listed control measures shall be specified in 

narrative form following the table.

Applicable Rules/Requirements Applicable Emissions Limitations/Control 

Measures

a. OAC rule 3745-31-05(A)(3), as 

effective 11/30/2001

Sulfur dioxide (SO2) emissions shall not 

exceed 0.03 pound per hour (lb/hr) and 

0.008 ton per year. 

see b)(2)a. and b)(2)b.

b. OAC rule 3745-31-05(A)(3)(a)(ii), as 

effective 12/01/2006

see b)(2)c.

c. OAC rule 3745-31-10 through 20 Carbon monoxide (CO) emissions shall 

not exceed 3.5 g/kW-hr, 17.35 pounds 

per hour (lbs/hr), and 4.34 tons per 

rolling, 12-month period.

Nitrogen oxides (NOx) emissions shall not 

exceed 5.61 g/kW-hr, 27.8 lbs/hr, and 

6.95 tons per rolling, 12-month period.

Particulate matter emissions less than 10 

microns in diameter (PM10) and 

particulate matter less than 2.5 microns in 

diameter (PM2.5) shall not exceed 0.20 

g/kW-hr, 0.99 lb/hr, and 0.25 tons per 

rolling, 12-month period.

Volatile organic compound (VOC) 

emissions shall not exceed 0.79 g/kW-hr, 

3.93 lbs/hr, and 0.98 ton per rolling, 12-

month period.
Final Permit-to-Install

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Facility ID: 0448020102

Effective Date:6/18/2013

Page 25 of 86

Applicable Rules/Requirements Applicable Emissions Limitations/Control 

Measures

Sulfuric acid mist (H2SO4) emissions shall 

not exceed 1.32E-04 g/kW-hr, 6.5 E-04 

lb/hr and 1.6E-04 ton per rolling, 12-

month period.

Carbon dioxide equivalent (CO2e) 

emissions shall not exceed 878 tons per 

rolling, 12-month period.

see b)(2)d. and b)(2)e.

d. OAC rule 3745-17-07(A) Visible particulate emissions from the 

stack serving this emissions unit shall not 

exceed 20 percent opacity as a 6-minute 

average.

e. OAC rule 3745-17-11(B)(5)(a) see b)(2)f.

f. OAC rule 3745-110-03(J)(16), and 

(J)(19) 

exemptions – see b)(2)g.

g. 40 CFR Part 60, Subpart A

(40 CFR 60.1-19)

Table 8 to Subpart IIII of 40 CFR Part 60 

– Applicability of General Provisions to 

Subpart IIII shows which parts of the 

General Provisions in 40 CFR 60.1-19 

apply.

h. 40 CFR Part 60, Subpart IIII

(40 CFR 60.4200–4219)

[In accordance with 40 CFR 

60.4200(a)(2), this emissions unit is 

a compression ignition emergency 

stationary internal combustion 

engine (CI ICE) for which 

construction commenced after July 

11, 2005 subject to the emissions 

limitation/control measures specified 

in this section.]

Non-methane hydrocarbon (NMHC) + 

NOx emissions shall not exceed 6.4 

g/kW-hr.

CO emissions shall not exceed 3.5 g/kWhr.

PM emissions shall not exceed 0.20 

g/kW-hr.

Exhaust opacity shall not exceed:

20 percent during acceleration mode;

15 percent during lugging mode; and

50 percent during the peaks in either the 

acceleration or lugging modes.

see b)(2)h.

[60.4205(b) and 60.4207(b)]

i. 40 CFR Part 63, Subpart ZZZZ

(40 CFR 63.6580-63.6675)

[In accordance with 40 CFR 

63.6590(c)(1), this emissions unit is 

a new stationary internal combustion 

see b)(2)i.

[63.6590(c), (c)(1)]
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Facility ID: 0448020102

Effective Date:6/18/2013

Page 26 of 86

Applicable Rules/Requirements Applicable Emissions Limitations/Control 

Measures

engine (RICE) located at an area 

source of HAP emissions subject to 

the emissions limitation/control 

measures specified in this section.]

(2) Additional Terms and Conditions

a. Compliance with the requirements of this rule for CO, NOx, PM10, PM2.5, and 

VOC emissions includes compliance with the requirements of OAC rule 3745-31-

10 through 20.

b. The permittee has satisfied the Best Available Technology (BAT) requirements 

pursuant to Ohio Administrative Code (OAC) paragraph 3745-31-05(A)(3), as 

effective November 30, 2001, in this permit. On December 1, 2006, paragraph 

(A)(3) of OAC rule 3745-31-05 was revised to conform to the Ohio Revised Code 

(ORC) changes effective August 3, 2006 (Senate Bill 265 changes), such that 

BAT is no longer required by State regulations for National Ambient Air Quality 

Standards (NAAQS) pollutant(s) less than ten tons per year. However, that rule 

revision has not yet been approved by U.S. EPA as a revision to Ohio’s State 

Implementation Plan (SIP). Therefore, until the SIP revision occurs and the U.S. 

EPA approves the revisions to OAC rule 3745-31-05, the requirement to satisfy 

BAT still exists as part of the federally-approved SIP for Ohio. Once U.S. EPA 

approves the December 1, 2006 version of OAC rule 3745-31-05, then these 

emission limitations/control measures no longer apply.

c. This rule paragraph applies once U.S. EPA approves the December 1, 2006 

version of OAC rule 3745-31-05 as part of the State Implementation Plan.

The Best Available Technology (BAT) requirements under OAC rule 3745-31-

05(A)(3) do not apply to the CO, NOx, PM10/PM2.5, SO2, and VOC emissions from 

this air contaminant source since the uncontrolled potential to emit for CO, NOx, 

PM10/PM2.5, SO2, and VOC is less than 10 tons per year taking into account the 

federally enforceable emissions limitations and operating hours restriction 

specified by OAC rule 3745-31-10 through 20.

d. All particulate emissions are assumed to be less than 2.5 microns in diameter. 

The PM10/PM2.5 emissions limitations include both filterable and condensable 

particulate emissions.

e. The maximum annual operating hours for this emissions unit shall not exceed 

500 hours, based upon a rolling, 12-month summation of the operating hours.

To ensure enforceability during the first 12 calendar months of operation or the 

first 12 calendar months following the issuance of this permit, the permittee shall 

not exceed the operating hours levels specified in the following table:
Final Permit-to-Install

Oregon Clean Energy Center

Permit Number: P0110840

Facility ID: 0448020102

Effective Date:6/18/2013

Page 27 of 86

Maximum Allowable

Month(s) Cumulative Operating Hours

1 500

1-2 500

1-3 500

1-4 500

1-5 500

1-6 500

1-7 500

1-8 500

1-9 500

1-10 500

1-11 500

1-12 500

After the first 12 calendar months of operation or the first 12 calendar months 

following the issuance of this permit, compliance with the annual operating hours 

limitation shall be based upon a rolling, 12-month summation of the operating 

hours.

f. The emission limitation specified by this rule is less stringent than the emission 

limitation established by OAC rule 3745-31-10 through 20. 

g. The requirements of this rule do not apply, since:

i. NOx emissions are restricted to less than 25 tons per year; and

ii. the emissions unit is subject to a BACT limitation for NOx.

h. The permittee shall only combust diesel fuel in this emissions unit meeting the 

following per gallon standards:

15 ppm maximum sulfur content; and

a minimum cetane index of 40 or a maximum aromatic content of 35 volume 

percent.

i. This emissions unit must meet the requirements of 40 CFR Part 60 Subpart IIII. 

No further requirements apply under this subpart.

c) Operational Restrictions

(1) See 40 CFR Part 60, Subpart IIII (40 CFR 60.4200-4219).

d) Monitoring and/or Recordkeeping Requirements

(1) The permittee shall maintain monthly records of the following information:

a. the operating hours for each month; and
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Permit Number: P0110840

Facility ID: 0448020102

Effective Date:6/18/2013

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b. beginning after the first 12 calendar months of operation or the first 12 calendar 

months following the issuance of this permit, the rolling, 12-month summation of 

the operating hours.

Also, during the first 12 calendar months of operation or the first 12 calendar months 

following the issuance of this permit, the permittee shall record the cumulative operating 

hours for each calendar month.

(2) For each shipment of diesel fuel received for burning in this emissions unit, the permittee 

shall maintain records of the oil supplier's (or permittee’s) analyses for sulfur content in 

parts per million (40 CFR 80.510). The permittee shall perform or require the supplier to 

perform the analyses for sulfur content in accordance with 40 CFR 80.585.

(3) The permittee shall also maintain documentation of supplier verification that the diesel 

fuel as purchased has a minimum cetane index of 40 or a maximum aromatic content of 

35 volume percent.

(4) See 40 CFR Part 60, Subpart IIII (40 CFR 60.4200-4219).

e) Reporting Requirements

(1) The permittee shall submit quarterly deviation (excursion) reports that identify the 

following:

a. each shipment of diesel fuel received for burning in this emissions unit which did 

not comply with the per gallon standards specified in b)(2); and

b. all exceedances of the rolling, 12-month limitation on the hours of operation for

this emissions unit; and for the first 12 calendar months of operation or the first 

12 calendar months following the issuance of this permit, all exceedances of the 

maximum allowable cumulative hours of operation.

The quarterly deviation (excursion) reports shall be submitted in accordance with the 

reporting requirements of the Standard Terms and Conditions of this permit.

(2) See 40 CFR Part 60, Subpart IIII (40 CFR 60.4200-4219).

(3) Unless other arrangements have been approved by the Director, all notifications and 

reports shall be submitted through the Ohio EPA's eBusiness Center: Air Services 

online web portal.

f) Testing Requirements

(1) Compliance with the Emissions Limitations and/or Control Requirements specified in 

section b) of these terms and conditions shall be determined in accordance with the 

following methods:

a. Emission Limitation:

CO emissions shall not exceed 3.5 g/kW-hr, 17.35 lbs/hr, and 4.34 tons per 

rolling, 12-month period.
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Permit Number: P0110840

Facility ID: 0448020102

Effective Date:6/18/2013

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Applicable Compliance Method:

The g/kW-hr limitation is based on the Tier 2 emission standards under 40 CFR 

89.112(a), Subpart B, Table 1. The hourly emission limitation was developed by 

multiplying the maximum operating load (2,250 kW) by the CO emission factor 

supplied by the manufacturer (3.5 g/kW-hr) and dividing by (454 g/lb) to 

determine the hourly emissions.

If required, the permittee shall demonstrate compliance with the g/kW-hr 

limitation and hourly emission limitation using Methods 1 thru 4 and 10 of 40 CFR 

Part 60, Appendix A. Alternative U.S. EPA approved test methods may be used 

with prior approval from the Ohio EPA.

The annual emission limitation was developed by multiplying the hourly emission 

limitation (17.35 lbs/hr) by the maximum annual operating hours (500 hrs/yr) and 

dividing by 2,000 pounds per ton. Therefore, compliance with the annual 

limitation shall be demonstrated if compliance with the hourly limitation and 

operating hours restriction is shown.

b. Emission Limitation:

NOx emissions shall not exceed 5.61 g/kW-hr, 27.8 lbs/hr, and 6.95 tons per 

rolling, 12-month period.

Applicable Compliance Method:

The g/kW-hr limitation is based on the combined NOx + NMHC emission 

limitation specified by the Tier 2 standard in 40 CFR 89.112(a) Table 1 (6.4 

g/kW-hr) multiplied by the Tier 1 emission limitation for NOx in Table 1 (9.2 g/kWhr) divided by the sum of the Tier 1 emission limitations for NOx and HC in Table 

1 (9.2 g/kW-hr + 1.3 g/kW-hr). The hourly emission limitation was developed by 

multiplying the maximum operating load (2,250 kW) by the NOx g/kW-hr 

emission limitation (5.61 g/kW-hr) divided by (454 g/lb) to determine the hourly 

emissions.

If required, the permittee shall demonstrate compliance with the g/kW-hr 

limitation and hourly emission limitation using Methods 1 thru 4 and 7E of 40 

CFR Part 60, Appendix A. Alternative U.S. EPA approved test methods may be 

used with prior approval from the Ohio EPA.

The annual emission limitation was developed by multiplying the hourly emission 

limitation (27.8 lbs/hr) by the maximum annual operating hours (500 hrs/yr) and 

dividing by 2,000 pounds per ton. Therefore, compliance with the annual 

limitation shall be demonstrated if compliance with the hourly limitation and 

operating hours restriction is shown.

c. Emission Limitation:

PM10/PM2.5 emissions shall not exceed 0.20 g/kW-hr, 0.99 lb/hr, and 0.25 ton per 

rolling, 12-month period.
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Permit Number: P0110840

Facility ID: 0448020102

Effective Date:6/18/2013

Page 30 of 86

Applicable Compliance Method:

The g/kW-hr limitation is based on manufacturer’s emissions data. The hourly 

emission limitation was developed by multiplying the maximum operating load 

(2,250 kW) by the PM10/PM2.5 emission factor supplied by the manufacturer (0.20 

g/kW-hr) divided by (454 g/lb) to determine the hourly emissions.

If required, the permittee shall demonstrate compliance with the g/kW-hr 

limitation and hourly emission limitation using Methods 201 or 201A and 202 of 

40 CFR Part 51, Appendix M. Alternative U.S. EPA approved test methods may 

be used with prior approval from the Ohio EPA.

The annual emission limitation was developed by multiplying the hourly emission 

limitation (0.99 lb/hr) by the maximum annual operating hours (500 hrs/yr) and 

dividing by 2,000 pounds per ton. Therefore, compliance with the annual 

limitation shall be demonstrated if compliance with the hourly limitation and 

operating hours restriction is shown.

d. Emission Limitation:

SO2 emissions shall not exceed 0.03 lb/hr and 0.008 ton/yr.

Applicable Compliance Method:

The hourly emission limitation is based dividing the AP-42 emission factor for

SO2 from AP-42 Table 3.4-1 dated 10/96 when burning diesel fuel with a 

maximum sulfur content of 15 ppmw (0.0015 lb/mmBtu) by (106 Btu/mmBtu) 

multiplied by (7,000 Btu/hp-hr) and multiplied by the maximum power rating 

(3,016.6 hp).

If required, the permittee shall demonstrate compliance with the hourly emission 

limitation using Methods 1 thru 4 and 6C of 40 CFR Part 60, Appendix A. 

Alternative U.S. EPA approved test methods may be used with prior approval 

from the Ohio EPA.

The annual emission limitation was developed by multiplying the hourly emission 

limitation (0.03 lb/hr) by the maximum annual operating hours (500 hrs/yr) and 

dividing by 2,000 pounds per ton. Therefore, compliance with the annual 

limitation shall be demonstrated if compliance with the hourly limitation and 

operating hours restriction is shown.

e. Emission Limitation:

VOC emissions shall not exceed 0.79 g/kW-hr, 3.93 lbs/hr, and 0.98 ton per 

rolling, 12-month period.

Applicable Compliance Method:

The g/kW-hr limitation is based on the combined NOx + NMHC emission 

limitation specified by the Tier 2 standard in 40 CFR 89.112(a) Table 1 (6.4 

g/kW-hr) multiplied by the Tier 1 emission limitation for NMHC in Table 1 (1.3 
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Permit Number: P0110840

Facility ID: 0448020102

Effective Date:6/18/2013

Page 31 of 86

g/kW-hr) divided by the sum of the Tier 1 emission limitations for NOx and HC in 

Table 1 (9.2 g/kW-hr + 1.3 g/kW-hr). The hourly emission limitation was 

developed by multiplying the maximum operating load (2250 kW) by the VOC 

emission factor supplied by the manufacturer (0.79 g/kW-hr) to determine the 

hourly emissions.

If required, the permittee shall demonstrate compliance with the g/kW-hr 

limitation and hourly emission limitation using Methods 1 through 4 and 18, 25 or 

25A, as appropriate, of 40 CFR Part 60, Appendix A. Use of Method 18, 25 or 

25A is to be selected based on the results of pre-survey stack sampling and U.S. 

EPA guidance documents. Alternative U.S. EPA approved test methods may be 

used with prior approval from the Ohio EPA.

The annual emission limitation was developed by multiplying the hourly emission 

limitation (3.93 lbs/hr) by the maximum annual operating hours (500 hrs/yr) and 

dividing by 2,000 pounds per ton. Therefore, compliance with the annual 

limitation shall be demonstrated if compliance with the hourly limitation and 

operating hours restriction is shown.

f. Emission Limitation:

H2SO4 emissions shall not exceed 1.32E-04 g/kW-hr, 6.5 E-04 lb/hr and 1.6E-04 

ton per rolling, 12-month period.

Applicable Compliance Method:

The g/kW-hr emission is based on the sulfuric acid mist emission factor from 

page 276 of Toxic Air Pollution Emission Factors, EPA 450/2-90-011 (8.9 ng/J x 

%sulfur in fuel = 8.9(0.0015) = 0.01335 ng/J). The H2SO4 emission factor 

(0.01335 ng/J) was converted to g/kW-hr by multiplying by (1055.1 J/Btu), 

multiplying by (7000 Btu/hp-hr), multiplying by (g/109ng), and multiplying by 

(1.341 hp/kW) = 1.32E-04 g/kW-hr.

The pound per hour emissions limitation was developed by multiplying the g/kWhr allowable H2SO4 emission limitation (1.32E-04 g/kW-hr) by the maximum 

operating load (2,250 kW) and divided by 454 grams per pound to determine the 

hourly emissions (6.5E-04 lb/hr).

If required, the permittee shall demonstrate compliance with the g/kW-hr and 

lb/hr emission limitation using Methods 1 thru 4 and 8 of 40 CFR Part 60, 

Appendix A. Alternative U.S. EPA approved test methods may be used with 

prior approval from the Ohio EPA.

The ton per year emission limitation was developed by multiplying the hourly 

allowable H2SO4 emission limitation (6.5E-04 lb/hr) by the maximum annual 

hours of operation (500 hours), and then dividing by 2,000 pounds per ton. 

Therefore, if compliance is shown with the short-term allowable emission 

limitation, compliance shall also be shown with the annual emission limitation.
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Permit Number: P0110840

Facility ID: 0448020102

Effective Date:6/18/2013

Page 32 of 86

g. Emission Limitation:

Carbon dioxide equivalent (CO2e) emissions shall not exceed 877 tons per 

rolling, 12-month period.

Applicable Compliance Method:

This emissions limitation was established to reflect the potential to emit for this 

emissions unit by calculating the sum of the maximum capacity (3016.6 hp) by 

the emission factor for CO2, N2O, and CH4, multiplied by the global warming 

potential for CO2, N2O, and CH4 (1, 310, and 21, respectively from Table A-1 to 

Subpart A of 40 CFR 98). Multiply the sum by the maximum annual hours of 

operation (500 hrs/yr) and divide by 2,000 pounds per ton. The CO2 emission 

factor was obtained from AP-42 Table 3.4-1 dated 10/96 (1.16 lb/hp-hr). The 

N2O emission factor was obtained from 40 Table C-2 to Subpart C of 40 CFR 98 

(0.6 g/mmBtu). The CH4 emission factor was obtained from AP-42 Table 3.4-1 

dated 10/96 (7.05E-04 lb TOC/hp-hr x 0.09 lb CH4/lb TOC = 6.34E-05 lb CH4/hphr).

(3016.6 h) 1.16



h − h

(1)

+ 0.6





 7000



h − h

 



106 (



454

)(310)

+ 6.34 − 05



(h − h)

 (21)  500

h

h

  



2,000

= 878 /

Since the CO2e emissions are estimated to consist of more than 99% CO2, 

compliance with this emission limitation will be assumed provided that the lb/hphr CO2 emission rate does not exceed 1.16 lb/hp-hr. If required, the permittee 

shall conduct emissions testing using Methods 1, 2, 3A and 4 of 40 CFR Part 60, 

Appendix A to determine the lb/hp-hr CO2 emission rate.

h. Emission Limitation:

The permittee shall only combust diesel fuel in this emissions unit meeting the 

following per gallon standard: 15 ppm maximum sulfur content

Applicable Compliance Method:

The records required by d)(2) shall be used to demonstrate compliance.

i. Emission Limitation: 

The permittee shall only combust diesel fuel in this emissions unit meeting the 

following per gallon standard: a minimum cetane index of 40 or a maximum 

aromatic content of 35 volume percent.
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Permit Number: P0110840

Facility ID: 0448020102

Effective Date:6/18/2013

Page 33 of 86

Applicable Compliance Method:

The records required by d)(2) and d)(3) shall serve as demonstration of 

compliance.

j. Emission Limitation:

Visible particulate emissions from the stack serving this emissions unit shall not 

exceed 20 percent opacity as a 6-minute average.

Applicable Compliance Method:

If required, the permittee shall demonstrate compliance according to Method 9 of 

40 CFR Part 60, Appendix A.

k. Emission Limitation:

NMHC + NOx emissions shall not exceed 6.4 g/kW-hr;

CO emissions shall not exceed 3.5 g/kW-hr;

PM emissions shall not exceed 0.20 g/kW-hr;

Exhaust opacity shall not exceed:

20 percent during acceleration mode;

15 percent during lugging mode; and

50 percent during the peaks in either the acceleration or lugging modes.

Applicable Compliance Method:

According to 40 CFR 60.4211(c), the permittee shall demonstrate compliance 

with these emissions limitations by purchasing an engine certified to the emission 

standards in 40 CFR 60.4205(b) for the same model year and maximum engine 

power. The engine must be installed and configured according to the 

manufacturer’s emission-related specifications, except as permitted in 40 CFR 

60.4211(g). The permittee shall maintain documentation of certification to the 

emission standards in 40 CFR 60.4205.

g) Miscellaneous Requirements

(1) None.
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Permit Number: P0110840

Facility ID: 0448020102

Effective Date:6/18/2013

Page 34 of 86

3. P004, Emergency Fire Pump

Operations, Property and/or Equipment Description: 

300 hp (223.8 kW) emergency diesel-fired fire pump engine

a) The following emissions unit terms and conditions are federally enforceable with the exception 

of those listed below which are enforceable under state law only.

(1) None.

b) Applicable Emissions Limitations and/or Control Requirements

(1) The specific operation(s), property, and/or equipment that constitute each emissions unit 

along with the applicable rules and/or requirements and with the applicable emissions 

limitations and/or control measures are identified below. Emissions from each unit shall 

not exceed the listed limitations, and the listed control measures shall be specified in 

narrative form following the table.

Applicable Rules/Requirements Applicable Emissions Limitations/Control 

Measures

a. OAC rule 3745-31-05(A)(3), as 

effective 11/30/2001

Sulfur dioxide (SO2) emissions shall not 

exceed 0.003 lb/hr and 8.0 E-04 ton/yr.

see b)(2)a. and b)(2)b.

b. OAC rule 3745-31-05(A)(3)(a)(ii), as 

effective 12/01/2006

see b)(2)c.

c. OAC rule 3745-31-10 through 20 Carbon monoxide (CO) emissions shall 

not exceed 3.5 g/kW-hr, 1.7 pounds per 

hour (lbs/hr), and 0.43 ton per rolling, 12-

month period.

Nitrogen Oxides (NOx) emissions shall 

not exceed 3.5 g/kW-hr, 1.7 lb/hr, and 

0.43 ton per rolling, 12-month period.

Particulate matter emissions less than 10 

microns in diameter (PM10) and 

particulate matter less than 2.5 microns in 

diameter (PM2.5) shall not exceed 0.20 

g/kW-hr, 0.10 lb/hr, and 0.025 ton per 

rolling, 12-month period.

Volatile organic compound (VOC) 

emissions shall not exceed 0.50 g/kW-hr, 

0.25 lb/hr, and 0.06 ton per rolling, 12-

month period.
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Permit Number: P0110840

Facility ID: 0448020102

Effective Date:6/18/2013

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Applicable Rules/Requirements Applicable Emissions Limitations/Control 

Measures

H2SO4 emissions shall not exceed 1.32 

E-04 g/kW-hr, 6.5E-05 lb/hr and 1.6E-05 

ton per rolling, 12-month period

Carbon dioxide equivalent (CO2e) 

emissions shall not exceed 87 tons per 

rolling, 12-month period.

see b)(2)d. and b)(2)e.

d. OAC rule 3745-17-07(A) Visible particulate emissions from the 

stack serving this emissions unit shall not 

exceed 20 percent opacity as a 6-minute 

average.

e. OAC rule 3745-17-11(B)(5)(a) see b)(2)f.

f. OAC rule 3745-18-06(G) less stringent than 40 CFR Part 63, 

Subpart IIII

g. OAC rule 3745-110-03(J)(16), (19) exemption – see b)(2)g.

h. 40 CFR Part 60, Subpart A

(40 CFR 60.1-19)

Table 8 to Subpart IIII of 40 CFR Part 60 

– Applicability of General Provisions to 

Subpart IIII shows which parts of the 

General Provisions in 40 CFR 60.1-19 

apply.

i. 40 CFR Part 60, Subpart IIII

(40 CFR 60.4200–4219)

[In accordance with 40 CFR 

60.4200(a)(2), this emissions unit is 

a compression ignition stationary 

internal combustion fire pump engine 

for which construction commenced 

after July 11, 2005 subject to the 

emissions limitation/control 

measures specified in this section.]

Non-methane hydrocarbon (NMHC) + 

NOx emissions shall not exceed 4.0 

g/kW-hr.

CO emissions shall not exceed 3.5 g/kWhr.

PM emissions shall not exceed 0.20 

g/kW-hr.

see b)(2)h.

[60.4205(c) and 60.4207(b)]

j. 40 CFR Part 63, Subpart ZZZZ

(40 CFR 63.6580-63.6675)

[In accordance with 40 CFR 

63.6590(c)(1), this emissions unit is 

a new stationary reciprocating 

internal combustion engine (RICE) 

located at an area source of HAP 

emissions subject to the emissions 

limitation/control measures specified 

in this section.]

see b)(2)i

[63.6590(c), (c)(1)]
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Permit Number: P0110840

Facility ID: 0448020102

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(2) Additional Terms and Conditions

a. Compliance with the requirements of this rule for CO, NOx, PM10, PM2.5, and 

VOC emissions includes compliance with the requirements of OAC rule 3745-31-

10 through 20.

b. The permittee has satisfied the Best Available Technology (BAT) requirements 

pursuant to Ohio Administrative Code (OAC) paragraph 3745-31-05(A)(3), as 

effective November 30, 2001, in this permit. On December 1, 2006, paragraph 

(A)(3) of OAC rule 3745-31-05 was revised to conform to the Ohio Revised Code 

(ORC) changes effective August 3, 2006 (Senate Bill 265 changes), such that 

BAT is no longer required by State regulations for National Ambient Air Quality 

Standards (NAAQS) pollutant(s) less than ten tons per year. However, that rule 

revision has not yet been approved by U.S. EPA as a revision to Ohio’s State 

Implementation Plan (SIP). Therefore, until the SIP revision occurs and the U.S. 

EPA approves the revisions to OAC rule 3745-31-05, the requirement to satisfy 

BAT still exists as part of the federally-approved SIP for Ohio. Once U.S. EPA 

approves the December 1, 2006 version of OAC rule 3745-31-05, then these 

emission limitations/control measures no longer apply.

c. This rule paragraph applies once U.S. EPA approves the December 1, 2006 

version of OAC rule 3745-31-05 as part of the State Implementation Plan.

The Best Available Technology (BAT) requirements under OAC rule 3745-31-

05(A)(3) do not apply to the CO, NOx, PM10/PM2.5, SO2, and VOC emissions from 

this air contaminant source since the uncontrolled potential to emit for CO, NOx, 

PM10/PM2.5, SO2, and VOC is less than 10 tons per year taking into consideration 

the federally enforceable emissions limitations and operating hours restriction 

specified by OAC rule 3745-31-10 through 20.

d. All particulate emissions are assumed to be less than 2.5 microns in diameter. 

The PM10/PM2.5 emissions limitations include both filterable and condensable 

particulate emissions.

e. The maximum annual operating hours for this emissions unit shall not exceed 

500 hours, based upon a rolling, 12-month summation of the operating hours.

To ensure enforceability during the first 12 calendar months of operation or the 

first 12 calendar months following the issuance of this permit, the permittee shall 

not exceed the operating hours levels specified in the following table:

Maximum Allowable

Month(s) Cumulative Operating Hours

1 500

1-2 500

1-3 500

1-4 500

1-5 500

1-6 500

1-7 500
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1-8 500

1-9 500

1-10 500

1-11 500

1-12 500

After the first 12 calendar months of operation or the first 12 calendar months 

following the issuance of this permit, compliance with the annual operating hours 

limitation shall be based upon a rolling, 12-month summation of the operating 

hours.

f. The emission limitation specified by this rule is less stringent than the emission 

limitation established by OAC rule 3745-31-10 through 20. 

g. The requirements of this rule do not apply, since:

i. NOx emissions are restricted to less than 25 tons per year; and

ii. the emissions unit is subject to a BACT limitation for NOx.

h. The permittee shall only combust diesel fuel in this emissions unit meeting the 

following per gallon standards:

15 ppm maximum sulfur content; and

a minimum cetane index of 40 or a maximum aromatic content of 35 volume 

percent.

i. This emissions unit must meet the requirements of 40 CFR Part 60 Subpart IIII. 

No further requirements apply under this subpart.

c) Operational Restrictions

(1) See 40 CFR Part 60, Subpart IIII (40 CFR 60.4200-4219).

d) Monitoring and/or Recordkeeping Requirements

(1) The permittee shall maintain monthly records of the following information:

a. the operating hours for each month; and

b. beginning after the first 12 calendar months of operation or the first 12 calendar 

months following the issuance of this permit, the rolling, 12-month summation of 

the operating hours.

Also, during the first 12 calendar months of operation or the first 12 calendar months 

following the issuance of this permit, the permittee shall record the cumulative operating 

hours for each calendar month.

(2) For each shipment of diesel fuel received for burning in this emissions unit, the permittee 

shall maintain records of the oil supplier's (or permittee’s) analyses for sulfur content in 
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Permit Number: P0110840

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Effective Date:6/18/2013

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parts per million (40 CFR 80.510). The permittee shall perform or require the supplier to 

perform the analyses for sulfur content in accordance with 40 CFR 80.585.

(3) The permittee shall also maintain documentation of supplier verification that the diesel 

fuel as purchased has a minimum cetane index of 40 or a maximum aromatic content of 

35 volume percent.

(4) See 40 CFR Part 60, Subpart IIII (40 CFR 60.4200-4219).

e) Reporting Requirements

(1) The permittee shall submit quarterly deviation (excursion) reports that identify the 

following:

a. each shipment of diesel fuel received for burning in this emissions unit which did 

not comply with the per gallon standards specified in b)(2); and

b. all exceedances of the rolling, 12-month limitation on the hours of operation for

this emissions unit; and for the first 12 calendar months of operation or the first 

12 calendar months following the issuance of this permit, all exceedances of the 

maximum allowable cumulative hours of operation.

The quarterly deviation (excursion) reports shall be submitted in accordance with the 

reporting requirements of the Standard Terms and Conditions of this permit.

(2) See 40 CFR Part 60, Subpart IIII (40 CFR 60.4200-4219).

(3) Unless other arrangements have been approved by the Director, all notifications and 

reports shall be submitted through the Ohio EPA's eBusiness Center: Air Services 

online web portal.

f) Testing Requirements

(1) Compliance with the Emissions Limitations and/or Control Requirements specified in 

section b) of these terms and conditions shall be determined in accordance with the 

following methods:

a. Emission Limitation:

CO emissions shall not exceed 3.5 g/kW-hr, 1.7 lbs/hr, and 0.43 ton per rolling, 

12-month period.

Applicable Compliance Method:

The g/kW-hr limitation is based on the standard specified in Table 4 to 40 CFR 

Part 60, Subpart IIII. The hourly emission limitation was developed by multiplying 

the maximum operating load (223.8 kW) by the g/kW-hr CO emission limitation 

(3.5 g/kW-hr) divided by (454 g/lb) to determine the hourly emissions.

If required, the permittee shall demonstrate compliance with the g/kW-hr 

limitation and hourly emission limitation using Methods 1 thru 4 and 10 of 40 CFR 
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Part 60, Appendix A. Alternative U.S. EPA approved test methods may be used 

with prior approval from the Ohio EPA.

The annual emission limitation was developed by multiplying the hourly emission 

limitation (1.7 lbs/hr) by the maximum annual operating hours (500 hrs/yr) and 

dividing by 2,000 pounds per ton. Therefore, compliance with the annual 

limitation shall be demonstrated if compliance with the hourly limitation and 

operating hours restriction is shown.

b. Emission Limitation:

NOx emissions shall not exceed 3.5 g/kW-hr, 1.7 lbs/hr, and 0.43 ton per rolling, 

12-month period.

Applicable Compliance Method:

The g/kW-hr limitation is based on the combined NOx + NMHC emission 

limitation specified by the Table 2 to 40 CFR Part 60, Subpart IIII (4.0 g/kW-hr) 

multiplied by the Tier 1 emission limitation for NOx in Table 1 to 40 CFR 

89.112(a) (9.2 g/kW-hr) divided by the sum of the Tier 1 emission limitations for

NOx and HC in Table 1 to 40 CFR 89.112(a) (9.2 g/kW-hr + 1.3 g/kW-hr). The 

hourly emission limitation was developed by multiplying the maximum operating 

load (223.8 kW) by the g/kW-hr NOx emission limitation (3.5 g/kW-hr) divided by 

(454 g/lb) to determine the hourly emissions.

If required, the permittee shall demonstrate compliance with the g/kW-hr 

limitation and hourly emission limitation using Methods 1 thru 4 and 7E of 40 

CFR Part 60, Appendix A. Alternative U.S. EPA approved test methods may be 

used with prior approval from the Ohio EPA.

The annual emission limitation was developed by multiplying the hourly emission 

limitation (1.7 lbs/hr) by the maximum annual operating hours (500 hrs/yr) and 

dividing by 2,000 pounds per ton. Therefore, compliance with the annual 

limitation shall be demonstrated if compliance with the hourly limitation and 

operating hours restriction is shown.

c. Emission Limitation:

PM10/PM2.5 emissions shall not exceed 0.20 g/kW-hr, 0.10 lb/hr, and 0.025 ton 

per rolling, 12-month period.

Applicable Compliance Method:

The g/kW-hr limitation is based on manufacturer’s emissions data. The hourly 

emission limitation was developed by multiplying the maximum operating load 

(223.8 kW) by the PM10/PM2.5 emission factor supplied by the manufacturer (0.20 

g/kW-hr) divided by (454 g/lb) to determine the hourly emissions.

If required, the permittee shall demonstrate compliance with the g/kW-hr 

limitation and hourly emission limitation using Methods 201 or 201A and 202 of 
Final Permit-to-Install

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Permit Number: P0110840

Facility ID: 0448020102

Effective Date:6/18/2013

Page 40 of 86

40 CFR Part 51, Appendix M. Alternative U.S. EPA approved test methods may 

be used with prior approval from the Ohio EPA.

The annual emission limitation was developed by multiplying the hourly emission 

limitation (0.10 lb/hr) by the maximum annual operating hours (500 hrs/yr) and 

dividing by 2,000 pounds per ton. Therefore, compliance with the annual 

limitation shall be demonstrated if compliance with the hourly limitation is shown.

d. Emission Limitation:

SO2 emissions shall not exceed 0.003 lb/hr and 8.0E-04 ton/yr.

Applicable Compliance Method:

The hourly emission limitation is based dividing the AP-42 emission factor for

SO2 from AP-42 Table 3.4-1 dated 10/96 when burning diesel fuel with a 

maximum sulfur content of 15 ppmw (0.0015 lb/mmBtu) by (106 Btu/mmBtu) 

multiplied by (7,000 Btu/hp-hr) and multiplied by the maximum power rating (300 

hp).

If required, the permittee shall demonstrate compliance with the hourly emission 

limitation using Methods 1 thru 4 and 6C of 40 CFR Part 60, Appendix A. 

Alternative U.S. EPA approved test methods may be used with prior approval 

from the Ohio EPA.

The annual emission limitation was developed by multiplying the hourly emission 

limitation (0.003 lb/hr) by the maximum annual operating hours (500 hrs/yr) and 

dividing by 2,000 pounds per ton. Therefore, compliance with the annual 

limitation shall be demonstrated if compliance with the hourly limitation is shown.

e. Emission Limitation:

VOC emissions shall not exceed 0.50 g/kW-hr, 0.25 lb/hr, and 0.06 ton/yr as a 

rolling, 12-month summation of the monthly emissions.

Applicable Compliance Method:

The g/kW-hr limitation is based on the combined NOx + NMHC emission 

limitation specified by the Table 2 to 40 CFR Part 60, Subpart IIII (4.0 g/kW-hr) 

multiplied by the Tier 1 emission limitation for NMHC in Table 1 to 40 CFR 

89112(a) (1.3 g/kW-hr) divided by the sum of the Tier 1 emission limitations for 

NOx and HC in Table 1 to 40 CFR 89.112(a) (9.2 g/kW-hr + 1.3 g/kW-hr). The 

hourly emission limitation was developed by multiplying the maximum operating 

load (223.8 kW) by the g/kW-hr VOC emission limitation (0.50 g/kW-hr) divided 

by (454 g/lb) to determine the hourly emissions.

If required, the permittee shall demonstrate compliance with the g/kW-hr 

limitation and hourly emission limitation using Methods 1 through 4 and 18, 25 or 

25A, as appropriate, of 40 CFR Part 60, Appendix A. Use of Method 18, 25 or

25A is to be selected based on the results of pre-survey stack sampling and U.S. 
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Facility ID: 0448020102

Effective Date:6/18/2013

Page 41 of 86

EPA guidance documents. Alternative U.S. EPA approved test methods may be 

used with prior approval from the Ohio EPA.

The annual emission limitation was developed by multiplying the hourly emission 

limitation (0.24 lb/hr) by the maximum annual operating hours (500 hrs/yr) and 

dividing by 2,000 pounds per ton. Therefore, compliance with the annual 

limitation shall be demonstrated if compliance with the hourly limitation is shown.

f. Emission Limitation:

H2SO4 emissions shall not exceed 1.32E-04 g/kW-hr, 6.5 E-05 lb/hr and 1.6E-05 

ton per rolling, 12-month period.

Applicable Compliance Method:

The g/kW-hr emission is based on the sulfuric acid mist emission factor from 

page 276 of Toxic Air Pollution Emission Factors, EPA 450/2-90-011 (8.9 ng/J x 

%sulfur in fuel = 8.9(0.0015) = 0.01335 ng/J). The H2SO4 emission factor 

(0.01335 ng/J) was converted to g/kW-hr by multiplying by (1055.1 J/Btu), 

multiplying by (7000 Btu/hp-hr), multiplying by (g/109ng), and multiplying by 

(1.341 hp/kW) = 1.32E-04 g/kW-hr.

The pound per hour emissions limitation was developed by multiplying the g/kWhr allowable H2SO4 emission limitation (1.32E-04 g/kW-hr) by the maximum 

operating load (223.8 kW) and divided by 454 grams per pound to determine the 

hourly emissions (6.5E-05 lb/hr).

If required, the permittee shall demonstrate compliance with the g/kW-hr and 

lb/hr emission limitation using Methods 1 thru 4 and 8 of 40 CFR Part 60, 

Appendix A. Alternative U.S. EPA approved test methods may be used with 

prior approval from the Ohio EPA.

The ton per year emission limitation was developed by multiplying the hourly 

allowable H2SO4 emission limitation (6.5E-05 lb/hr) by the maximum annual 

hours of operation (500 hours), and then dividing by 2,000 pounds per ton. 

Therefore, if compliance is shown with the short-term allowable emission 

limitation, compliance shall also be shown with the annual emission limitation.

g. Emission Limitation:

Carbon dioxide equivalent (CO2e) emissions shall not exceed 87 tons per rolling, 

12-month period.

Applicable Compliance Method:

This emissions limitation was established to reflect the potential to emit for this 

emissions unit by calculating the sum of the maximum capacity (300 hp) by the 

emission factor for CO2, N2O, and CH4, multiplied by the global warming potential 

for CO2, N2O, and CH4 (1, 310, and 21, respectively from Table A-1 to Subpart of 

40 CFR 98). Multiply the sum by the maximum annual hours of operation (500 
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Page 42 of 86

hrs/yr) and divide by 2,000 pounds per ton. The CO2 emission factor was 

obtained from AP-42 Table 3.3-1 dated 10/96 (1.15 lb/hp-hr). The N2O emission 

factor was obtained from Table C-2 to Subpart C of 40 CFR 98 (0.6 g/mmBtu). 

The CH4 emission factor was obtained from AP-42 Table 3.3-1 dated 10/96 

(2.47E-03 lb TOC/hp-hr (0.09 lb CH4/lb TOC)= 2.223E-04 lb CH4/hp-hr, this table 

did not include an estimate of how much methane comprises the TOC emission 

factor, so the value of 9% from AP-42 Table 3.4-1 dated 10/96 was used).

(300 h) 1.15



h − h

(1)

+ 0.6





 7000



h − h

 



106 (



454

)(310)

+ 2.223 − 04



(h − h)

 (21)  500

h

h

  



2,000

= 87 /

Since the CO2e emissions are estimated to consist of more than 99% CO2, 

compliance with this emission limitation will be assumed provided that the lb/hphr CO2 emission rate does not exceed 1.15 lb/hp-hr. If required, the permittee 

shall conduct emissions testing using Methods 1, 2, 3A and 4 of 40 CFR Part 60, 

Appendix A to determine the lb/hp-hr CO2 emission rate.

h. Emission Limitation:

The permittee shall only combust diesel fuel in this emissions unit meeting the 

following per gallon standard: 15 ppm maximum sulfur content

Applicable Compliance Method:

The records required by d)(2) shall be used to demonstrate compliance.

i. Emission Limitation: 

The permittee shall only combust diesel fuel in this emissions unit meeting the 

following per gallon standard: a minimum cetane index of 40 or a maximum 

aromatic content of 35 volume percent.

Applicable Compliance Method:

The records required by d)(2) and d)(3) shall serve as demonstration of 

compliance.

j. Emission Limitation:

Visible particulate emissions from the stack serving this emissions unit shall not 

exceed 20 percent opacity as a 6-minute average.
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Applicable Compliance Method:

If required, the permittee shall demonstrate compliance with this emissions 

limitation according to Method 9 of 40 CFR Part 60, Appendix A.

k. Emission Limitation:

NMHC + NOx emissions shall not exceed 4.0 g/kW-hr (3.0 g/hp-hr);

CO emissions shall not exceed 3.5 g/kW-hr (2.6 g/hp-hr); and

PM emissions shall not exceed 0.20 g/kW-hr (0.15 g/hp-hr)

Applicable Compliance Method:

According to 40 CFR 60.4211(c), the permittee shall demonstrate compliance 

with these emissions limitations by purchasing an engine certified to the emission 

standards in 40 CFR 60.4205(c) for the same model year and maximum engine 

power. The engine must be installed and configured according to the 

manufacturer’s emission-related specifications, except as permitted in 40 CFR 

60.4211(g).

g) Miscellaneous Requirements

(1) None.
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4. P005, Wet Cooling Tower

Operations, Property and/or Equipment Description: 

16 cell mechanical draft wet cooling tower with high efficiency drift eliminator

a) The following emissions unit terms and conditions are federally enforceable with the exception 

of those listed below which are enforceable under state law only.

(1) None.

b) Applicable Emissions Limitations and/or Control Requirements

(1) The specific operation(s), property, and/or equipment that constitute each emissions unit 

along with the applicable rules and/or requirements and with the applicable emissions 

limitations and/or control measures are identified below. Emissions from each unit shall 

not exceed the listed limitations, and the listed control measures shall be specified in 

narrative form following the table.

Applicable Rules/Requirements Applicable Emissions Limitations/Control 

Measures

a. OAC rule 3745-31-05(A)(3), as 

effective 11/30/2001

see b)(2)a. and b.

b. OAC rule 3745-31-05(A)(3)(a)(ii), as 

effective 12/01/2006

see b)(2)c. 

c. OAC rules 3745-10 through 20

(Prevention of Significant 

Deterioration of Air Quality)

Particulate matter emissions less than 10 

microns in diameter (PM10) shall not 

exceed 1.03 pounds per hour and 4.5 

tons per rolling, 12-month period.

Particulate matter emissions less than 2.5 

microns in diameter (PM2.5) shall not 

exceed 3.4E-03 pound per hour and 

0.015 ton per rolling, 12-month period.

The permittee shall install a drift 

eliminator with a maximum drift rate of 

0.0005% on this emissions unit.

Visible particulate emissions shall not 

exceed 10% opacity as a 6-minute 

average. The presence of condensed 

water vapor shall not be deemed a 

violation for failure of stack emissions 

meeting this visible emission limitation.

see c)(1)

d. OAC rule 3745-17-07(A)(1) see b)(2)d.

e. OAC rule 3745-17-11(B) see b)(2)d.
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(2) Additional Terms and Conditions

a. The requirements of this rule include compliance with the requirements of OAC 

rule 3745-10 through 20.

b. The permittee has satisfied the Best Available Technology (BAT) requirements 

pursuant to Ohio Administrative Code (OAC) paragraph 3745-31-05(A)(3), as 

effective November 30, 2001, in this permit. On December 1, 2006, paragraph 

(A)(3) of OAC rule 3745-31-05 was revised to conform to the Ohio Revised Code 

(ORC) changes effective August 3, 2006 (Senate Bill 265 changes), such that 

BAT is no longer required by State regulations for National Ambient Air Quality 

Standards (NAAQS) pollutant(s) less than ten tons per year. However, that rule 

revision has not yet been approved by U.S. EPA as a revision to Ohio’s State 

Implementation Plan (SIP). Therefore, until the SIP revision occurs and the U.S. 

EPA approves the revisions to OAC rule 3745-31-05, the requirement to satisfy 

BAT still exists as part of the federally-approved SIP for Ohio. Once U.S. EPA 

approves the December 1, 2006 version of OAC rule 3745-31-05, then these 

emission limitations/control measures no longer apply.

c. This rule paragraph applies once U.S. EPA approves the December 1, 2006 

version of OAC rule 3745-31-05 as part of the State Implementation Plan.

The Best Available Technology (BAT) requirements under OAC rule 3745-31-

05(A)(3) do not apply to the PM10 and PM2.5 emissions from this air contaminant 

source since the calculated annual emission rate for PM10 and PM2.5 is less than 

10 tons per year taking into account the federally enforceable rule limit of 

0.0005% drift and a maximum TDS concentration of 2,030.5 mg/l under OAC rule 

3745-31-10 through 20.

d. The emission limitation specified by this rule is less stringent than the emission 

limitation established by OAC rule 3745-31-10 through 20.

c) Operational Restrictions

(1) The permittee shall maintain the total dissolved solids (TDS) concentration of the cooling 

water less than or equal to 2,030.5 milligrams per liter.

d) Monitoring and/or Recordkeeping Requirements

(1) The permittee shall properly install, operate, and maintain a conductivity meter or other 

equipment to continuously monitor and record the TDS concentration of the cooling 

tower water. The monitoring devices shall be installed, calibrated, operated, and 

maintained in accordance with the manufacturer’s recommendations, instructions, and 

operating manuals.

(2) Since the TDS data measured by TDS monitors is based on a correlation between 

conductivity and TDS, an exceedance measured by the TDS monitor is not a violation of 

the TDS operational restriction, but rather serves as an indicator to initiate corrective 

action by the permittee to reduce the TDS concentration..
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e) Reporting Requirements

(1) The permittee shall submit quarterly deviation (excursion) reports that identify all TDS 

readings in excess of 2030.5 mg/l. The reports shall identify corrective action taken to 

reduce the TDS concentration.

The quarterly deviation (excursion) reports shall be submitted in accordance with the 

reporting requirements of the Standard Terms and Conditions of this permit

(2) Prior to startup, the permittee shall submit written documentation provided by the 

vendor/manufacturer, of the maximum drift rate of 0.0005% for the drift eliminator and 

the premise, basis, and justification for the drift rate.

(3) Unless other arrangements have been approved by the Director, all notifications and 

reports shall be submitted through the Ohio EPA's eBusiness Center: Air Services 

online web portal.

f) Testing Requirements

(1) Compliance with the Emissions Limitations and/or Control Requirements specified in 

section b) of these terms and conditions shall be determined in accordance with the 

following methods:

a. Emission Limitation:

PM10 emissions shall not exceed 1.03 lbs/hr and 4.5 tons per rolling, 12-month 

period.

Applicable Compliance Method:

The lb/hr PM10 emission limitation is based on multiplying the maximum recirculating water flow rate (322,000 gal/min) by the maximum TDS concentration 

(2030.5/1E06) multiplied by the decimal fraction drift rate (0.000005) multiplied 

by the density of water (8.34 lbs/gal) multiplied by (60 min/hr) and multiplied by 

the decimal fraction of PM10 contained in the TDS (0.63). The permittee 

calculated the PM10 fraction using AWMA Abstract No. 216, Session No. AM-1b, 

Orlando, 2001.

The annual emission limitation is based on multiplying the hourly emission 

limitation (1.03 lbs/hr) by the maximum annual hours of operation (8,760 hrs/yr) 

and dividing by (2,000 lbs/ton) 

Compliance with the hourly and annual emissions limitation will be assumed 

provided that the TDS concentration recorded in d) remains below 2030.5 mg/l.

b. Emission Limitation:

PM2.5 emissions shall not exceed 3.4E-03 lb/hr and 0.015 ton/yr

The lb/hr PM2.5 emission limitation is based on multiplying the maximum recirculating water flow rate (322,000 gal/min) by the maximum TDS concentration 
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(2030.5/1E06) multiplied by the decimal fraction drift rate (0.000005) multiplied 

by the density of water (8.34 lbs/gal) multiplied by (60 min/hr) and multiplied by 

the decimal fraction of PM2.5 contained in the TDS (0.0021). The permittee 

calculated the PM2.5 fraction using AWMA Abstract No. 216, Session No. AM-1b, 

Orlando, 2001.

The annual emission limitation is based on multiplying the hourly emission 

limitation (3.4E-03 lb/hr) by the maximum annual hours of operation (8,760 

hrs/yr) and dividing by (2,000 lbs/ton) 

Compliance with the hourly and annual emissions limitation will be assumed 

provided that the TDS concentration recorded in d) remains below 2030.5 mg/l.

c. Emission Limitation:

The maximum drift rate shall not exceed 0.0005%.

Applicable Compliance Method:

Manufacturer's emissions data shall be used to demonstrate compliance with this 

limitation.

Within 90 days of startup, the permittee shall submit to the Toledo Division of 

Environmental Services written documentation provided by the 

vendor/manufacturer, of the maximum drift rate of 0.0005% for the drift eliminator 

and the premise, basis, and justification for the drift rate.

d. Emission Limitation:

The permittee shall maintain the TDS concentration of the cooling water less

than or equal to 2,030.5 milligrams per liter.

Applicable Compliance Method:

The monitoring and recordkeeping requirements under d)(1) and d)(2) shall serve 

as demonstration of compliance.

If required, compliance shall be demonstrated using test procedures that conform 

to regulation 40 CFR 136, "Test Procedures For The Analysis of Pollutants". 

Alternative U.S. EPA approved test methods may be used with prior written 

approval from the Ohio EPA.

g) Miscellaneous Requirements

(1) None.
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5. Emissions Unit Group -P001 and P002: CTG #1 and CTG #2

EU ID Operations, Property and/or Equipment Description

P001 Mitsubishi M501GAC or Siemens SCC6-8000H combined cycle combustion turbine (2,932 

mmBtu/hr heat input turbine and 300 mmBtu/hr heat input duct burner) with dry low NOx 

combustors, selective catalytic reduction (SCR), and catalytic oxidizer.

P002 Mitsubishi M501GAC or Siemens SCC6-8000H combined cycle combustion turbine (2,932 

mmBtu/hr heat input turbine and 300 mmBtu/hr heat input duct burner) with dry low NOx 

combustors, selective catalytic reduction (SCR), and catalytic oxidizer.

a) The following emissions unit terms and conditions are federally enforceable with the exception 

of those listed below which are enforceable under state law only:

(1) d)(12) through d)(15) and e)(6).

b) Applicable Emissions Limitations and/or Control Requirements

(1) The specific operation(s), property, and/or equipment that constitute each emissions unit 

along with the applicable rules and/or requirements and with the applicable emissions 

limitations and/or control measures are identified below. Emissions from each unit shall 

not exceed the listed limitations, and the listed control measures shall be specified in 

narrative form following the table.

Applicable Rules/Requirements Applicable Emissions Limitations/Control 

Measures

a. ORC 3704.03(T) Sulfur dioxide (SO2) emissions shall not 

exceed 1.4E-03 lb/mmBtu of heat input.

see b)(2)b.

b. OAC rule 3745-31-05(D) The combined SO2 emissions from P001 

and P002 shall not exceed 34.2 tons per 

rolling 12-month period if Mitsubishi 

turbines are installed and 36.8 tons per 

rolling, 12-month period if Siemens 

turbines are installed.

see b)(2)e. and f.

c. OAC rule 3745-31-10 through 20 Visible particulate emissions from the 

stack serving this emissions unit shall not 

exceed 10 percent opacity as a 6-minute 

average.

Carbon dioxide equivalent (CO2e) 

emissions from the Mitsubishi turbine 

shall not exceed 840 lb/MW-hr gross 

energy output and 318,404 lbs/hr.
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Applicable Rules/Requirements Applicable Emissions Limitations/Control 

Measures

Carbon dioxide equivalent (CO2e) 

emissions from the Siemens turbine shall 

not exceed 833 lb/MW-hr gross energy 

output and 327,819 lbs/hr.

see b)(2)c., b)(2)d., b)(2)g. through 

b)(2)n., and b)(2)v. through x.

d. OAC rule 3745-17-07(A) see b)(2)o.

e OAC rule 3745-17-11(B)(4) see b)(2)o.

f. OAC rule 3745-18-06(A) see b)(2)q.

g. OAC rule 3745-110-03(J)(19) Exemption

h. OAC rule 3745-114 see d)(12) through d)(15)

i. 40 CFR Part 60, Subpart A see b)(2)r.

j. 40 CFR Part 60, Subpart KKKK

(40 CFR 60.4300 – 60.4420)

[In accordance with 40 CFR 

60.4305(a), this emissions unit is a 

stationary combustion turbine with a 

heat input at peak load greater than 

10 mmBtu/hr with a heat recovery 

steam generator/duct burners 

subject to the emissions 

limitations/control measures 

specified in this section.]

see b)(2)p. and b)(2)s.

k. 40 CFR Part 63, Subpart YYYY see b)(2)t.

l. 40 CFR Part 63, Subpart JJJJJJ see b)(2)u.

(2) Additional Terms and Conditions

a. All requirements specified for in this Section of the permit for Emissions Unit 

Group P001 and P002 apply to each combined cycle combustion turbine (P001 

and P002) unless a combined requirement is otherwise specified.

b. Compliance with the requirements of this rule for CO, NOx, PM10, PM2.5, and VOC 

includes compliance with the requirements of OAC rule 3745-31-10 through 20.

c. The emissions from this emissions unit shall be vented to the SCR and catalytic 

oxidation units at all times during which the emissions unit is in operation.

d. All particulate emissions are assumed to be less than 2.5 microns in diameter. 

The PM10/PM2.5 emissions limitations include both filterable and condensable 

particulate emissions.

e. The sulfur content of natural gas burned in this emissions unit shall not exceed 

0.5 grains per 100 standard cubic feet. 
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f. The combined natural gas usage by emissions units P001 and P002 shall not 

exceed 47,917 mmscf per rolling, 12-month period if Mitsubishi turbines are 

installed and 51,560 mmscf per rolling, 12-month period if Siemens turbines are 

installed. To ensure enforceability during the first 12 calendar months of 

operation or the first 12 calendar months following the issuance of this permit, the 

permittee shall not exceed the natural gas usage levels specified in the following 

table:

Maximum Allowable Cumulative

Natural Gas Usage by 

P001 and P002 combined

(Million Standard Cubic Feet)

Month(s) mmscf, if Mitsubishi turbines 

are installed

mmscf, if Siemens turbines are 

installed

1 7,986 8,593

1-2 15,972 17,187

1-3 23,959 25,780

1-4 31,945 34,373

1-5 39,931 42,967

1-6 47,917 51,560

1-7 47,917 51,560

1-8 47,917 51,560

1-9 47,917 51,560

1-10 47,917 51,560

1-11 47,917 51,560

1-12 47,917 51,560

After the first 12 calendar months of operation or the first 12 calendar months 

following the issuance of this permit, compliance with the annual natural gas 

usage limitation shall be based upon a rolling, 12-month summation of the 

monthly natural gas usage.

g. The permittee shall comply with the following emissions limitations if a Mitsubishi 

turbine is installed:
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Allowable Emissions if Mitsubishi Turbine is Installed

Pollutant Operating 

Modea

Emission 

Rate b,e

Emission 

rate, 

lb/hrb

Emission rate, 

tons per rolling, 

12-month period

CO CT with DB 2.0c12.7 -

CT only 2.0c13.7 -

All operating 

modes, including 

startup periods - - 183.9

NOx CT with DB 2.0c20.8 -

CT only 2.0c22.6 -

All operating 

modes, including 

startup periods 94.8

PM10/PM2.5 CT with DB 3.73E-03d10.1 -

CT only 3.84E-03d11.3 -

All operating 

modes, including 

startup periods - - 44.2

VOC CT With DB 2.0c7.3 -

CT only 2.0c7.9 -

All operating 

modes, including 

startup periods - - 56.0

H2SO4 CT only 4.1E-04d1.2 -

CT with DB 4.4E-04d1.2 -

All operating 

modes, including 

startup periods - - 5.26

CO2e All operating 

modes, including 

startup periods - - 1,394,611
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Allowable Emissions if Mitsubishi Turbine is Installed

Pollutant Operating 

Modea

Emission 

Rate b,e

Emission 

rate, 

lb/hrb

Emission rate, 

tons per rolling, 

12-month period

a. CT = combustion turbine

 DB = duct burner

b. Emission limitation does not apply during periods of startup and shutdown.

c. Parts per million by volume dry (ppmvd) at 15% oxygen

d. Pound per million Btu of heat input

e. Emissions limitations are based on an hourly average.

h. To ensure enforceability of the rolling, 12-month emissions limitations during the 

first 12 calendar months of operation or the first 12 calendar months following the 

issuance of this permit, the permittee shall not exceed the emission levels 

specified in the following table:

Maximum Allowable Cumulative Emissions

if a Mitsubishi turbine is installed

(Tons)

Month(s) CO NOx PM10/PM2.5 VOC H2SO4

1 30.7 15.8 7.4 9.3 0.88

1-2 61.3 31.6 14 18.7 1.75

1-3 92.0 47.4 22.1 28.0 2.63

1-4 122.6 63.2 29.5 37.3 3.51

1-5 153.3 79.0 36.8 46.7 4.38

1-6 183.9 94.8 44.2 56.0 5.26

1-7 183.9 94.8 44.2 56.0 5.26

1-8 183.9 94.8 44.2 56.0 5.26

1-9 183.9 94.8 44.2 56.0 5.26

1-10 183.9 94.8 44.2 56.0 5.26

1-11 183.9 94.8 44.2 56.0 5.26

1-12 183.9 94.8 44.2 56.0 5.26
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After the first 12 calendar months of operation or the first 12 calendar months 

following the issuance of this permit, compliance with the annual emissions 

limitations shall be based upon a rolling, 12-month summation of the monthly

emissions.

i. The permittee shall comply with the following requirements during periods of 

startup and shutdown if a Mitsubishi turbine is installed.

Emissions Limitations During Startup (lbs/hr)a

Cold 

Startup

Hot 

Startup

Warm 

Startup

Shutdown

CO 1106.72 578.5 973.42 263

NOx 43.56 46.93 42.27 35

VOC 339.4 109.34 314.07 111

a Pound per hour emissions rates as presented are averaged 

over the duration of the event where the duration of a cold start 

is 150 minutes, the duration of a warm start is 110 minutes, the 

duration of a hot start is 67 minutes, and the duration of a 

shutdown is less than 1 hour.

“Cold Startup” is defined as a combustion turbine startup that occurs more than 

60 hours after a combustion turbine shutdown. The period of startup is defined 

as the lesser of the first 150 minutes of continuous fuel flow to the combustion 

turbine after fuel flow is initiated or the period of time from combustion turbine 

fuel flow initiation until the combustion turbine achieves ten consecutive CEM 

data points in compliance with the ppmvd emissions limitations for CO and NOx.

 “Hot Startup” is defined as a combustion turbine startup that occurs within 8 

hours of a combustion turbine shutdown. The period of hot startup is defined as 

the lesser of the first 67 minutes of continuous fuel flow to the combustion turbine 

after fuel flow is initiated or the period of time from combustion turbine fuel flow 

initiation until the combustion turbine achieves ten consecutive CEM data points 

in compliance with the ppmvd emissions limitations for CO and NOx.

“Warm Startup” is defined as a combustion turbine startup that occurs between 8 

hours of and 60 hours of a combustion turbine shutdown. The period of startup 

is defined as the lesser of the first 110 minutes of continuous fuel flow to the 

combustion turbine after fuel flow is initiated or the period of time from 

combustion turbine fuel flow initiation until the combustion turbine achieves ten 

consecutive CEM data points in compliance with the ppmvd emissions limitations 

for CO and NOx.
Final Permit-to-Install

Oregon Clean Energy Center

Permit Number: P0110840

Facility ID: 0448020102

Effective Date:6/18/2013

Page 54 of 86

j. The design net plant base heat rate with the Mitsubishi turbine shall not exceed 

7,280 Btu/kW-hr HHV (ISO conditions without duct firing).

k. The permittee shall comply with the following emissions limitations if a Siemens 

turbine is installed:

Allowable Emissions if Siemens Turbine is Installed

Pollutant Operating 

Modea

Emission 

Rate b,e

Emission 

rate, 

lb/hrb

Emission rate, 

tons per rolling, 

12-month period

CO CT with DB 2.0c13.0 -

CT only 2.0c13.0 -

All operating 

modes, including 

startup periods - - 72.2

NOx CT with DB 2.0c21.0 -

CT only 2.0c22.0 -

All operating 

modes, including 

startup periods 92.0

PM10/PM2.5 CT with DB 5.5E-03d14.0 -

CT only 4.7E-03d13.3 -

All operating 

modes, including 

startup periods - - 61.3

VOC CT With DB 1.9c5.9 -

CT only 1.0c3.9 -

All operating 

modes, including 

startup periods - - 28.6

H2SO4 CT with DB 7.0E-04d1.5 -

CT only 6.0E-04d1.6 -

All operating 

modes, including 
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Oregon Clean Energy Center

Permit Number: P0110840

Facility ID: 0448020102

Effective Date:6/18/2013

Page 55 of 86

Allowable Emissions if Siemens Turbine is Installed

Pollutant Operating 

Modea

Emission 

Rate b,e

Emission 

rate, 

lb/hrb

Emission rate, 

tons per rolling, 

12-month period

startup periods - - 6.57

CO2e All operating 

modes, including 

startup periods - - 1,435,847

a. CT = combustion turbine

 DB = duct burner

b. Limitation does not apply during periods of startup and shutdown.

c. Parts per million by volume dry (ppmvd) at 15% oxygen

d. Pound per million Btu of heat input

e. Emissions limitations are based on an hourly average.

l. To ensure enforceability of the rolling, 12-month emissions limitations during the 

first 12 calendar months of operation or the first 12 calendar months following the 

issuance of this permit, the permittee shall not exceed the emission levels 

specified in the following table:

Maximum Allowable Cumulative Emissions

if a Siemens turbine is installed

(Tons)

Month(s) CO NOx PM10/PM2.5 VOC H2SO4

1 12.0 15.3 10.2 4.8 1.10

1-2 24.1 30.7 20.4 9.5 2.19

1-3 36.1 46.0 30.7 14.3 3.29

1-4 48.1 61.3 40.9 19.1 4.3

1-5 60.2 76.7 51.1 23.8 5.48

1-6 72.2 92.0 61.3 28.6 6.57

1-7 72.2 92.0 61.3 28.6 6.57

1-8 72.2 92.0 61.3 28.6 6.57

1-9 72.2 92.0 61.3 28.6 6.57
Final Permit-to-Install

Oregon Clean Energy Center

Permit Number: P0110840

Facility ID: 0448020102

Effective Date:6/18/2013

Page 56 of 86

Maximum Allowable Cumulative Emissions

if a Siemens turbine is installed

(Tons)

Month(s) CO NOx PM10/PM2.5 VOC H2SO4

1-10 72.2 92.0 61.3 28.6 6.57

1-11 72.2 92.0 61.3 28.6 6.57

1-12 72.2 92.0 61.3 28.6 6.57

After the first 12 calendar months of operation or the first 12 calendar months 

following the issuance of this permit, compliance with the annual emissions 

limitations shall be based upon a rolling, 12-month summation of the monthly

emissions.

m. The permittee shall comply with the following requirements during periods of 

startup and shutdown if a Siemens turbine is installed.

Emissions Limitations During Startup and Shutdown 

(lbs/hr)a

Cold 

Startup

Hot 

Startup

Warm 

Startup

Shutdown

CO 182.0 211.46 214.90 113

NOx 62.67 76.83 78.98 46

VOC 56.0 83.41 84.49 44

a Pound per hour emissions rates as presented are averaged over the 

duration of the event where the duration of a cold start is 180 minutes, 

the duration of a warm start is 98 minutes, the duration of a hot start is 

82 minutes, and the duration of a shutdown is less than 1 hour.

“Cold Startup” is defined as a combustion turbine startup that occurs more than 

64 hours after a combustion turbine shutdown. The period of startup is defined 

as the lesser of the first 180 minutes of continuous fuel flow to the combustion 

turbine after fuel flow is initiated or the period of time from combustion turbine 

fuel flow initiation until the combustion turbine achieves ten consecutive CEM 

data points in compliance with the ppmvd emissions limitations for CO and NOx.

 “Hot Startup” is defined as a combustion turbine startup that occurs within 16 

hours of a combustion turbine shutdown. The period of hot startup is defined as 
Final Permit-to-Install

Oregon Clean Energy Center

Permit Number: P0110840

Facility ID: 0448020102

Effective Date:6/18/2013

Page 57 of 86

the lesser of the first 82 minutes of continuous fuel flow to the combustion turbine 

after fuel flow is initiated or the period of time from combustion turbine fuel flow 

initiation until the combustion turbine achieves ten consecutive CEM data points 

in compliance with the ppmvd emissions limitations for CO and NOx.

“Warm Startup” is defined as a combustion turbine startup that occurs between 

16 hours of and 64 hours of a combustion turbine shutdown. The period of 

startup is defined as the lesser of the first 98 minutes of continuous fuel flow to 

the combustion turbine after fuel flow is initiated or the period of time from 

combustion turbine fuel flow initiation until the combustion turbine achieves ten 

consecutive CEM data points in compliance with the ppmvd emissions limitations 

for CO and NOx.

n. The design net plant base heat rate with the Siemens turbine shall not exceed 

7,227 Btu/kW-hr HHV (ISO conditions without duct firing).

o. The emission limitation specified by this rule is less stringent than the limitation 

established by OAC rule 3745-31-10 through 20.

p. The emission limitation specified by this rule is less stringent than the limitation 

established by ORC 3704.03(T).

q. This emissions unit is exempt from the requirements of this rule, since only 

natural gas is burned.

r. 40 CFR Part 60 subpart A provides applicability provisions, definitions, and other 

general provisions that are pertinent to emissions units affected by 40 CFR Part 

60.

s. This emissions unit is subject to the applicable provisions of Subpart KKKK of the 

New Source Performance Standards (NSPS) as promulgated by the United 

States Environmental Protection Agency, 40 CFR Part 60. The application and 

enforcement of these standards are delegated to the Ohio EPA. The 

requirements of 40 CFR Part 60 are also federally enforceable.

t. This emissions unit is not subject to the requirements of 40 CFR Part 63, Subpart 

YYYY, since it is not located at a major source of HAP emissions.

u. The duct burner is exempt from the requirements of this rule per 40 CFR 

63.11195(e) due to combusting only natural gas.

v. Each continuous NOx monitoring system shall be certified to meet the 

requirements of 40 CFR Part 60, Appendix B, Performance Specifications 2 and 

6. At least 45 days before commencing certification testing of the continuous 

NOx monitoring system(s), the permittee shall develop and maintain a written 

quality assurance/quality control plan designed to ensure continuous valid and 

representative readings of NOx emissions from the continuous monitor(s), in 

units of the applicable standard(s). Except as allowed below, the plan shall 

follow the requirements of 40 CFR Part 60, Appendix F and 40 CFR Part 75, 

Appendix B. The quality assurance/quality control plan and a logbook dedicated 
Final Permit-to-Install

Oregon Clean Energy Center

Permit Number: P0110840

Facility ID: 0448020102

Effective Date:6/18/2013

Page 58 of 86

to the continuous monitoring system must be kept on site and available for 

inspection during regular office hours.

The plan shall include the requirement to conduct relative accuracy test audits for 

the continuous NOx monitoring system in accordance with the frequencies 

required pursuant to 40 CFR Part 60 and 40 CFR Part 75; or may follow relative 

accuracy test audit frequency requirements for monitoring systems subject to 40 

CFR 75, Appendix B, in lieu of frequencies required in 40 CFR Part 60. In either 

case, results shall be recorded and reported in units of the applicable standard(s) 

in accordance with 40 CFR Part 60.

The plan shall include the requirement to conduct quarterly cylinder gas audits or 

relative accuracy audits pursuant to 40 CFR Part 60, and linearity checks 

pursuant to 40 CFR Part 75; however, linearity checks completed pursuant to 40 

CFR Part 75, Appendix B, may be substituted for the quarterly cylinder gas or 

relative accuracy audits required per 40 CFR Part 60.

w. Each continuous carbon monoxide (CO) monitoring system shall be certified to 

meet the requirements of 40 CFR Part 60, Appendix B, Performance 

Specifications 4 or 4a and 6. At least 45 days before commencing certification 

testing of the continuous CO monitoring system(s), the permittee shall develop 

and maintain a written quality assurance/quality control plan designed to ensure 

continuous valid and representative readings of CO emissions from the 

continuous monitor(s), in units of the applicable standard(s). The fuel flow 

monitor/meter shall be maintained as required in Part 75, Appendix D. Except as 

allowed below, the plan shall follow the requirements of 40 CFR Part 60, 

Appendix F. The quality assurance/quality control plan and a logbook dedicated 

to the continuous monitoring system must be kept on site and available for 

inspection during regular office hours.

The plan shall include the requirement to conduct relative accuracy test audits for 

the continuous CO monitoring system in accordance with the frequencies 

required for monitoring systems subject to 40 CFR 60, or may follow relative 

accuracy test audit frequency requirements for monitoring systems subject to 40 

CFR 75, Appendix B. In either case, results shall be recorded and reported in 

units of the applicable standard(s) in accordance with 40 CFR Part 60.

The plan shall include the requirement to conduct quarterly cylinder gas audits or 

relative accuracy audits as required in 40 CFR Part 60; however, the quarterly 

cylinder gas audit and relative accuracy audit frequency requirements may be 

adjusted to coincide with linearity checks completed for continuous emissions 

monitoring systems subject to 40 CFR Part 75, Appendix B requirements.

x. The continuous emission monitoring system consists of all the equipment used to 

acquire data to provide a record of emissions and includes the sample extraction 

and transport hardware, sample conditioning hardware, analyzers, and data 

recording/processing hardware and software.
Final Permit-to-Install

Oregon Clean Energy Center

Permit Number: P0110840

Facility ID: 0448020102

Effective Date:6/18/2013

Page 59 of 86

c) Operational Restrictions

(1) The permittee shall only burn pipeline quality natural gas as fuel in this emissions unit.

(2) To ensure compliance with the PSD modeling, the permittee shall not operate more than 

one combustion turbine in startup mode at a time.

(3) See 40 CFR Part 60, Subpart KKKK (40 CFR 60.4300 – 60.4420)

d) Monitoring and/or Recordkeeping Requirements

(1) For each day during which the permittee burns a fuel other than natural gas, the 

permittee shall maintain a record of the type and quantity of fuel burned in this emissions 

unit.

(2) For purposes of demonstrating compliance with the natural gas sulfur concentration 

restriction of 0.5 grain/dscf, the permittee shall sample and analyze the natural gas 

burned in this emissions unit monthly to determine the sulfur content using the 

appropriate ASTM or Gas Processors Association standards. Fuel supplier data may be 

used to comply with this requirement, provided that it is demonstrated to be 

representative of the fuel received for burning at this emissions unit.

(3) The permittee may elect not to monitor the total sulfur content of the fuel combusted in 

the turbine as specified in d)(2), if the fuel is demonstrated not to exceed potential sulfur 

emissions of 1.4E-03 lb SO2/mmBtu. The permittee shall use one of the following 

sources of information to make the required demonstration:

a. the fuel quality characteristics in a current, valid purchase contract, tariff sheet or 

transportation contract for the fuel, specifying that the maximum total sulfur 

content for natural gas is 0.5 grains of sulfur or less per 100 standard cubic feet, 

has potential sulfur emissions of less than less than 1.4E-03 lb SO2/mmBtu heat 

input;

b. representative fuel sampling data which show that the sulfur content of the fuel 

does not exceed 1.4E-03 lb SO2/mmBtu heat input. At a minimum, the amount of 

fuel sampling data specified in section 2.3.1.4 or 2.3.2.4 of appendix D to part 75 

of this chapter is required; or

c. one of the custom sulfur monitoring schedules outlined in 40 CFR 60.4370(c) 

may be used to comply with the 1.4E-03 lb SO2/mmBtu standard.

(4) The permittee shall maintain monthly records of the following information:

a. the natural gas usage by P001 and P002 for each month;

b. the combined natural gas usage by P001 and P002 for each month; and

c. beginning after the first 12 calendar months of operation or the first 12 calendar 

months following the issuance of this permit, the rolling, 12-month summation of 

the combined natural gas usage by P001 and P002.
Final Permit-to-Install

Oregon Clean Energy Center

Permit Number: P0110840

Facility ID: 0448020102

Effective Date:6/18/2013

Page 60 of 86

Also, during the first 12 calendar months of operation or the first 12 calendar months 

following the issuance of this permit, the permittee shall record the cumulative combined 

natural gas usage by P001 and P002 for each calendar month.

(5) The permittee shall maintain monthly records of the following information:

a. the CO, NOx, PM10/PM2.5, VOC, and H2SO4 emission rate for each month of 

operations; and

b. beginning after the first 12 calendar months of operation or the first 12 calendar 

months following the issuance of this permit, the rolling, 12-month summation of 

the CO, NOx, PM10/PM2.5, VOC, and H2SO4 emissions.

Also, during the first 12 calendar months of operation or the first 12 calendar months 

following the issuance of this permit, the permittee shall record the cumulative CO, NOx, 

PM10/PM2.5, VOC, and H2SO4 emissions for each calendar month.

(6) The permittee shall maintain monthly records of the following information for this 

emissions unit for purposes of calculating rolling, 12-month emissions: 

a. date, time, and duration of each cold, warm, hot startup and shutdown period;

b. the hours of operation of the combustion turbine;

c. the hours of operation of the duct burner;

d. the total duration of all cold startup periods in hours per rolling, 12-month period;

e. the total duration of all hot startup periods in hours per rolling, 12-month period;

f. the total duration of all warm startup periods in hours per rolling, 12-month 

period;

g. the total duration of all shutdown periods in hours per rolling, 12-month period;

h. the total duration of steady-state operation without duct burner firing in hours per 

rolling, 12-month period;

i. the total duration of steady-state operation with duct burner firing in hours per 

rolling, 12-month period;

(7) Prior to the installation of the continuous NOx monitoring system, the permittee shall 

submit information detailing the proposed location of the sampling site in accordance 

with the siting requirements in 40 CFR Part 60, Appendix B, Performance Specification 

2. The Ohio EPA, Central Office shall approve the proposed sampling site and certify 

that the continuous NOx monitoring system meets the requirements of Performance 

Specifications 2 and 6; and the U.S. EPA shall certify that the continuous NOx 

monitoring system meets the requirements under 40 CFR Part 75, which may be 

approved through the recommendation for certification by Ohio EPA to U.S. EPA. Once 
Final Permit-to-Install

Oregon Clean Energy Center

Permit Number: P0110840

Facility ID: 0448020102

Effective Date:6/18/2013

Page 61 of 86

received, the letter(s)/document(s) of certification under Part 60 and certification or 

recommendation for certification under Part 75 shall be maintain on-site and made 

available to the Director (the appropriate Ohio EPA District Office or local air agency) 

upon request.

(8) The permittee shall install, operate, and maintain equipment to continuously monitor and 

record NOx emissions from this emissions unit in units of the applicable standard(s). 

The continuous monitoring and recording equipment shall comply with the requirements 

specified in 40 CFR Part 60 and 40 CFR Part 75.

The permittee shall maintain records of all data obtained by the continuous NOx 

monitoring system including, but not limited to:

a. emissions of NOx in parts per million for each cycle time of the analyzer, with no 

resolution less than one data point per minute required;

b. emissions of NOx in pounds per hour and in units of the applicable standard(s) in 

the appropriate averaging period;

c. results of quarterly cylinder gas audits or linearity checks;

d. results of daily zero/span calibration checks and the magnitude of manual 

calibration adjustments;

e. results of required relative accuracy test audit(s), including results in units of the 

applicable standard(s);

f. hours of operation of the emissions unit, continuous NOx monitoring system, and 

control equipment;

g. the date, time, and hours of operation of the emissions unit without the control 

equipment and/or the continuous NOx monitoring system;

h. malfunction of the control equipment and/or the continuous NOx monitoring 

system; as well as,

i. the reason (if known) and the corrective actions taken (if any) for each such 

event in (g) and (h).

All valid data points generated and recorded by the continuous emission monitoring and 

data acquisition and handling system shall be used in the calculation of the pollutant 

concentration and/or emission rate over the appropriate averaging period.

(9) Prior to the installation of the continuous carbon monoxide (CO) monitoring system, the 

permittee shall submit information detailing the proposed location of the sampling site in 

accordance with the siting requirements in 40 CFR Part 60, Appendix B, Performance 

Specification 4 or 4a (as appropriate). The Ohio EPA, Central Office shall approve the 

proposed sampling site and certify that the continuous CO monitoring system meets the 
Final Permit-to-Install

Oregon Clean Energy Center

Permit Number: P0110840

Facility ID: 0448020102

Effective Date:6/18/2013

Page 62 of 86

requirements of Performance Specifications 4 or 4a and 6. Once received, the 

letter(s)/document(s) of certification shall be maintained on-site and shall be made 

available to the Director (the appropriate Ohio EPA District Office or local air agency) 

upon request.

(10) The permittee shall operate and maintain equipment to continuously monitor and record 

CO emissions from this emissions unit in units of the applicable standard(s). The 

continuous monitoring and recording equipment shall comply with the requirements 

specified in 40 CFR Parts 60.

The permittee shall maintain records of all data obtained by the continuous CO 

monitoring system including, but not limited to:

a. emissions of CO in parts per million for each cycle time of the analyzer, with no 

resolution less than one data point per minute required;

b. emissions of CO in pounds per hour and in units of the applicable standard(s) in 

the appropriate averaging period;

c. results of quarterly cylinder gas audits;

d. results of daily zero/span calibration checks and the magnitude of manual 

calibration adjustments;

e. results of required relative accuracy test audit(s), including results in units of the 

applicable standard(s);

f. hours of operation of the emissions unit, continuous CO monitoring system, and 

control equipment;

g. the date, time, and hours of operation of the emissions unit without the control 

equipment and/or the continuous CO monitoring system;

h. the date, time, and hours of operation of the emissions unit during any 

malfunction of the control equipment and/or the continuous CO monitoring 

system; as well as,

i. the reason (if known) and the corrective actions taken (if any) for each such 

event in (g) and (h).

All valid data points generated and recorded by the continuous emission monitoring and 

data acquisition and handling system shall be used in the calculation of the pollutant 

concentration and/or emission rate over the appropriate averaging period.

(11) The permittee shall calculate and record the monthly CO2 emissions from P001 and 

P002 using data from the continuous flow and moisture content monitors using the 

procedures set forth in 40 CFR Part 75, Appendix G. From this data, the permittee shall 

calculate the CO2 emissions from P001 and P002 per rolling, 12-month period.
Final Permit-to-Install

Oregon Clean Energy Center

Permit Number: P0110840

Facility ID: 0448020102

Effective Date:6/18/2013

Page 63 of 86

(12) The Permit to Install application for these emissions units, P001 and P002, was 

evaluated based on the actual materials and the design parameters of the emissions 

unit's(s’) exhaust system, as specified by the permittee. The “Toxic Air Contaminant 

Statute”, ORC 3704.03(F), was applied to this/these emissions unit(s) for each toxic air 

contaminant listed in OAC rule 3745-114-01, using data from the permit application; and 

modeling was performed for each toxic air contaminant(s) emitted at over one ton per 

year using an air dispersion model such as SCREEN3, AERMOD, or ISCST3, or other 

Ohio EPA approved model. The predicted 1-hour maximum ground-level concentration 

result(s) from the approved air dispersion model, was compared to the Maximum 

Acceptable Ground-Level Concentration (MAGLC), calculated as described in the Ohio 

EPA guidance document entitled “Review of New Sources of Air Toxic Emissions, 

Option A”, as follows:

a. the exposure limit, expressed as a time-weighted average concentration for a 

conventional 8-hour workday and a 40-hour workweek, for each toxic 

compound(s) emitted from the emissions unit(s), (as determined from the raw 

materials processed and/or coatings or other materials applied) has been 

documented from one of the following sources and in the following order of 

preference (TLV was and shall be used, if the chemical is listed):

i. threshold limit value (TLV) from the American Conference of 

Governmental Industrial Hygienists (ACGIH) “Threshold Limit Values for

Chemical Substances and Physical Agents Biological Exposure Indices”;

or 

ii. STEL (short term exposure limit) or the ceiling value from the American 

Conference of Governmental Industrial Hygienists (ACGIH) “Threshold 

Limit Values for Chemical Substances and Physical Agents Biological 

Exposure Indices”; the STEL or ceiling value is multiplied by 0.737 to 

convert the 15-minute exposure limit to an equivalent 8-hour TLV.

b. The TLV is divided by ten to adjust the standard from the working population to 

the general public (TLV/10).

c. This standard is/was then adjusted to account for the duration of the exposure or 

the operating hours of the emissions unit(s), i.e., “X = 24” hours per day and “Y = 

7” days per week, from that of 8 hours per day and 5 days per week. The 

resulting calculation was (and shall be) used to determine the Maximum

Acceptable Ground-Level Concentration (MAGLC):

TLV/10 x 8/X x 5/Y = 4 TLV/XY = MAGLC

d. The following summarizes the results of dispersion modeling for the “worst case” 

toxic contaminant(s) if Mitsubishi turbines are installed:

Toxic Contaminant: H2SO4

TLV (mg/m3): 0.2 mg/m3

Maximum Hourly Emission Rate (lbs/hr): 1.2
Final Permit-to-Install

Oregon Clean Energy Center

Permit Number: P0110840

Facility ID: 0448020102

Effective Date:6/18/2013

Page 64 of 86

Predicted 1-Hour Maximum Ground-Level Concentration (μg/m3): 0.329

MAGLC (μg/m3): 4.76

e. The following summarizes the results of dispersion modeling for the “worst case” 

toxic contaminant(s) if Siemens turbines are installed:

Toxic Contaminant: H2SO4

TLV (mg/m3): 0.2

Maximum Hourly Emission Rate (lbs/hr): 0.7

Predicted 1-Hour Maximum Ground-Level Concentration (μg/m3): 0.169

MAGLC (μg/m3): 4.76

The permittee, has demonstrated that emissions of H2SO4, from emissions unit(s) P001 

and P002, is calculated to be less than eighty per cent of the maximum acceptable 

ground level concentration (MAGLC); any new raw material or processing agent shall 

not be applied without evaluating each component toxic air contaminant in accordance 

with the “Toxic Air Contaminant Statute”, ORC 3704.03(F).

(13) Prior to making any physical changes to or changes in the method of operation of the 

emissions unit(s), that could impact the parameters or values that were used in the 

predicted 1-hour maximum ground-level concentration, the permittee shall re-model the 

change(s) to demonstrate that the MAGLC has not been exceeded. Changes that can 

affect the parameters/values used in determining the 1-hour maximum ground-level 

concentration include, but are not limited to, the following:

a. changes in the composition of the materials used or the use of new materials, 

that would result in the emission of a new toxic air contaminant with a lower 

Threshold Limit Value (TLV) than the lowest TLV previously modeled;

b. changes in the composition of the materials, or use of new materials, that would 

result in an increase in emissions of any toxic air contaminant listed in OAC rule 

3745-114-01, that was modeled from the initial (or last) application; and

c. physical changes to the emissions unit(s) or its/their exhaust parameters (e.g., 

increased/ decreased exhaust flow, changes in stack height, changes in stack 

diameter, etc.).

If the permittee determines that the “Toxic Air Contaminant Statute” will be satisfied for

the above changes, the Ohio EPA will not consider the change(s) to be a "modification" 

under OAC rule 3745-31-01 solely due to a non-restrictive change to a parameter or 

process operation, where compliance with the “Toxic Air Contaminant Statute”, ORC 

3704.03(F), has been documented. If the change(s) meet(s) the definition of a 

“modification”, the permittee shall apply for and obtain a final PTI prior to the change. 

The Director may consider any significant departure from the operations of the 
Final Permit-to-Install

Oregon Clean Energy Center

Permit Number: P0110840

Facility ID: 0448020102

Effective Date:6/18/2013

Page 65 of 86

emissions unit, described in the permit application, as a modification that results in 

greater emissions than the emissions rate modeled to determine the ground level 

concentration; and he/she may require the permittee to submit a permit application for 

the increased emissions.

(14) The permittee shall collect, record, and retain the following information for each toxic 

evaluation conducted to determine compliance with the “Toxic Air Contaminant Statute”, 

ORC 3704.03(F):

a. a description of the parameters/values used in each compliance demonstration 

and the parameters or values changed for any re-evaluation of the toxic(s) 

modeled (the composition of materials, new toxic contaminants emitted, change 

in stack/exhaust parameters, etc.);

b. the Maximum Acceptable Ground-Level Concentration (MAGLC) for each 

significant toxic contaminant or worst-case contaminant, calculated in 

accordance with the “Toxic Air Contaminant Statute”, ORC 3704.03(F);

c. a copy of the computer model run(s), that established the predicted 1-hour 

maximum ground-level concentration that demonstrated the emissions unit(s) to 

be in compliance with the “Toxic Air Contaminant Statute”, ORC 3704.03(F), 

initially and for each change that requires re-evaluation of the toxic air 

contaminant emissions; and

d. the documentation of the initial evaluation of compliance with the “Toxic Air 

Contaminant Statute”, ORC 3704.03(F), and documentation of any determination 

that was conducted to re-evaluate compliance due to a change made to the 

emissions unit(s) or the materials applied.

(15) The permittee shall maintain a record of any change made to a parameter or value used 

in the dispersion model, used to demonstrate compliance with the “Toxic Air 

Contaminant Statute”, ORC 3704.03(F), through the predicted 1-hour maximum 

ground-level concentration. The record shall include the date and reason(s) for the 

change and if the change would increase the ground-level concentration.

(16) See 40 CFR Part 60, Subpart KKKK (40 CFR 60.4300 – 60.4420)

e) Reporting Requirements

(1) The permittee shall submit deviation (excursion) reports that identify each day when a 

fuel other than natural gas was burned in this emissions unit. Each report shall be 

submitted within 30 days after the deviation occurs.

(2) The permittee shall submit quarterly deviation (excursion) reports that identify the 

following:

a. Any monthly record showing an exceedance of the allowable sulfur content of 

natural gas, 0.5 grain per 100 standard cubic feet; and
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b. all exceedances of the rolling, 12-month combined natural gas usage limitation; 

and for the first 12 calendar months of operation or the first 12 calendar months 

following the issuance of this permit, all exceedances of the maximum allowable 

cumulative combined natural gas usage levels.

The quarterly deviation (excursion) reports shall be submitted in accordance with the 

reporting requirements of the Standard Terms and Conditions of this permit.

(3) The permittee shall comply with the following quarterly reporting requirements for the 

emissions unit and its continuous NOx monitoring system:

a. Pursuant to the monitoring, record keeping, and reporting requirements for

continuous monitoring systems contained in 40 CFR 60.7 and 60.13(h) and the 

requirements established in this permit, the permittee shall submit reports within 

30 days following the end of each calendar quarter to the appropriate Ohio EPA 

District Office or local air agency, documenting all instances of NOx emissions in 

excess of any applicable limit specified in this permit, 40 CFR Part 60, 40 CFR 

Parts 75 and 76, OAC Chapters 3745-14 and 3745-23, and any other applicable 

rules or regulations. The report shall document the date, commencement and 

completion times, duration, and magnitude of each exceedance, as well as the 

reason (if known) and the corrective actions taken (if any) for each exceedance. 

Excess emissions shall be reported in units of the applicable standard(s).

b. These quarterly reports shall be submitted by January 30, April 30, July 30, and 

October 30 of each year and shall include the following:

i. the facility name and address;

ii. the manufacturer and model number of the continuous NOx and other 

associated monitors;

iii. a description of any change in the equipment that comprises the 

continuous emission monitoring system (CEMS), including any change to 

the hardware, changes to the software that may affect CEMS readings, 

and/or changes in the location of the CEMS sample probe;

iv. the excess emissions report (EER)*, i.e., a summary of any exceedances 

during the calendar quarter, as specified above;

v. the total NOx emissions for the calendar quarter (tons);

vi. the total operating time (hours) of the emissions unit;

vii. the total operating time of the continuous NOx monitoring system while 

the emissions unit was in operation;

viii. results and date of quarterly cylinder gas audits or linearity checks;

ix. unless previously submitted, results and date of the relative accuracy test 

audit(s), including results in units of the applicable standard(s), (during 

appropriate quarter(s));
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x. unless previously submitted, the results of any relative accuracy test audit 

showing the continuous NOx monitor out-of-control and the compliant 

results following any corrective actions;

xi. the date, time, and duration of any/each malfunction** of the continuous 

NOx monitoring system, emissions unit, and/or control equipment;

xii. the date, time, and duration of any downtime** of the continuous NOx 

monitoring system and/or control equipment while the emissions unit was 

in operation; and

xiii. the reason (if known) and the corrective actions taken (if any) for each 

event in (b)(xi) and (xii).

Each report shall address the operations conducted and data obtained during the 

previous calendar quarter. Data substitution procedures from 40 CFR 75 are not to be 

used for showing compliance with the short term OAC 3745-31-05(A)(3) rule-based or 

NSPS-based limitation(s) in this permit.

* where no excess emissions have occurred or the continuous monitoring system(s) 

has/have not been inoperative, repaired, or adjusted during the calendar quarter, such 

information shall be documented in the EER quarterly report

** each downtime and malfunction event shall be reported regardless if there is an 

exceedance of any applicable limit

(4) The permittee shall comply with the following quarterly reporting requirements for the 

emissions unit and its continuous CO monitoring system:

a. Pursuant to the monitoring, record keeping, and reporting requirements for

continuous monitoring systems contained in 40 CFR 60.7 and 60.13(h) and the 

requirements established in this permit, the permittee shall submit reports within 

30 days following the end of each calendar quarter to the appropriate Ohio EPA 

District Office or local air agency, documenting all instances of CO emissions in 

excess of any applicable limit specified in this permit, 40 CFR Part 60, OAC 

Chapter 3745-21, and any other applicable rules or regulations. The report shall 

document the date, commencement and completion times, duration, and 

magnitude of each exceedance, as well as, the reason (if known) and the 

corrective actions taken (if any) for each exceedance. Excess emissions shall be 

reported in units of the applicable standard(s).

b. These quarterly reports shall be submitted by January 30, April 30, July 30, and 

October 30 of each year and shall include the following:

i. the facility name and address;

ii. the manufacturer and model number of the continuous CO and other 

associated monitors;
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iii. a description of any change in the equipment that comprises the 

continuous emission monitoring system (CEMS), including any change to 

the hardware, changes to the software that may affect CEMS readings, 

and/or changes in the location of the CEMS sample probe;

iv. the excess emissions report (EER)*, i.e., a summary of any exceedances 

during the calendar quarter, as specified above;

v. the total CO emissions for the calendar quarter (tons);

vi. the total operating time (hours) of the emissions unit;

vii. the total operating time of the continuous CO monitoring system while the 

emissions unit was in operation;

viii. results and dates of quarterly cylinder gas audits;

ix. unless previously submitted, results and dates of the relative accuracy 

test audit(s), including results in units of the applicable standard(s), 

(during appropriate quarter(s));

x. unless previously submitted, the results of any relative accuracy test audit 

showing the continuous CO monitor out-of-control and the compliant 

results following any corrective actions;

xi. the date, time, and duration of any/each malfunction** of the continuous 

CO monitoring system, emissions unit, and/or control equipment;

xii. the date, time, and duration of any downtime** of the continuous CO 

monitoring system and/or control equipment while the emissions unit was 

in operation; and

xiii. the reason (if known) and the corrective actions taken (if any) for each 

event in (b)(xi) and (xii).

Each report shall address the operations conducted and data obtained during the 

previous calendar quarter. Data substitution procedures from 40 CFR 75 are not to be 

used for showing compliance with the short term OAC 3745-31-05(A)(3) rule-based or 

NSPS-based limitation(s) in this permit.

* where no excess emissions have occurred or the continuous monitoring system(s) 

has/have not been inoperative, repaired, or adjusted during the calendar quarter, such 

information shall be documented in the EER quarterly report

** each downtime and malfunction event shall be reported regardless if there is an 

exceedance of any applicable limit

(5) The permittee shall collect, record, and maintain measurements, data, records, and 

reports required per 40 CFR Part 75; and shall submit certification, recertification, 

notifications, applications, monitoring plans, petitions for alternative monitoring systems, 
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electronic quarterly reports, and any other pertinent record and/or report to the 

Administrator (U.S. EPA), as required by this Part.

(6) The permittee shall submit annual reports that include any changes to any parameter or 

value used in the dispersion model used to demonstrate compliance with the “Toxic Air 

Contaminate Statute”, ORC 3704.03(F), through the predicted 1 hour maximum 

concentration. The report should include:

a. the original model input;

b. the updated model input;

c. the reason for the change(s) to the input parameter(s); and

d. a summary of the results of the updated modeling, including the input changes; 

and

e. a statement that the model results indicate that the 1-hour maximum ground-level 

concentration is less than 80% of the MAGLC.

If no changes to the emissions, emissions unit(s), or the exhaust stack have been made 

during the reporting period, then the report shall include a statement to that effect.

(7) See 40 CFR Part 60, Subpart KKKK (40 CFR 60.4300 – 60.4420)

f) Testing Requirements

(1) Compliance with the Emissions Limitations and/or Control Requirements specified in 

section b) of these terms and conditions shall be determined in accordance with the 

following methods:

a. Emission Limitation:

If a Mitsubishi turbine is installed, CO emissions from this emissions unit shall not 

exceed 2.0 ppmvd at 15% oxygen as an hourly average and 13.7 lbs/hr when the 

duct burner is not in operation; and, 2.0 ppmvd at 15% oxygen as an hourly 

average and 12.7 lbs/hr when the duct burner is in operation.

Applicable Compliance Method:

These emissions limitations are based on manufacturer’s data. Ongoing 

compliance with the CO emission limitations shall be demonstrated through the 

data collected as required in the Monitoring and Record keeping Section of this 

permit; and through demonstration of compliance with the quality 

assurance/quality control plan, which shall meet the requirements of 40 CFR Part 

60.

If required, the permittee shall demonstrate compliance using Methods 1 thru 4 

and 10 of 40 CFR Part 60, Appendix A. Alternative U.S. EPA approved test 

methods may be used with prior approval from the Ohio EPA. 
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b. Emission Limitation:

If a Mitsubishi turbine is installed, CO emissions from this emissions unit shall not 

exceed 183.9 tons per rolling, 12-month period.

Applicable Compliance Method:

This emissions limitation is based on the following anticipated worst case 

emissions: 50 cold startups per year, with a minimum downtime preceding cold 

startup of 60 hours and a cold startup duration of 150 minutes, maximum CO 

emissions of 2,766.8 pounds during each cold startup period; 250 hot startups 

per year with a of duration of 67 minutes each and maximum CO emissions of 

646 pounds during each hot startup period; hourly CO emissions at ISO 

conditions during steady state operation of 12.7 lbs/hr based on manufacturer’s 

data and steady state operating hours was determined by the following equation.

8,760 h − 50 60 h +

 

 







 + 250 

 

 







 = 5,355.8 hours

The allowable annual emission rate was determined by the following calculation 

using the above information.



,.



,.



 .







 



= 183.9 tons

Where:

CS = cold starts

HS = hot starts

Ongoing compliance with this emissions limitation shall be based on the pounds 

per hour emission data from the CO CEMS and the actual hours of operation of 

this emissions unit.

c. Emission Limitation:

If a Mitsubishi turbine is installed, CO emissions from this emissions unit shall not 

exceed 1106.72 lbs/hr during cold startup, 578.5 lbs/hr during hot startup, 973.42 

lbs/hr during warm startup, and 263 lbs/hr during shutdown averaged over the 

duration of the event.
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Applicable Compliance Method:

These emissions limitations are based on manufacturer’s data. Ongoing 

compliance with the CO emission limitations shall be demonstrated through the 

data collected as required in the Monitoring and Record keeping Section of this 

permit; and through demonstration of compliance with the quality 

assurance/quality control plan, which shall meet the requirements of 40 CFR Part 

60.

d. Emission Limitation:

If a Mitsubishi turbine is installed, NOx emissions from this emissions unit shall 

not exceed 2.0 ppmvd at 15% oxygen as an hourly average and 22.6 lbs/hr when 

the duct burner is not in operation; and, NOx emissions shall not exceed 2.0 

ppmvd at 15% oxygen as an hourly average and 20.8 lbs/hr when the duct 

burner is in operation.

Applicable Compliance Method:

These emissions limitations are based on manufacturer’s data. Ongoing 

compliance with the NOx emissions limitations shall be demonstrated through the 

data collected as required in the Monitoring and Record keeping Section of this 

permit; and through demonstration of compliance with the quality 

assurance/quality control plan, which shall meet the testing and recertification 

requirements of 40 CFR Part 60 and 40 CFR Part 75.

If required, the permittee shall demonstrate compliance using Methods 1 thru 4 

and 7E of 40 CFR Part 60, Appendix A, and the procedures specified in 40 CFR 

60.4400. Alternative U.S. EPA approved test methods may be used with prior 

approval from the Ohio EPA.

e. Emission Limitation:

If a Mitsubishi turbine is installed, NOx emissions shall not exceed 94.8 tons per 

rolling, 12-month period.

Applicable Compliance Method:

This emissions limitation is based on the following anticipated worst case 

emissions: 250 hot startups per year with a duration of 67 minutes each and 

maximum NOx emissions of 52.4 pounds during each hot startup period; hourly 

NOx emissions at ISO conditions during steady state operation of 20.8 lbs/hr 

based on manufacturer’s data and steady state operating hours as calculated by 

the following equation.

8,760 h − 250 

67 

60 







 = 8,480.83 h   
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The allowable annual emission rate was determined by the following calculation 

using the above information.



.



. .













=94.8 tons NOx

Where:

HS = hot starts

Ongoing compliance with this emissions limitation shall be determined using the 

pounds per hour emission data from the NOx CEMS and the actual hours of 

operation of this emissions unit.

f. Emission Limitation:

If a Mitsubishi turbine is installed, NOx emissions from this emissions unit shall 

not exceed 43.56 lbs/hr during cold startup, 46.93 lbs/hr during hot startup, 

42.27 lbs/hr during warm startup, and 35 lbs/hr during shutdown averaged over 

the duration of the event.

Applicable Compliance Method:

These emissions limitations are based on manufacturer’s data. Ongoing 

compliance with the NOx emissions limitations shall be demonstrated through the 

data collected as required in the Monitoring and Record keeping Section of this 

permit; and through demonstration of compliance with the quality 

assurance/quality control plan, which shall meet the testing and recertification 

requirements of 40 CFR Part 60 and 40 CFR Part 75.

g. Emission Limitation:

If a Mitsubishi turbine is installed, PM10 emissions and PM2.5 emissions shall not 

exceed 3.84E-03 lb/mmBtu of heat input and 11.3 lbs/hr when the duct burner is 

not in operation; and, PM10 and PM2.5 shall not exceed 3.73E-03 lb/mmBtu of 

heat input and 10.1 lbs/hr when the duct burner is in operation.

Applicable Compliance Method:

These emissions limitations are based on manufacturer’s data. If required, the 

permittee shall demonstrate compliance with these emissions limitations using 

Methods 201A and 202 of 40 CFR Part 51, Appendix M. Alternative U.S. EPA 

approved test methods may be used with prior approval from the Ohio EPA.
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h. Emission Limitation:

If a Mitsubishi turbine is installed, PM10 and PM2.5 emissions from this emissions 

unit shall not exceed 44.2 tons per rolling, 12-month period.

Applicable Compliance Method:

This emission limitation was developed by multiplying the short-term allowable 

PM10/PM2.5 emission limitation (10.1 lbs/hr) by the maximum annual hours of 

operation (8,760 hours), and then dividing by 2,000 pounds per ton. Therefore, if 

compliance is shown with the short-term allowable emission limitation, 

compliance shall also be shown with the annual emission limitation.

i. Emission Limitation:

The sulfur content of natural gas burned shall not exceed 0.5 grain per standard 

cubic feet.

Applicable Compliance Method:

Compliance with the lb/mmBtu limitation will be determined by the monitoring and 

recordkeeping specified in 40 CFR 60.4365 or 40 CFR 60.4370.

If required, the permittee shall demonstrate compliance using the procedures 

specified in 40 CFR 60.4415(a)(1). Alternative U.S. EPA approved test methods 

may be used with prior approval from the Ohio EPA.

j. Emission Limitation:

SO2 emissions shall not exceed 1.4E-03 lb/mmBtu of heat input.

Applicable Compliance Method:

The lb/mmBtu limitation was established based on using pipeline quality natural 

gas having a maximum sulfur content of 0.5 grains per 100 cubic feet according 

to the following calculation. Multiply the maximum sulfur content of natural gas 

(0.5 grain S/100 scf) by the molecular weight of SO2 (64.07 lb SO2/lb-mole) 

divide by the molecular weight of sulfur (32.06 lb S/lb-mole) divide by (7,000 

grains/lb), divide by (1,020 Btu/scf), and multiply by (106 Btu/mmBtu).

If required, compliance shall be demonstrated according to 40 CFR 60.4415.

k. Emission Limitation:

The combined SO2 emissions from P001 and P002 shall not exceed 34.2 tons 

per rolling 12-month period if Mitsubishi turbines are installed.

Applicable Compliance Method:

Compliance with this emissions limitation shall be determined by the following 

calculation based on the records required by d). Multiply the maximum sulfur 
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content of natural gas (0.5 gr S/100 scf) by the molecular weight of SO2 (64.07 

lb/lb-mole), divide by the molecular weight of sulfur (32.06 lb/lb-mole), divide by 

(7,000 gr/lb), multiply by the monthly natural gas usage (scf), and divide by 

(2,000 lbs/ton) to determine the monthly SO2 emissions (tons). Add the SO2

emissions calculated for the current month to the total SO2 emissions calculated 

for the previous 11 months to determine the tons SO2 emissions per rolling, 12-

month period.

l. Emission Limitation:

If a Mitsubishi turbine is installed, VOC emissions shall not exceed 2.0 ppmvd at 

15% oxygen as an hourly average and 7.9 lbs/hr when the duct burner is not in 

operation; and, VOC emissions shall not exceed 2.0 ppmvd at 15% oxygen as an 

hourly average and 7.3 lbs/hr when the duct burner is in operation.

Applicable Compliance Method:

These emissions limitations are based on manufacturer’s data. If required, the 

permittee shall demonstrate compliance with this emission limitation through 

emission testing performed in accordance with Methods 1 through 4 and 18, 25 

or 25A, as appropriate, of 40 CFR Part 60, Appendix A. Use of Method 18, 25 or 

25A is to be selected based on the results of pre-survey stack sampling and U.S. 

EPA guidance documents. Alternative U.S. EPA approved test methods may be 

used with prior approval from Ohio EPA.

m. Emission Limitation:

If a Mitsubishi turbine is installed, VOC emissions shall not exceed 56.0 tons per 

rolling, 12-month period.

Applicable Compliance Method:

This emissions limitation is based on the following anticipated worst case 

emissions: 50 cold startups per year, with a minimum downtime preceding cold 

startup of 60 minutes and a cold startup duration of 150 minutes, maximum VOC 

emissions of 848.5 pounds during each cold startup period; 250 hot startups per 

year with a of duration of 67 minutes each and maximum VOC emissions of 

122.1 pounds during each hot startup period; hourly VOC emissions at ISO 

conditions during steady state operation of 7.3 lbs/hr based on manufacturer’s 

data and steady state operating hours was determined by the following equation.

8,760 h − 50 60 h +

 

 







 + 250 

 

 







 = 5,355.8 hours

The allowable annual emission rate was determined by the following calculation 

using the above information.
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.



.



,.



 .











= 56.0 tons

Where:

CS = cold starts

HS = hot starts

Ongoing compliance with this emissions limitation shall be based on the following 

calculation. 

 = (#) 339.5



h

 + (#) 109.88 

 + (#) 314.07 h

 + (#) 7.3



h

 + (#)(7.0



h

)

2000 



Where:

VOC = tons VOC emissions per rolling, 12-month period

#CS = hours operated in cold startup per rolling, 12-month period

#HS = hours operated in hot startup per rolling, 12-month period

#WS = hours operated in warm startup per rolling, 12-month period

#SSDB = hours operated in steady state with duct burner per rolling, 12-month 

period

#SSNDB = hours operated in steady state without duct burner per rolling, 12-

month period 

n. Emission Limitation:

If a Mitsubishi turbine is installed, VOC emissions from this emissions unit shall 

not exceed 339.4 lbs/hr during cold startup, 109.34 lbs/hr during hot startup, 

314.07 lbs/hr during warm startup, and 111 lbs/hr during shutdown averaged 

over the duration of the event.

Applicable Compliance Method:

These emissions limitations are based on manufacturer’s data. If required, the 

permittee shall demonstrate compliance with this emission limitation through 

emission testing performed in accordance with Methods 1 through 4 and 18, 25 

or 25A, as appropriate, of 40 CFR Part 60, Appendix A. Use of Method 18, 25 or 
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25A is to be selected based on the results of pre-survey stack sampling and U.S. 

EPA guidance documents. Alternative U.S. EPA approved test methods may be 

used with prior approval from Ohio EPA.

o. Emission Limitation:

If a Mitsubishi turbine is installed, H2SO4 emissions shall not exceed 4.1E-04 

lb/mmBtu of heat input and 1.2 lbs/hr when the duct burner is not in operation; 

and, H2SO4 emissions shall not exceed 4.4E-04 lb/mmBtu of heat input and 1.2 

lbs/hr when the duct burner is in operation.

These emissions limitations are based on manufacturer’s data. If required, the 

permittee shall demonstrate compliance using Methods 1 thru 4 and 8 of 40 CFR 

Part 60, Appendix A. Alternative U.S. EPA approved test methods may be used 

with prior approval from the Ohio EPA.

p. Emission Limitation:

If a Mitsubishi turbine is installed, H2SO4 emissions shall not exceed 5.26 tons 

per rolling, 12-month period.

Applicable Compliance Method:

This emission limitation was developed by multiplying the short-term allowable 

H2SO4 emission limitation (1.2 lbs/hr) by the maximum annual hours of operation 

(8,760 hours), and then dividing by 2,000 pounds per ton. Therefore, if 

compliance is shown with the short-term allowable emission limitation, 

compliance shall also be shown with the annual emission limitation.

q. Emission Limitation:

If a Mitsubishi turbine is installed, CO2e emissions shall not exceed 318,404 

lbs/hr and 1,394,611 tons per rolling, 12-month period.

Applicable Compliance Method:

The hourly emission limitation is based on the sum of following manufacturer’s 

data (317,920.46 lbs/hr CO2, 6.007 lbs/hr CH4, and 1.154 lbs/hr N2O) multiplied 

by the associated global warming potential for each pollutant (CO2=1, CH4=21, 

N2O=310 from Table A-1 of 40 CFR 98).

317,920.46



h

 (1) + 6.007



h

 (21) + 1.154



h

 (310) = 318,404 /h

Since the CO2e emissions are estimated to consist of more than 99% CO2, 

compliance with this emission limitation will be assumed provided that the hourly 

CO2 emission rate does not exceed 317,920.46 lbs/hr. If required, the permittee 

shall conduct emissions testing using Methods 1, 2, 3A and 4 of 40 CFR Part 60, 

Appendix A to determine the hourly CO2 emission rate.
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The annual emission limitation is based on the sum of following manufacturer’s 

data (317,920.46 lbs/hr CO2, 6.01 lbs/hr CH4, and 1.15 lbs/hr N2O) multiplied by 

the associated global warming potential for each pollutant (CO2=1, CH4=21, 

N2O=310 from Table A-1 of 40 CFR 98), multiplied by the maximum annual 

hours of operation (8,760 hrs/yr) and divided by (2,000 lbs/ton).

317,920.46



h

 (1) + 6.007



h

 (21)

+ 1.154



h

 (310) 8,760

h

  



2000 = 1,394,611 /

Since the CO2e emissions are estimated to consist of more than 99% CO2, 

compliance with this emission limitation will be assumed provided that the rolling, 

12-month CO2 emissions as calculated in section d) above do not exceed 

1,392,492 tons per rolling, 12-month period (317,920.46 lbs/hr x 8760 hrs/yr x 

ton/2000 lb = 1,392,492 tons/yr).

r. Emission Limitation:

Visible particulate emissions from any stack serving this emissions unit shall not 

exceed 10 percent opacity as a 6-minute average.

Applicable Compliance Method:

If required, the permittee shall demonstrate compliance with this emissions 

limitation using Method 9 of 40 CFR Part 60, Appendix A. Alternative U.S. EPA 

approved test methods may be approved with prior approval from Ohio EPA.

s. Emission Limitation:

If a Siemens turbine is installed, CO emissions from this emissions unit shall not 

exceed 2.0 ppmvd at 15% oxygen as an hourly average and 13.0 lbs/hr when the 

duct burner is not in operation; and, 2.0 ppmvd at 15% oxygen as an hourly 

average and 13.0 lbs/hr when the duct burner is in operation.

Applicable Compliance Method:

These emissions limitations are based on manufacturer’s data. Ongoing 

compliance with the CO emission limitations shall be demonstrated through the 

data collected as required in the Monitoring and Record keeping Section of this 

permit; and through demonstration of compliance with the quality 

assurance/quality control plan, which shall meet the requirements of 40 CFR Part 

60.

If required, the permittee shall demonstrate compliance using Methods 1 thru 4 

and 10 of 40 CFR Part 60, Appendix A. Alternative U.S. EPA approved test 

methods may be used with prior approval from the Ohio EPA.

t. Emission Limitation:
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If a Siemens turbine is installed, CO emissions from this emissions unit shall not 

exceed 182.0 lbs/hr during cold startup, 211.46 lbs/hr during hot startup, 214.90 

lbs/hr during warm startup, and 113 lbs/hr during shutdown averaged over the 

duration of the event.

Applicable Compliance Method:

These emissions limitations are based on manufacturer’s data. Ongoing 

compliance with the CO emission limitations shall be demonstrated through the 

data collected as required in the Monitoring and Record keeping Section of this 

permit; and through demonstration of compliance with the quality 

assurance/quality control plan, which shall meet the requirements of 40 CFR Part 

60.

u. Emission Limitation:

If a Siemens turbine is installed, CO emissions from this emissions unit shall not 

exceed 72.2 tons per rolling, 12-month period.

Applicable Compliance Method:

This emissions limitation is based on the following anticipated worst case 

emissions: 250 warm startups per year, with a minimum downtime preceding 

warm startup of 16 hours and a warm startup duration of 98 minutes, maximum 

CO emissions of 351 pounds during each warm startup period; hourly CO 

emissions at ISO conditions during steady state operation of 13.0 lbs/hr based on 

manufacturer’s data and steady state operating hours was determined by the 

following equation.

8,760 h − 250 16 h +

 

 







 = 4,351.7 hours

The allowable annual emission rate was determined by the following calculation 

using the above information.



 ,.



 .











= 72.2 tons

Where:

WS = warm starts

Ongoing compliance with this emissions limitation shall be based on the pounds 

per hour emission data from the CO CEMS and the actual hours of operation of 

this emissions unit.
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v. Emission Limitation:

If a Siemens turbine is installed, NOx emissions from this emissions unit shall not 

exceed 2.0 ppmvd at 15% oxygen as an hourly average and 22.0 lbs/hr when the 

duct burner is not in operation; and, NOx emissions shall not exceed 2.0 ppmvd 

at 15% oxygen as an hourly average and 21.0 lbs/hr when the duct burner is in 

operation.

Applicable Compliance Method:

These emissions limitations are based on manufacturer’s data. Ongoing 

compliance with the NOx emissions limitations shall be demonstrated through the 

data collected as required in the Monitoring and Record keeping Section of this 

permit; and through demonstration of compliance with the quality 

assurance/quality control plan, which shall meet the testing and recertification 

requirements of 40 CFR Part 60 and 40 CFR Part 75.

If required, the permittee shall demonstrate compliance using Methods 1 thru 4 

and 7E of 40 CFR Part 60, Appendix A, and the procedures specified in 40 CFR 

60.4400. Alternative U.S. EPA approved test methods may be used with prior 

approval from the Ohio EPA.

w. Emission Limitation:

If a Siemens turbine is installed, NOx emissions shall not exceed 92.0 tons per 

rolling, 12-month period.

Applicable Compliance Method:

This emission limitation was developed by multiplying the short-term allowable 

NOx emission limitation (21.0 lbs/hr) by the maximum annual hours of operation 

(8,760 hours), and then dividing by 2,000 pounds per ton. Therefore, if 

compliance is shown with the short-term allowable emission limitation, 

compliance shall also be shown with the annual emission limitation.

Ongoing compliance with this emissions limitation shall be determined using the 

pounds per hour emission data from the NOx CEMS and the actual hours of 

operation of this emissions unit.

x. Emission Limitation:

If a Siemens turbine is installed, NOx emissions from this emissions unit shall not 

exceed 62.67 lbs/hr during cold startup, 76.83 lbs/hr during hot startup, 78.98 

lbs/hr during warm startup, and 46 lbs/hr during shutdown averaged over the 

duration of the event.

Applicable Compliance Method:

These emissions limitations are based on manufacturer’s data. Ongoing 

compliance with the NOx emissions limitations shall be demonstrated through the 

data collected as required in the Monitoring and Record keeping Section of this 
Final Permit-to-Install

Oregon Clean Energy Center

Permit Number: P0110840

Facility ID: 0448020102

Effective Date:6/18/2013

Page 80 of 86

permit; and through demonstration of compliance with the quality 

assurance/quality control plan, which shall meet the testing and recertification 

requirements of 40 CFR Part 60 and 40 CFR Part 75.

y. Emission Limitation:

If a Siemens turbine is installed, PM10 emissions and PM2.5 emissions shall not 

exceed 4.7E-03 lb/mmBtu of heat input and 13.3 lbs/hr when the duct burner is 

not in operation; and, PM10 and PM2.5 shall not exceed 5.5E-03 lb/mmBtu of heat 

input and 14.0 lbs/hr when the duct burner is in operation.

Applicable Compliance Method:

These emissions limitations are based on manufacturer’s data. If required, the 

permittee shall demonstrate compliance with these emissions limitations using 

Methods 201A and 202 of 40 CFR Part 51, Appendix M. Alternative U.S. EPA 

approved test methods may be used with prior approval from the Ohio EPA.

z. Emission Limitation:

If a Siemens turbine is installed, PM10 and PM2.5 emissions from this emissions 

unit shall not exceed 61.3 tons per rolling, 12-month period.

Applicable Compliance Method:

This emission limitation was developed by multiplying the short-term allowable 

PM10/PM2.5 emission limitation (14.0 lbs/hr) by the maximum annual hours of 

operation (8,760 hours), and then dividing by 2,000 pounds per ton. Therefore, if 

compliance is shown with the short-term allowable emission limitation, 

compliance shall also be shown with the annual emission limitation.

aa. Emission Limitation:

The combined SO2 emissions from P001 and P002 shall not exceed 36.8 tons 

per rolling, 12-month period if Siemens turbines are installed.

Applicable Compliance Method:

Compliance with this emissions limitation shall be determined by the following 

calculation based on the records required by d). Multiply the maximum sulfur 

content of natural gas (0.5 gr S/100 scf) by the molecular weight of SO2 (64.07 

lb/lb-mole), divide by the molecular weight of sulfur (32.06 lb/lb-mole), divide by 

(7,000 gr/lb), multiply by the monthly natural gas usage (scf), and divide by 

(2,000 lbs/ton) to determine the monthly SO2 emissions (tons). Add the SO2

emissions calculated for the current month to the total SO2 emissions calculated 

for the previous 11 months to determine the tons SO2 emissions per rolling, 12-

month period.
Final Permit-to-Install

Oregon Clean Energy Center

Permit Number: P0110840

Facility ID: 0448020102

Effective Date:6/18/2013

Page 81 of 86

bb. Emission Limitation:

If a Siemens turbine is installed, VOC emissions shall not exceed 1.0 ppmvd at 

15% oxygen as an hourly average and 3.9 lbs/hr when the duct burner is not in 

operation; and, VOC emissions shall not exceed 1.9 ppmvd at 15% oxygen as an 

hourly average and 5.9 lbs/hr when the duct burner is in operation.

Applicable Compliance Method:

These emissions limitations are based on manufacturer’s data. If required, the 

permittee shall demonstrate compliance with this emission limitation through 

emission testing performed in accordance with Methods 1 through 4 and 18, 25 

or 25A, as appropriate, of 40 CFR Part 60, Appendix A. Use of Method 18, 25 or 

25A is to be selected based on the results of pre-survey stack sampling and U.S. 

EPA guidance documents. Alternative U.S. EPA approved test methods may be 

used with prior approval from Ohio EPA.

cc. Emission Limitation:

If a Siemens turbine is installed, VOC emissions shall not exceed 28.6 tons per 

rolling, 12-month period.

Applicable Compliance Method:

This emissions limitation is based on the following anticipated worst case 

emissions: 250 warm startups per year, with a minimum downtime preceding 

warm startup of 16 hours and a warm startup duration of 98 minutes, maximum 

VOC emissions of 138 pounds during each warm startup period; hourly VOC 

emissions at ISO conditions during steady state operation of 5.2 lbs/hr based on 

manufacturer’s data and steady state operating hours was determined by the 

following equation.

8,760 h − 250 16 h +

 

 







 = 4,351.7 hours

The allowable annual emission rate was determined by the following calculation 

using the above information.



 ,.



 .











= 28.6 tons

Where:

WS = warm starts

Ongoing compliance with this emissions limitation shall be based on the following 

calculation. 
Final Permit-to-Install

Oregon Clean Energy Center

Permit Number: P0110840

Facility ID: 0448020102

Effective Date:6/18/2013

Page 82 of 86

(#).





(#).

(#).

(#).





(#).











= VOC

Where:

VOC = tons VOC emissions per rolling, 12-month period

#CS = hours operated in cold startup per rolling, 12-month period

#HS = hours operated in hot startup per rolling, 12-month period

#WS = hours operated in warm startup per rolling, 12-month period

#SSDB = hours operated in steady state with duct burner per rolling, 12-month 

period

#SSNDB = hours operated in steady state without duct burner per rolling, 12-

month period 

dd. Emission Limitation:

If a Siemens turbine is installed, VOC emissions from this emissions unit shall 

not exceed 56.0 lbs/hr during cold startup, 83.41 lbs/hr during hot startup, 84.49 

lbs/hr during warm startup, and 44 lbs/hr during shutdown averaged over the 

duration of the event.

Applicable Compliance Method:

These emissions limitations are based on manufacturer’s data. If required, the 

permittee shall demonstrate compliance with this emission limitation through 

emission testing performed in accordance with Methods 1 through 4 and 18, 25 

or 25A, as appropriate, of 40 CFR Part 60, Appendix A. Use of Method 18, 25 or 

25A is to be selected based on the results of pre-survey stack sampling and U.S. 

EPA guidance documents. Alternative U.S. EPA approved test methods may be 

used with prior approval from Ohio EPA.

ee. Emission Limitation:

If a Siemens turbine is installed, H2SO4 emissions shall not exceed 6.0E-04 

lb/mmBtu of heat input and 1.6 lbs/hr when the duct burner is not in operation; 

and, H2SO4 emissions shall not exceed 7.0E-04 lb/mmBtu of heat input and 1.5 

lbs/hr when the duct burner is in operation.

These emissions limitations are based on manufacturer’s data. If required, the 

permittee shall demonstrate compliance using Methods 1 thru 4 and 8 of 40 CFR 

Part 60, Appendix A. Alternative U.S. EPA approved test methods may be used 

with prior approval from the Ohio EPA.
Final Permit-to-Install

Oregon Clean Energy Center

Permit Number: P0110840

Facility ID: 0448020102

Effective Date:6/18/2013

Page 83 of 86

ff. Emission Limitation:

If a Siemens turbine is installed, H2SO4 emissions shall not exceed 6.57 tons per 

rolling, 12-month period.

Applicable Compliance Method:

This emission limitation was developed by multiplying the short-term allowable 

H2SO4 emission limitation (1.5 lbs/hr) by the maximum annual hours of operation 

(8,760 hours), and then dividing by 2,000 pounds per ton. Therefore, if 

compliance is shown with the short-term allowable emission limitation, 

compliance shall also be shown with the annual emission limitation.

gg. Emission Limitation:

If a Siemens turbine is installed, CO2e emissions shall not exceed 327,819 lbs/hr 

and 1,435,847 tons per rolling, 12-month period.

Applicable Compliance Method:

The hourly emission limitation is based on the sum of following manufacturer’s 

data (327,380 lbs/hr CO2, 6.14 lbs/hr CH4, and 1.00 lbs/hr N2O) multiplied by the 

associated global warming potential for each pollutant (CO2=1, CH4=21, 

N2O=310 from Table A-1 of 40 CFR 98).

327,380



h

 (1) + 6.14



h

 (21) + 1.00



h

 (310) = 327,819 /h

Since the CO2e emissions are estimated to consist of more than 99% CO2, 

compliance with this emission limitation will be assumed provided that the hourly 

CO2 emission rate does not exceed 327,380 lbs/hr. If required, the permittee 

shall conduct emissions testing using Methods 1, 2, 3A and 4 of 40 CFR Part 60, 

Appendix A to determine the hourly CO2 emission rate.

This emission limitation is based on the sum of following manufacturer’s data 

(327,380 lbs/hr CO2, 6.14 lbs/hr CH4, and 1.00 lbs/hr N2O) multiplied by the 

associated global warming potential for each pollutant (CO2=1, CH4=21, 

N2O=310 from Table A-1 of 40 CFR 98), multiplied by the maximum annual 

hours of operation (8,760 hrs/yr) and divided by (2,000 lbs/ton).

327,380



h

 (1) + 6.14



h

 (21) + 1.00



h

 (310) 8,760

h

  



2000

= 1,435,847 /

Since the CO2e emissions are estimated to consist of more than 99% CO2, 

compliance with this emission limitation will be assumed provided that the rolling, 

12-month CO2 emissions as calculated in section d) above do not exceed 

1,433,924 tons per rolling, 12-month period (327,380 lbs/hr x 8760 hrs/yr x 

ton/2000 lb = 1,433,924 tons/yr).
Final Permit-to-Install

Oregon Clean Energy Center

Permit Number: P0110840

Facility ID: 0448020102

Effective Date:6/18/2013

Page 84 of 86

(2) The permittee shall conduct, or have conducted, emission testing for this emissions unit 

in accordance with the following requirements:

a. The emission testing shall be conducted within 60 days after achieving the 

maximum production rate at which the emissions unit will be operated, but not 

later than 180 days after initial startup of the emissions unit.

b. The emission testing shall be conducted to demonstrate compliance with the 

allowable mass emission rate(s) for CO, NOx, PM10, PM2.5, VOC, and H2SO4, in 

the appropriate averaging period(s).

The emission testing shall also be conducted to determine a site-specific 

emission factor for CO2.

c. The following test method(s) shall be employed to demonstrate compliance with 

the allowable mass emission rate(s):

For CO, Methods 1 thru 4 and 10 of 40 CFR Part 60, Appendix A;

For NOx, Methods 1 thru 4 and 7E of 40 CFR Part 60, Appendix A, and the 

procedures specified in 40 CFR 60.4400;

For PM10 and PM2.5, Methods 201A and 202 of 40 CFR Part 52, Appendix M;

For SO2, 40 CFR 60.4415;

For VOC, Methods 1 through 4 and 18, 25 or 25A, as appropriate, of 40 CFR 

Part 60, Appendix A. Use of Method 18, 25 or 25A is to be selected based on the 

results of pre-survey stack sampling and U.S. EPA guidance documents;

For H2SO4, Methods 1 thru 4 and 8 of 40 CFR Part 60, Appendix A; and

For CO2, Methods 1, 2, 3A, and 4 of 40 CFR Part 60, Appendix A.

Alternative U.S. EPA approved test methods may be used with prior approval 

from the Ohio EPA.

d. The test(s) shall be conducted under those representative conditions that 

challenge to the fullest extent possible a facility’s ability to meet the applicable 

emissions limits and/or control requirements, unless otherwise specified or 

approved by the appropriate Ohio EPA District Office or local air agency. 

Although this generally consists of operating the emissions unit at its maximum 

material input/production rates and results in the highest emission rate of the 

tested pollutant, there may be circumstances where a lower emissions loading is 

deemed the most challenging control scenario. Failure to test under these 

conditions is justification for not accepting the test results as a demonstration of 

compliance.
Final Permit-to-Install

Oregon Clean Energy Center

Permit Number: P0110840

Facility ID: 0448020102

Effective Date:6/18/2013

Page 85 of 86

e. Not later than 30 days prior to the proposed test date(s), the permittee shall 

submit an "Intent to Test" notification to the appropriate Ohio EPA District Office 

or local air agency. The "Intent to Test" notification shall describe in detail the 

proposed test methods and procedures, the emissions unit operating 

parameters, the time(s) and date(s) of the test(s), and the person(s) who will be 

conducting the test(s). Failure to submit such notification for review and approval 

prior to the test(s) may result in the Ohio EPA District Office's or local air 

agency's refusal to accept the results of the emission test(s).

f. Personnel from the appropriate Ohio EPA District Office or local air agency shall 

be permitted to witness the test(s), examine the testing equipment, and acquire 

data and information necessary to ensure that the operation of the emissions unit 

and the testing procedures provide a valid characterization of the emissions from 

the emissions unit and/or the performance of the control equipment.

g. A comprehensive written report on the results of the emissions test(s) shall be 

signed by the person or persons responsible for the tests and submitted to the 

appropriate Ohio EPA District Office or local air agency within 30 days following 

completion of the test(s). The permittee may request additional time for the 

submittal of the written report, where warranted, with prior approval from the 

appropriate Ohio EPA District Office or local air agency.

(3) Within 60 days of achieving the maximum production rate at which the emissions unit(s) 

will be operated, but not later than 180 days after initial startup, the permittee shall 

conduct certification tests of the continuous NOx monitoring system, in units of the 

applicable standard(s), to demonstrate compliance with 40 CFR Part 60, Appendix B, 

Performance Specification 2; Performance Specification 6 relative accuracy 

requirements; ORC section 3704.03(I); and 40 CFR Part 75.

The permittee shall certify that the fuel flow monitor/meter meets 40 CFR 75 certification 

requirements prior to the performance specification test and shall demonstrate how the 

pound per hour emissions of NOx will be calculated stoichiometrically from the fuel flow 

rate.

Personnel from the Ohio EPA Central Office and the appropriate Ohio EPA District 

Office or local air agency shall be notified 45 days prior to initiation of the applicable 

tests and shall be permitted to examine equipment and witness the certification tests. 

Two copies of the test results shall be submitted to Ohio EPA, one copy to the 

appropriate Ohio EPA District Office or local air agency and one copy to Ohio EPA 

Central Office, and pursuant to OAC rule 3745-15-04, within 30 days after the test is 

completed.

Certification, or recommendation for certification by Ohio EPA to U.S. EPA, of the 

continuous NOx monitoring system shall be granted upon determination by the Ohio 

EPA, Central Office that the system meets the requirements of 40 CFR Part 60, 

Appendix B, Performance Specification 2; Performance Specification 6 relative accuracy 

requirements; ORC section 3704.03(I); and 40 CFR Part 75.
Final Permit-to-Install

Oregon Clean Energy Center

Permit Number: P0110840

Facility ID: 0448020102

Effective Date:6/18/2013

Page 86 of 86

Ongoing compliance with the NOx emissions limitations contained in this permit, 40 CFR 

Parts 60 and 75, and any other applicable standard(s) shall be demonstrated through 

the data collected as required in the Monitoring and Record keeping Section of this 

permit; and through demonstration of compliance with the quality assurance/quality 

control plan, which shall meet the testing and recertification requirements of 40 CFR Part 

60 and 40 CFR Part 75.

(4) Within 60 days of achieving the maximum production rate at which the emissions unit(s) 

will be operated, but not later than 180 days after initial startup, the permittee shall 

conduct certification tests of the continuous CO monitoring system in units of the 

applicable standard(s), to demonstrate compliance with 40 CFR Part 60, Appendix B, 

Performance Specification 4 or 4a (as appropriate); Performance Specification 6 relative 

accuracy requirements; and ORC section 3704.03(I).

The permittee shall certify that the fuel flow monitor/meter is calibrated prior to the 

performance specification test and shall demonstrate how the pound per hour emissions 

of CO will be calculated stoichiometrically from the fuel flow rate.

Personnel from the Ohio EPA Central Office and the appropriate Ohio EPA District 

Office or local air agency shall be notified 30 days prior to initiation of the applicable 

tests and shall be permitted to examine equipment and witness the certification tests. 

Two copies of the test results shall be submitted to Ohio EPA, one copy to the 

appropriate Ohio EPA District Office or local air agency and one copy to Ohio EPA 

Central Office, and pursuant to OAC rule 3745-15-04, within 30 days after the test is 

completed.

Certification of the continuous CO monitoring system shall be granted upon 

determination by the Ohio EPA Central Office that the system meets the requirements of 

40 CFR Part 60, Appendix B, Performance Specification 4 or 4a (as appropriate); 

Performance Specification 6 relative accuracy requirements; and ORC section 

3704.03(I).

Ongoing compliance with the CO emission limitations contained in this permit, 40 CFR 

Part 60, and any other applicable standard(s) shall be demonstrated through the data 

collected as required in the Monitoring and Record keeping Section of this permit; and 

through demonstration of compliance with the quality assurance/quality control plan, 

which shall meet the requirements of 40 CFR Part 60.

g) Miscellaneous Requirements

(1) None.
John R. Kasich, Governor

Mary Taylor, Lt. Governor

Craig W. Butler, Director

50 West Town Street • Suite 700 • P.O. Box 1049 • Columbus, OH 43216-1049

www.epa.ohio.gov • (614) 644-3020 • (614) 644-3184 (fax)

9/30/2014

William Martin

Oregon Clean Energy Center

20 Park Plaza, Suite 456

Boston, MA 02216

RE: FINALAIR POLLUTION PERMIT-TO-INSTALL

Facility ID: 0448020102

Permit Number: P0117413

Permit Type: Administrative Modification

County: Lucas

Dear Permit Holder:

Enclosed please find a final Ohio Environmental Protection Agency (EPA)Air Pollution Permit-to-Install (PTI) 

which will allow you to install or modify the described emissions unit(s) in a manner indicated in the permit. 

Because this permit contains several conditions and restrictions, we urge you to read it carefully. Because this 

permit contains conditions and restrictions, please read it very carefully. In this letter you will find the 

information on the following topics:

 How to appeal this permit

 How to save money, reduce pollution and reduce energy consumption

 How to give us feedback on your permitting experience

 How to get an electronic copy of your permit

How to appeal this permit

The issuance of this PTI is a final action of the Director and may be appealed to the Environmental Review 

Appeals Commission pursuant to Section 3745.04 of the Ohio Revised Code. The appeal must be in writing 

and set forth the action complained of and the grounds upon which the appeal is based. The appeal must be 

filed with the Commission within thirty (30) days after notice of the Director's action. The appeal must be 

accompanied by a filing fee of $70.00, made payable to "Ohio Treasurer Josh Mandel," which the Commission, 

in its discretion, may reduce if by affidavit you demonstrate that payment of the full amount of the fee would 

cause extreme hardship. Notice of the filing of the appeal shall be filed with the Director within three (3) days 

of filing with the Commission. Ohio EPA requests that a copy of the appeal be served upon the Ohio Attorney 

General's Office, Environmental Enforcement Section. An appeal may be filed with the Environmental Review 

Appeals Commission at the following address:

Environmental Review Appeals Commission

77 South High Street, 17th Floor

Columbus, OH 43215

Certified Mail

Yes TOXIC REVIEW

Yes PSD

Yes SYNTHETIC MINOR TO AVOID MAJOR NSR

Yes CEMS

No MACT/GACT

Yes NSPS

No NESHAPS

No NETTING

No MAJOR NON-ATTAINMENT

Yes MODELING SUBMITTED

Yes MAJOR GHG

No SYNTHETIC MINOR TO AVOID MAJOR GHG
How to save money, reduce pollution and reduce energy consumption

The Ohio EPA is encouraging companies to investigate pollution prevention and energy conservation. Not 

only will this reduce pollution and energy consumption, but it can also save you money. If you would like to 

learn ways you can save money while protecting the environment, please contact our Office of Compliance 

Assistance and Pollution Prevention at (614) 644-3469. Additionally, all or a portion of the capital expenditures 

related to installing air pollution control equipment under this permit may be eligible for financing and State tax 

exemptions through the Ohio Air Quality Development Authority (OAQDA) under Ohio Revised Code Section 

3706. For more information, see the OAQDA website: www.ohioairquality.org/clean_air

How to give us feedback on your permitting experience

Please complete a survey at www.epa.ohio.gov/survey.aspx and give us feedback on your permitting 

experience. We value your opinion.

How to get an electronic copy of your permit

This permit can be accessed electronically via the eBusiness Center: Air Services in Microsoft Word format or 

in Adobe PDF on the Division of Air Pollution Control (DAPC) Web page, www.epa.ohio.gov/dapc by clicking 

the "Search for Permits" link under the Permitting topic on the Programs tab. 

If you have any questions, please contact Toledo Department of Environmental Services at (419)936-3015 or 

the Office of Compliance Assistance and Pollution Prevention at (614) 644-3469.

Sincerely,

Erica R. Engel-Ishida, Interim Manager

Permit Issuance and Data Management Section, DAPC

Cc: U.S. EPA

TDES; Michigan; Indiana; Canada
Response to Comments

Oregon Clean Energy Center

Permit Number: P0117413

Facility ID: 0448020102

Response to Comments

Facility ID: 0448020102

Facility Name: Oregon Clean Energy Center

Facility Description: Electric power generating plant

Facility Address:

816 Lallendorf Rd

Oregon, OH 43616

Lucas County

Permit: P0117413, Permit-To-Install - Administrative Modification

A public notice for the draft permit issuance was published in the Ohio EPA Weekly Review and appeared in 

the Toledo Blade on 08/27/2014. The comment period ended on 09/26/2014.

Hearing date (if held)

Hearing Public Notice 

Date (if different from 

draft public notice)

The following comments were received during the comment period specified. Ohio EPA reviewed and 

considered all comments received during the public comment period. By law, Ohio EPA has authority to 

consider specific issues related to protection of the environment and public health. Often, public concerns fall 

outside the scope of that authority. For example, concerns about zoning issues are addressed at the local 

level. Ohio EPA may respond to those concerns in this document by identifying another government agency 

with more direct authority over the issue.

In an effort to help you review this document, the questions are grouped by topic and organized in a consistent 

format. PDF copies of the original comments in the format submitted are available upon request.

1. Topic: There were no comments received.

a. Comment: None

b. Response: None

FINAL

Division of Air Pollution Control

Permit-to-Install

for

Oregon Clean Energy Center

Facility ID: 0448020102

Permit Number: P0117413

Permit Type: Administrative Modification

Issued: 9/30/2014

Effective: 9/30/2014

Division of Air Pollution Control

Permit-to-Install

for

Oregon Clean Energy Center

Table of Contents

Authorization ..................................................................................................................................................... 1

A. Standard Terms and Conditions .................................................................................................................. 3

1. Federally Enforceable Standard Terms and Conditions ......................................................................... 4

2. Severability Clause ................................................................................................................................ 4

3. General Requirements........................................................................................................................... 4

4. Monitoring and Related Record Keeping and Reporting Requirements.................................................. 5

5. Scheduled Maintenance/Malfunction Reporting ..................................................................................... 6

6. Compliance Requirements..................................................................................................................... 6

7. Best Available Technology..................................................................................................................... 7

8. Air Pollution Nuisance............................................................................................................................ 8

9. Reporting Requirements ........................................................................................................................ 8

10. Applicability............................................................................................................................................ 8

11. Construction of New Sources(s) and Authorization to Install .................................................................. 8

12. Permit-To-Operate Application............................................................................................................... 9

13. Construction Compliance Certification ................................................................................................. 10

14. Public Disclosure ................................................................................................................................. 10

15. Additional Reporting Requirements When There Are No Deviations of Federally Enforceable Emission 

Limitations, Operational Restrictions, or Control Device Operating Parameter Limitations ................... 10

16. Fees..................................................................................................................................................... 10

17. Permit Transfers .................................................................................................................................. 10

18. Risk Management Plans ...................................................................................................................... 10

19. Title IV Provisions ................................................................................................................................ 10

B. Facility-Wide Terms and Conditions........................................................................................................... 11

C. Emissions Unit Terms and Conditions ....................................................................................................... 13

1. B001, Auxiliary Boiler........................................................................................................................... 14

2. P005, Wet Cooling Tower .................................................................................................................... 24

3. Emissions Unit Group -P001, P002: P001,P002, ................................................................................ 28

Final Permit-to-Install

Oregon Clean Energy Center

Permit Number: P0117413

Facility ID: 0448020102

Effective Date:9/30/2014

Page 1 of 55

Authorization

Facility ID: 0448020102

Facility Description: Electric power generating plant

Application Number(s): M0002922

Permit Number: P0117413

Permit Description: Administrative modification to revise emissions limitations based on updated 

information from the turbine manufacturer and to revise the projected operating 

scenario for a natural gas-fired combined cycle combustion turbine power plant.

Permit Type: Administrative Modification

Permit Fee: $2,300.00

Issue Date: 9/30/2014

Effective Date: 9/30/2014

This document constitutes issuance to:

Oregon Clean Energy Center

816 Lallendorf Rd

Oregon, OH 43616

of a Permit-to-Install for the emissions unit(s) identified on the following page.

Ohio Environmental Protection Agency (EPA) District Office or local air agency responsible for processing and 

administering your permit:

Toledo Department of Environmental Services

348 South Erie Street

Toledo, OH 43604

(419)936-3015

The above named entity is hereby granted a Permit-to-Install for the emissions unit(s) listed in this section 

pursuant to Chapter 3745-31 of the Ohio Administrative Code. Issuance of this permit does not constitute 

expressed or implied approval or agreement that, if constructed or modified in accordance with the plans 

included in the application, the emissions unit(s) of environmental pollutants will operate in compliance with 

applicable State and Federal laws and regulations, and does not constitute expressed or implied assurance 

that if constructed or modified in accordance with those plans and specifications, the above described 

emissions unit(s) of pollutants will be granted the necessary permits to operate (air) or NPDES permits as 

applicable.

This permit is granted subject to the conditions attached hereto.

Ohio Environmental Protection Agency

Craig W. Butler

Director
Final Permit-to-Install

Oregon Clean Energy Center

Permit Number: P0117413

Facility ID: 0448020102

Effective Date:9/30/2014

Page 2 of 55

Authorization (continued)

Permit Number: P0117413

Permit Description: Administrative modification to revise emissions limitations based on updated information 

from the turbine manufacturer and to revise the projected operating scenario for a 

natural gas-fired combined cycle combustion turbine power plant.

Permits for the following Emissions Unit(s) or groups of Emissions Units are in this document as indicated 

below:

Emissions Unit ID: B001

Company Equipment ID: Auxiliary Boiler

Superseded Permit Number: P0110840

General Permit Category and Type: Not Applicable

Emissions Unit ID: P005

Company Equipment ID: Wet Cooling Tower

Superseded Permit Number: P0110840

General Permit Category and Type: Not Applicable

Group Name: P001, P002

Emissions Unit ID: P001

Company Equipment ID: CTG #1

Superseded Permit Number: P0110840

General Permit Category andType: Not Applicable

Emissions Unit ID: P002

Company Equipment ID: CTG #2

Superseded Permit Number: P0110840

General Permit Category andType: Not Applicable
Final Permit-to-Install

Oregon Clean Energy Center

Permit Number: P0117413

Facility ID: 0448020102

Effective Date:9/30/2014

Page 3 of 55

A. Standard Terms and Conditions
Final Permit-to-Install

Oregon Clean Energy Center

Permit Number: P0117413

Facility ID: 0448020102

Effective Date:9/30/2014

Page 4 of 55

1. Federally Enforceable Standard Terms and Conditions

a) All Standard Terms and Conditions are federally enforceable, with the exception of those listed 

below which are enforceable under State law only:

(1) Standard Term and Condition A.2.a), Severability Clause

(2) Standard Term and Condition A.3.c) through A. 3.e)General Requirements

(3) Standard Term and Condition A.6.c) and A. 6.d), Compliance Requirements

(4) Standard Term and Condition A.9., Reporting Requirements

(5) Standard Term and Condition A.10., Applicability

(6) Standard Term and Condition A.11.b) through A.11.e), Construction of New Source(s) 

and Authorization to Install

(7) Standard Term and Condition A.14., Public Disclosure

(8) Standard Term and Condition A.15., Additional Reporting Requirements When There 

Are No Deviations of Federally Enforceable Emission Limitations, Operational 

Restrictions, or Control Device Operating Parameter Limitations

(9) Standard Term and Condition A.16., Fees

(10) Standard Term and Condition A.17., Permit Transfers

2. Severability Clause

a) A determination that any term or condition of this permit is invalid shall not invalidate the force or 

effect of any other term or condition thereof, except to the extent that any other term or condition 

depends in whole or in part for its operation or implementation upon the term or condition 

declared invalid.

b) All terms and conditions designated in parts B and C of this permit are federally enforceable as 

a practical matter, if they are required under the Act, or any of its applicable requirements, 

including relevant provisions designed to limit the potential to emit of a source, are enforceable 

by the Administrator of the U.S. EPA and the State and by citizens (to the extent allowed by 

section 304 of the Act) under the Act. Terms and conditions in parts B and C of this permit shall 

not be federally enforceable and shall be enforceable under State law only, only if specifically 

identified in this permit as such.

3. General Requirements

a) Any noncompliance with the federally enforceable terms and conditions of this permit 

constitutes a violation of the Act, and is grounds for enforcement action or for permit revocation, 

revocation and re-issuance, or modification.
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Permit Number: P0117413

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b) It shall not be a defense for the permittee in an enforcement action that it would have been 

necessary to halt or reduce the permitted activity in order to maintain compliance with the 

federally enforceable terms and conditions of this permit.

c) This permit may be modified, revoked, or revoked and reissued, for cause. The filing of a 

request by the permittee for a permit modification, revocation and reissuance, or revocation, or 

of a notification of planned changes or anticipated noncompliance does not stay any term and 

condition of this permit.

d) This permit does not convey any property rights of any sort, or any exclusive privilege.

e) The permittee shall furnish to the Director of the Ohio EPA, or an authorized representative of 

the Director, upon receipt of a written request and within a reasonable time, any information that 

may be requested to determine whether cause exists for modifying or revoking this permit or to 

determine compliance with this permit. Upon request, the permittee shall also furnish to the 

Director or an authorized representative of the Director, copies of records required to be kept by 

this permit. For information claimed to be confidential in the submittal to the Director, if the 

Administrator of the U.S. EPA requests such information, the permittee may furnish such 

records directly to the Administrator along with a claim of confidentiality.

4. Monitoring and Related Record Keeping and Reporting Requirements

a) Except as may otherwise be provided in the terms and conditions for a specific emissions unit, 

the permittee shall maintain records that include the following, where applicable, for any 

required monitoring under this permit:

(1) The date, place (as defined in the permit), and time of sampling or measurements.

(2) The date(s) analyses were performed.

(3) The company or entity that performed the analyses.

(4) The analytical techniques or methods used.

(5) The results of such analyses.

(6) The operating conditions existing at the time of sampling or measurement. 

b) Each record of any monitoring data, testing data, and support information required pursuant to 

this permit shall be retained for a period of five years from the date the record was created. 

Support information shall include, but not be limited to all calibration and maintenance records 

and all original strip-chart recordings for continuous monitoring instrumentation, and copies of all 

reports required by this permit. Such records may be maintained in computerized form.

c) Except as may otherwise be provided in the terms and conditions for a specific emissions unit, 

the permittee shall submit required reports in the following manner:

(1) Reports of any required monitoring and/or recordkeeping of federally enforceable 

information shall be submitted to the Toledo Department of Environmental Services.
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Permit Number: P0117413

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(2) Quarterly written reports of (i) any deviations from federally enforceable 

emissionlimitations, operationalrestrictions, 

andcontroldeviceoperatingparameterlimitations, excluding deviations resulting from 

malfunctions reported in accordance with OAC rule 3745-15-06, that have been detected 

by the testing, monitoring and recordkeeping requirements specified in this permit, (ii) 

the probable cause of such deviations, and (iii) any corrective actions or preventive 

measures taken, shall be made to the Toledo Department of Environmental Services. 

The written reports shall be submitted (i.e., postmarked) quarterly, by January 31, April 

30, July 31, and October 31 of each year and shall cover the previous calendar quarters. 

See A.15. below if no deviations occurred during the quarter.

(3) Written reports, which identify any deviations from the federally enforceable monitoring, 

recordkeeping, andreportingrequirements contained in this permit shall be submitted to 

the Toledo Department of Environmental Services every six months, by January 31 and 

July 31 of each year for the previous six calendar months. If no deviations occurred 

during a six-month period, the permittee shall submit a semi-annual report, which states 

that no deviations occurred during that period.

(4) This permit is for an emissions unit located at a Title V facility. Each written report shall 

be signed by a responsible official certifying that, based on information and belief formed 

after reasonable inquiry, the statements and information in the report are true, accurate, 

and complete.

d) The permittee shall report actual emissions pursuant to OAC Chapter 3745-78 for the purpose 

of collecting Air Pollution Control Fees.

5. Scheduled Maintenance/Malfunction Reporting

Any scheduled maintenance of air pollution control equipment shall be performed in accordance with 

paragraph (A) of OAC rule 3745-15-06. The malfunction, i.e., upset, of any emissions units or any 

associated air pollution control system(s) shall be reported to theToledo Department of Environmental 

Servicesin accordance with paragraph (B) of OAC rule 3745-15-06. (The definition of an upset 

condition shall be the same as that used in OAC rule 3745-15-06(B)(1) for a malfunction.) The verbal 

and written reports shall be submitted pursuant to OAC rule 3745-15-06.

Except as provided in that rule, any scheduled maintenance or malfunction necessitating the shutdown 

or bypassing of any air pollution control system(s) shall be accompanied by the shutdown of the 

emission unit(s) that is (are) served by such control system(s).

6. Compliance Requirements

a) All applications, notifications or reports required by terms and conditions in this permit to be 

submitted or "reported in writing" are to be submitted to Ohio EPA through the Ohio EPA's 

eBusiness Center: Air Services web service ("Air Services"). Ohio EPA will accept hard copy 

submittals on an as-needed basis if the permittee cannot submit the required documents 

through the Ohio EPA eBusiness Center. In the event of an alternative hard copy submission in 

lieu of the eBusiness Center, the post-marked date or the date the document is delivered in 

person will be recognized as the date submitted. Electronic submission of applications, 

notifications or reports required to be submitted to Ohio EPA fulfills the requirement to submit 

the required information to the Director, the appropriate Ohio EPA District Office or contracted 
Final Permit-to-Install

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Permit Number: P0117413

Facility ID: 0448020102

Effective Date:9/30/2014

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local air agency, and/or any other individual or organization specifically identified as an 

additional recipient identified in this permit unless otherwise specified. Consistent with OAC rule 

3745-15-03, the electronic signature date shall constitute the date that the required application, 

notification or report is considered to be "submitted". Any document requiring signature may be 

represented by entry of the personal identification number (PIN) by responsible official as part of 

the electronic submission process or by the scanned attestation document signed by the 

Authorized Representative that is attached to the electronically submitted written report.

Any document (including reports) required to be submitted and required by a federally 

applicable requirement in this permit shall include a certification by a Responsible Official that, 

based on information and belief formed after reasonable inquiry, the statements in the 

document are true, accurate, and complete.

b) Upon presentation of credentials and other documents as may be required by law, the permittee 

shall allow the Director of the Ohio EPA or an authorized representative of the Director to:

(1) At reasonable times, enter upon the permittee's premises where a source is located or 

the emissions-related activity is conducted, or where records must be kept under the 

conditions of this permit.

(2) Have access to and copy, at reasonable times, any records that must be kept under the 

conditions of this permit, subject to the protection from disclosure to the public of 

confidential information consistent with ORC section 3704.08.

(3) Inspect at reasonable times any facilities, equipment (including monitoring and air 

pollution control equipment), practices, or operations regulated or required under this 

permit.

(4) As authorized by the Act, sample or monitor at reasonable times substances or 

parameters for the purpose of assuring compliance with the permit and applicable 

requirements.

c) The permittee shall submit progress reports to the Toledo Department of Environmental 

Services concerning any schedule of compliance for meeting an applicable requirement. 

Progress reports shall be submitted semiannually or more frequently if specified in the 

applicable requirement or by the Director of the Ohio EPA. Progress reports shall contain the 

following:

(1) Dates for achieving the activities, milestones, or compliance required in any schedule of 

compliance, and dates when such activities, milestones, or compliance were achieved.

(2) An explanation of why any dates in any schedule of compliance were not or will not be 

met, and any preventive or corrective measures adopted.

7. Best Available Technology

As specified in OAC Rule 3745-31-05, new sources that must employ Best Available Technology (BAT)

shall comply with the Applicable Emission Limitations/Control Measures identified as BAT for each 

subject emissions unit.
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Permit Number: P0117413

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8. Air Pollution Nuisance

The air contaminants emitted by the emissions units covered by this permit shall not cause a public 

nuisance, in violation of OAC rule 3745-15-07.

9. Reporting Requirements

The permittee shall submit required reports in the following manner:

a) Reports of any required monitoring and/or recordkeeping of state-only enforceable information 

shall be submitted to the Toledo Department of Environmental Services.

b) Except as otherwise may be provided in the terms and conditions for a specific emissions unit, 

quarterly written reports of (a) any deviations (excursions) from state-only required emission 

limitations, operational restrictions, and control device operating parameter limitations that have 

been detected by the testing, monitoring, and recordkeeping requirements specified in this 

permit, (b) the probable cause of such deviations, and (c) any corrective actions or preventive 

measures which have been or will be taken, shall be submitted to the Toledo Department of 

Environmental Services. If no deviations occurred during a calendar quarter, the permittee shall 

submit a quarterly report, which states that no deviations occurred during that quarter. The 

reports shall be submitted quarterly, by January 31, April 30, July 31, and October 31 of each 

year and shall cover the previous calendar quarters. (These quarterly reports shall exclude 

deviations resulting from malfunctions reported in accordance with OAC rule 3745-15-06.)

10. Applicability

This Permit-to-Install is applicable only to the emissions unit(s) identified in the Permit-to-Install. 

Separate application must be made to the Director for the installation or modification of any other 

emissions unit(s)not exempt from the requirement to obtain a Permit-to-Install.

11. Construction of New Sources(s) and Authorization to Install

a) This permit does not constitute an assurance that the proposed source will operate in 

compliance with all Ohio laws and regulations. This permit does not constitute expressed or 

implied assurance that the proposed facility has been constructed in accordance with the 

application and terms and conditions of this permit. The action of beginning and/or completing 

construction prior to obtaining the Director's approval constitutes a violation of OAC rule 3745-

31-02. Furthermore, issuance of this permit does not constitute an assurance that the proposed 

source will operate in compliance with all Ohio laws and regulations. Issuance of this permit is 

not to be construed as a waiver of any rights that the Ohio Environmental Protection Agency (or 

other persons) may have against the applicant for starting construction prior to the effective date 

of the permit. Additional facilities shall be installed upon orders of the Ohio Environmental 

Protection Agency if the proposed facilities cannot meet the requirements of this permit or 

cannot meet applicable standards.

b) If applicable, authorization to install any new emissions unit included in this permit shall 

terminate within eighteen months of the effective date of the permit if the owner or operator has 

not undertaken a continuing program of installation or has not entered into a binding contractual 

obligation to undertake and complete within a reasonable time a continuing program of 

installation. This deadline may be extended by up to 12 months if application is made to the 
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Permit Number: P0117413

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Director within a reasonable time before the termination date and the permittee shows good 

cause for any such extension.

c) The permittee may notify Ohio EPA of any emissions unit that is permanently shut down (i.e., 

the emissions unit has been physically removed from service or has been altered in such a way 

that it can no longer operate without a subsequent "modification" or "installation" as defined in 

OAC Chapter 3745-31) by submitting a certification from the authorized official that identifies the 

date on which the emissions unit was permanently shut down. Authorization to operate the 

affected emissions unit shall cease upon the date certified by the authorized official that the 

emissions unit was permanently shut down. At a minimum, notification of permanent shut down 

shall be made or confirmed by marking the affected emissions unit(s) as "permanently shut 

down" in "Air Services" along with the date the emissions unit(s) was permanently removed 

and/or disabled. Submitting the facility profile update electronically will constitute notifying the 

Director of the permanent shutdown of the affected emissions unit(s).

d) The provisions of this permit shall cease to be enforceable for each affected emissions unit after 

the date on which an emissions unit is permanently shut down (i.e., emissions unit has been 

physically removed from service or has been altered in such a way that it can no longer operate 

without a subsequent "modification" or "installation" as defined in OAC Chapter 3745-31). All 

records relating to any permanently shutdown emissions unit, generated while the emissions 

unit was in operation, must be maintained in accordance with law. All reports required by this 

permit must be submitted for any period an affected emissions unit operated prior to permanent 

shut down. At a minimum, the permit requirements must be evaluated as part of the reporting 

requirements identified in this permit covering the last period the emissions unit operated.

Unless otherwise exempted,no emissions unit certified by the responsible official as being 

permanently shut down may resume operation without first applying for and obtaining a permit 

pursuant to OAC Chapter 3745-31 and OAC Chapter 3745-77 if the restarted operation is 

subject to one or more applicable requirements.

e) The permittee shall comply with any residual requirements related to this permit, such as the 

requirement to submit a deviation report, air fee emission report, or other any reporting required 

by this permit for the period the operating provisions of this permit were enforceable, or as 

required by regulation or law. All reports shall be submitted in a form and manner prescribed by 

the Director. All records relating to this permit must be maintained in accordance with law.

12. Permit-To-Operate Application

The permittee is required to apply for a Title V permit pursuant to OAC Chapter 3745-77. The 

permittee shall submit a complete Title V permit application or a complete Title V permit modification 

application within twelve (12) months after commencing operation of the emissions units covered by 

this permit. However, if operation of the proposed new or modified source(s) as authorized by this 

permit would be prohibited by the terms and conditions of an existing Title V permit, a Title V permit 

modification of such new or modified source(s) pursuant to OAC rule 3745-77-04(D) and OAC rule 

3745-77-08(C)(3)(d)must be obtained beforeoperating the source in a manner that would violate the 

existing Title V permit requirements.
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Permit Number: P0117413

Facility ID: 0448020102

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13. Construction Compliance Certification

The applicant shall identify the following dates in the "Air Services"facility profile for each new 

emissions unit identified in this permit.

a) Completion of initial installation date shall be enteredupon completion of construction and prior 

to start-up.

b) Commence operation after installation or latest modification date shall be entered within 90 days 

after commencing operation of the applicable emissions unit.

14. Public Disclosure

The facility is hereby notified that this permit, and all agency records concerning the operation of this 

permitted source, are subject to public disclosure in accordance with OAC rule 3745-49-03.

15. Additional Reporting Requirements When There Are No Deviations of Federally Enforceable

Emission Limitations, Operational Restrictions, or Control Device Operating Parameter 

Limitations

If no deviations occurred during a calendar quarter, the permittee shall submit a quarterly report, which 

states that no deviations occurred during that quarter. The reports shall be submitted quarterly by 

January 31, April 30, July 31, and October 31 of each year and shall cover the previous calendar 

quarters.

16. Fees

The permittee shall pay fees to the Director of the Ohio EPA in accordance with ORC section 3745.11 

and OAC Chapter 3745-78. The permittee shall pay all applicable permit-to-install fees within 30 days 

after the issuance of any permit-to-install. The permittee shall pay all applicable permit-to-operate fees 

within thirty days of the issuance of the invoice.

17. Permit Transfers

Any transferee of this permit shall assume the responsibilities of the prior permit holder. The new 

owner must update and submit the ownership information via the "Owner/Contact Change" functionality 

in "Air Services" once the transfer is legally completed.The change must be submitted through "Air 

Services" within thirty days of the ownership transfer date. 

18. Risk Management Plans

If the permittee is required to develop and register a risk management plan pursuant to section 112(r) of 

the Clean Air Act, as amended, 42 U.S.C. 7401 et seq. ("Act"), the permittee shall comply with the 

requirement to register such a plan.

19. Title IV Provisions

If the permittee is subject to the requirements of 40 CFR Part 72 concerning acid rain, the permittee 

shall ensure that any affected emissions unit complies with those requirements. Emissions exceeding 

any allowances that are lawfully held under Title IV of the Act, or any regulations adopted thereunder, 

are prohibited.
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Permit Number: P0117413

Facility ID: 0448020102

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B. Facility-Wide Terms and Conditions
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Permit Number: P0117413

Facility ID: 0448020102

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1. All the following facility-wide terms and conditions are federally enforceable with the exception of those 

listed below which are enforceable under state law only:

a) None.

2. The permittee shall ensure that any emissions unit(s) subject to the Clean Air Interstate Rule (CAIR) 

complies/comply with the requirements of the Ohio Administrative Code (OAC) Chapter 3745-109, 

which includes submitting timely permit applications.

3. The following emissions unit contained in this permit is subject to 40 CFR Part 60 Subpart A and Dc:

B001. The complete NSPS requirements, including the NSPS General Provisions may be accessed 

via the internet from the electronic Code of Federal Regulations (e-CFR) website www.ecfr.gov or by 

contacting the appropriate Ohio EPA district or local air agency.

4. The following emissions unit contained in this permit is subject to 40 CFR Part 60 Subpart A and KKKK: 

P001 and P002. The complete NSPS requirements, including the NSPS General Provisions may be 

accessed via the internet from the electronic Code of Federal Regulations (e-CFR) website 

www.ecfr.gov or by contacting the appropriate Ohio EPA district or local air agency.
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C. Emissions Unit Terms and Conditions
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Permit Number: P0117413

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1. B001, Auxiliary Boiler

Operations, Property and/or Equipment Description: 

99 mmBtu/hr natural gas fired boiler with low-NOx burners and flue gas re-circulation

a) The following emissions unit terms and conditions are federally enforceable with the exception 

of those listed below which are enforceable under state law only.

(1) None.

b) Applicable Emissions Limitations and/or Control Requirements

(1) The specific operation(s), property, and/or equipment that constitute each emissions unit 

along with the applicable rules and/or requirements and with the applicable emissions 

limitations and/or control measures are identified below. Emissions from each unit shall 

not exceed the listed limitations, and the listed control measures shall be specified in 

narrative form following the table.

Applicable Rules/Requirements Applicable Emissions Limitations/Control 

Measures

a. OAC rule 3745-31-05(A)(3), as 

effective 11/30/2001

Sulfur dioxide (SO2) emissions shall not 

exceed 1.5E-03 pound per million Btu 

(lb/mmBtu) of heat input.

see b)(2)a. and b)(2)b.

b. OAC rule 3745-31-05(A)(3)(a)(ii), as 

effective 12/01/2006

see b)(2)c.

c. OAC rule 3745-31-10 through 20 Carbon monoxide (CO) emissions shall 

not exceed 0.055 pound per million Btu 

(lb/mmBtu) of heat input, 5.45 pounds per 

hour (lbs/hr), and 5.45 tons per rolling, 

12-month period.

Nitrogen Oxides (NOx) emissions shall 

not exceed 0.020 lb/mmBtu of heat input, 

1.98 lbs/hr, and 1.98 tons per rolling, 12-

month period.

Particulate matter emissions less than 10 

microns in diameter (PM10) and 

particulate matter less than 2.5 microns in 

diameter (PM2.5) shall not exceed 0.008 

lb/mmBtu of heat input, 0.79 lb/hr, and 

0.79 ton per rolling, 12-month period.

Volatile organic compound (VOC) 

emissions shall not exceed 0.006 

lb/mmBtu of heat input, 0.59 lb/hr and 

0.59 ton per rolling, 12-month period.
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Permit Number: P0117413

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Applicable Rules/Requirements Applicable Emissions Limitations/Control 

Measures

Sulfuric acid mist (H2SO4) emissions shall 

not exceed 1.1E-04 lb/mmBtu, 0.011 

lb/hr, and 0.011 ton per rolling, 12-month 

period.

Carbon dioxide equivalent (CO2e) 

emissions shall not exceed 11,671 tons 

per rolling, 12-month period.

Visible particulate emissions from the 

stack serving this emissions unit shall not 

exceed 10 percent opacity as a 6-minute 

average.

see b)(2)d., b)(2)e.

d. OAC rule 3745-31-05(D) SO2 emissions shall not exceed 0.15 ton 

per rolling, 12-month period.

see b)(2)k.

e. OAC rule 3745-17-07(A) see b)(2)f.

f. OAC rule 3745-17-10(B)(1) see b)(2)f.

g. OAC rule 3745-110-03(J)(16) exemption - see b)(2)l.

h. 40 CFR Part 60, Subpart A

(40 CFR 60.1 – 40 CFR 60.19)

see b)(2)g.

i. 40 CFR Part 60, Subpart Dc

(40 CFR 60.40c – 40 CFR 60.48c)

see b)(2)h. and b)(2)i.

j. 40 CFR Part 63, Subpart JJJJJJ

(40 CFR 63.11193 – 63.11236)

see b)(2)j.

(2) Additional Terms and Conditions

a. Compliance with the requirements of this rule for CO, NOx, PM10/PM2.5, and VOC 

emissions includes compliance with the requirements of OAC rule 3745-31-10 

through 20.

b. The permittee has satisfied the Best Available Technology (BAT) requirements 

pursuant to Ohio Administrative Code (OAC) paragraph 3745-31-05(A)(3), as 

effective November 30, 2001, in this permit. On December 1, 2006, paragraph 

(A)(3) of OAC rule 3745-31-05 was revised to conform to the Ohio Revised Code 

(ORC) changes effective August 3, 2006 (Senate Bill 265 changes), such that 

BAT is no longer required by State regulations for National Ambient Air Quality 

Standards (NAAQS) pollutant(s) less than ten tons per year. However, that rule 

revision has not yet been approved by U.S. EPA as a revision to Ohio’s State 

Implementation Plan (SIP). Therefore, until the SIP revision occurs and the U.S. 

EPA approves the revisions to OAC rule 3745-31-05, the requirement to satisfy 
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Permit Number: P0117413

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BAT still exists as part of the federally-approved SIP for Ohio. Once U.S. EPA 

approves the December 1, 2006 version of OAC rule 3745-31-05, then these 

emission limitations/control measures no longer apply.

c. This rule paragraph applies once U.S. EPA approves the December 1, 2006 

version of OAC rule 3745-31-05 as part of the State Implementation Plan.

The Best Available Technology (BAT) requirements under OAC rule 3745-31-

05(A)(3) do not apply to the CO, NOx, PM10/PM2.5, SO2, and VOC emissions from 

this air contaminant source since the uncontrolled potential to emit for CO, NOx, 

PM10/PM2.5, SO2, and VOC is less than 10 tons per year .

d. All particulate emissions are assumed to be less than 2.5 microns in diameter. 

The PM10/PM2.5 emissions limitations include both filterable and condensable 

particulate emissions.

e. The lb/mmBtu and lb/hr, emission limitations are based on the emissions unit's 

potentials to emit. Therefore, no monitoring, record keeping, and reporting 

requirements are necessary to ensure ongoing compliance with these emission 

limitations.

f. The emission limitation specified by this rule is less stringent than the limitation 

established by OAC rule 3745-31-10 through 20.

g. 40 CFR Part 60 subpart A provides applicability provisions, definitions, and other 

general provisions that are pertinent to emissions units affected by 40 CFR Part 

60.

h. This rule does not establish emission limitations for natural gas-fired boilers, but 

does require recordkeeping of gas usage per 40 CFR 60.48c(g).

i. This emissions unit is subject to the applicable provisions of Subpart Dc of the 

New Source Performance Standards (NSPS) as promulgated by the United 

States Environmental Protection Agency, 40 CFR Part 60. The application and 

enforcement of these standards are delegated to the Ohio EPA. The 

requirements of 40 CFR Part 60 are also federally enforceable.

j. This emissions unit is exempt from the requirements of this rule per 40 CFR 

63.11195(e) due tocombusting only natural gas.

k. The maximum annual operating hours for this emissions unit shall not exceed 

2,000 hours per rolling, 12-monthperiod.

To ensure enforceability during the first 12 calendar months of operation or the 

first 12 calendar months following the issuance of this permit, the permittee shall 

not exceed the operating hours levels specified in the following table:
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Permit Number: P0117413

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Maximum Allowable

Month(s) Cumulative Operating Hours

1 720

1-2 1,440

1-3 2,000

1-4 2,000

1-5 2,000

1-6 2,000

1-7 2,000

1-8 2,000

1-9 2,000

1-10 2,000

1-11 2,000

1-12 2,000

After the first 12 calendar months of operation or the first 12 calendar months 

following the issuance of this permit, compliance with the annual operating hours 

limitation shall be based upon a rolling, 12-month summation of the operating 

hours.

l. The permittee is exempt from the requirements of OAC rule 3745-110-03(A) 

through (F), since this permit restricts NOx emissions from this emissions unit to 

less than 25 tons per year.

c) Operational Restrictions

(1) The permittee shall burn only natural gas in this emissions unit.

d) Monitoring and/or Recordkeeping Requirements

(1) For each day during which the permittee burns a fuel other than natural gas, the 

permittee shall maintain a record of the type and quantity of fuel burned in this emissions 

unit.

(2) The permittee shall maintain monthly records of the following information:

a. the operating hours for each month; and

b. beginning after the first 12 calendar months of operation or the first 12 calendar 

months following the issuance of this permit, the rolling, 12-month summation of 

the operating hours.

Also, during the first 12 calendar months of operation or the first 12 calendar months 

following the issuance of this permit, the permittee shall record the cumulative operating 

hours for each calendar month.

(3) See 40 CFR Part 60, Subpart Dc (40 CFR 60.40c-48c).
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e) Reporting Requirements

(1) The permittee shall submit deviation (excursion) reports that identify each day when a 

fuel other than natural gas was burned in this emissions unit. Each report shall be 

submitted within 30 days after the deviation occurs.

(2) Pursuant to the 40 CFR Part 60.7 and 60.48c(a), the permittee is hereby advised of the 

requirement to report the following at the appropriate times:

a. construction date (no later than 30 days after such date);

b. anticipated start-up date (not more than 60 days or less than 30 days prior to 

such date);

c. actual start-up date (within 15 days after such date); and

d. the design heat input capacity of the affected facility and identification of fuels to 

be combusted in the affected facility.

(3) The permittee shall submit quarterly deviation (excursion) reports that identify the 

following:

all exceedances of the rolling, 12-month limitation on the hours of operation for this 

emissions unit; and for the first 12 calendar months of operation or the first 12 calendar 

months following the issuance of this permit, all exceedances of the maximum allowable 

cumulative hours of operation;

The quarterly deviation (excursion) reports shall be submitted in accordance with the 

reporting requirements of the Standard Terms and Conditions of this permit.

(4) See 40 CFR Part 60, Subpart Dc (40 CFR 60.40c-48c).

(5) Unless other arrangements have been approved by the Director, all notifications and 

reports shall be submitted through the Ohio EPA's eBusiness Center: Air Services online 

web portal.

f) Testing Requirements

(1) Compliance with the Emissions Limitations and/or Control Requirements specified in 

section b) of these terms and conditions shall be determined in accordance with the 

following methods:

a. Emission Limitation:

CO emissions shall not exceed 0.055 lb/mmBtu of heat input, 5.45 lbs/hr, and 

5.45 tons per rolling, 12-month period.

Applicable Compliance Method:

The lb/mmBtu emission limitation is based on manufacturer’s data. The hourly 

emission limitation was developed by multiplying the maximum heat input (99 
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Effective Date:9/30/2014

Page 19 of 55

mmBtu/hr) by the CO emission factor supplied by the manufacturer (0.055 

lb/mmBtu) to determine the hourly emissions.

The annual emission limitation was developed by multiplying the hourly emission 

limitation (5.45 lbs/hr) by the maximum annual operating hours (2,000 hrs/yr) and 

dividing by 2,000 pounds per ton. Therefore, compliance with the annual 

limitation shall be demonstrated if compliance with the hourly limitation is shown.

b. Emission Limitation:

NOx emissions shall not exceed 0.020 lb/mmBtu of heat input, 1.98 lbs/hr, and 

1.98 tons per rolling, 12-month period.

Applicable Compliance Method:

The lb/mmBtu limitation is based on manufacturer’s data. The hourly emission 

limitation was developed by multiplying the maximum heat input (99 mmBtu/hr) 

by the NOx emission factor supplied by the manufacturer (0.020 lb/mmBtu) to 

determine the hourly emissions.

The annual emission limitation was developed by multiplying the hourly emission 

limitation (1.98 lbs/hr) by the maximum annual operating hours (2,000 hrs/yr) and 

dividing by 2,000 pounds per ton. Therefore, compliance with the annual 

limitation shall be demonstrated if compliance with the hourly limitation is shown.

c. Emission Limitation:

PM10 and PM2.5 shall not exceed 0.008 lb/mmBtu of heat input, 0.79 lb/hr, and 

0.79 ton per rolling, 12-month period.

Applicable Compliance Method:

The lb/mmBtu limitation is based on manufacturer’s data. The hourly emission 

limitation was developed by multiplying the maximum heat input (99 mmBtu/hr) 

by the PM10/PM2.5 emission factor supplied by the manufacturer (0.008 lb/mmBtu) 

to determine the hourly emissions. 

If required, the permittee shall demonstrate compliance with the lb/mmBtu and 

hourly emission limitation using Methods 201 or 201A and 202 of 40 CFR Part 

51, Appendix M. Alternative U.S. EPA approved test methods may be used with 

prior approval from the Ohio EPA.

The annual emission limitation was developed by multiplying the hourly emission 

limitation (0.79 lb/hr) by the maximum annual operating hours (2,000 hrs/yr) and 

dividing by 2,000 pounds per ton. Therefore, compliance with the annual 

limitation shall be demonstrated if compliance with the hourly limitation is shown.

d. Emission Limitation:

SO2 emissions shall not exceed 1.5E-03 lb/mmBtu of heat input and 0.15 ton per 

rolling, 12-month period.
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Page 20 of 55

Applicable Compliance Method:

The lb/mmBtu limitation was established based on using pipeline quality natural 

gas having a maximum sulfur content of 0.5 grains per 100 cubic feet according 

to the following calculation. Multiply the maximum sulfur content of natural gas 

(0.5 grain S/100 scf) by the molecular weight of SO2 (64.07 lb SO2/lb-mole) 

divide by the molecular weight of sulfur (32.06 lb S/lb-mole) divide by (7,000 

grains/lb), divide by manufacturer’s gas specification (983 Btu/scf), and multiply 

by (106 Btu/mmBtu).

If required, the permittee shall demonstrate compliance with the lb/mmBtu and 

hourly emission limitation using Methods 1 thru 4 and 6C of 40 CFR Part 60, 

Appendix A. Alternative U.S. EPA approved test methods may be used with prior 

approval from the Ohio EPA.

The annual emission limitation was developed by multiplying the lb/mmBtu 

emission limitation (1.5E-03 lb/mmBtu) by the maximum heat input (99 

mmBtu/hr), multiplied by the maximum annual operating hours (2,000 hrs/yr) and 

dividing by 2,000 pounds per ton. Therefore, compliance with the annual

limitation shall be demonstrated if compliance with the hourly limitation is shown.

e. Emission Limitation:

VOC emissions shall not exceed 0.006 lb/mmBtu of heat input, 0.59 lb/hr, and 

0.59 ton per rolling, 12-month period.

Applicable Compliance Method:

The lb/mmBtu limitation is based on manufacturer’s data. The hourly emission 

limitation was developed by multiplying the maximum heat input (99 mmBtu/hr) 

by the VOC emission factor supplied by the manufacturer (0.006 lb/mmBtu) to 

determine the hourly emissions.

If required, the permittee shall demonstrate compliance with the lb/mmBtu and 

hourly emission limitation Methods 1 through 4 and 18, 25 or 25A, as 

appropriate, of 40 CFR Part 60, Appendix A. Use of Method 18, 25 or 25A is to 

be selected based on the results of pre-survey stack sampling and U.S. EPA 

guidance documents. Alternative U.S. EPA approved test methods may be used 

with prior approval from the Ohio EPA.

The annual emission limitation was developed by multiplying the hourly emission 

limitation (0.59 lb/hr) by the maximum annual operating hours (2,000 hrs/yr) and 

dividing by 2,000 pounds per ton. Therefore, compliance with the annual 

limitation shall be demonstrated if compliance with the hourly limitation is 

maintained.

f. Emission Limitation:

Sulfuric acid mist (H2SO4) emissions shall not exceed 1.1E-04 lb/mmBtu, 0.011 

lb/hr, and 0.011 ton per rolling, 12-month period.
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Applicable Compliance Method:

The lb/mmBtu emission limitation is based on the assumption that 5% of the SO2

emissions are converted to SO3 and then converted to H2SO4 when combined 

with water vapor by the following calculation.

1.5E-03 lb SO2/mmBtu(0.05)(98 lb H2SO4/lb-mole)(lb-mole/64 lb SO2) = 1.1E-04 

lb H2SO4/mmBtu

Multiply the lb H2SO4/mmBtu (1.1E-04 lb/mmBtu) by the maximum heat input (99 

mmBtu/hr) to determine the maximum hourly H2SO4 emissions (0.011 lb/hr), and 

multiply by the maximum annual hours of operation (2,000 hrs/yr) divided by 

2,000 lbs/ton to determine the annual H2SO4 emissions (0.011 ton/yr).

If required, the permittee shall demonstrate compliance with the lb/mmBtu and 

lb/hr emissions limitations using Methods 1 thru 4 and 8 of 40 CFR Part 60, 

Appendix A.

g. Emission Limitation:

Carbon dioxide equivalent (CO2e) emissions shall not exceed 11,671 tons per 

rolling, 12-month period.

Applicable Compliance Method:

This emissions limitation was established to reflect the potential to emit for this 

emissions unit by calculating the sum of the product of the maximum natural gas 

usage (0.104 mmscf/hr) multiplied by the AP-42 emission factor for CO2, N2O, 

and CH4 from Table 1.4-2 dated 7/98 (120,000 lb/mmscf, 0.64 lb/mmscf, and 2.3 

lb/mmscf, respectively), multiplied by the global warming potential for CO2, N2O, 

and CH4 (1, 298, and 25, respectively from Table A-1 to Subpart A of 40 CFR 

98). Multiply the calculated sum by the natural gas heating value used in the 

application for this emissions unit (950 Btu/scf), divide by the average heating 

value used for AP-42 emission factors in Table 1.-42 dated 7/98 (1,020 Btu/scf), 

multiply by the maximum annual hours of operation (2,000 hrs/yr) and divide by 

2,000 pounds per ton. 

99



h

  120,000



 (1) + (0.64



)

(298)

+ 2.3



 (25)  



1020 2,000

h

h

  



2,000

= 11,671





Since the CO2e emissions are estimated to consist of more than 99% CO2, 

compliance with this emission limitation will be assumed provided that the lb/scf 

CO2 emission rate does not exceed 120,000 lb/mmscf.
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Page 22 of 55

If required, the permittee shall conduct emissions testing using Methods 1, 2, 3A 

and 4 of 40 CFR Part 60, Appendix A to determine the lb/scf CO2 emission rate.

h. Emission Limitation:

Visible emissions shall not exceed 10% opacity as a 6-minute average, except as 

provided by rule.

Applicable Compliance Method:

If required, compliance with the stack visible particulate emissions limitation shall 

be determined through visible emissions observations performed in accordance 

with Method 9 of 40 CFR Part 60, Appendix A.

(2) The permittee shall conduct, or have conducted, emission testing for this emissions unit 

in accordance with the following requirements:

a. The emission testing shall be conducted within 60 days after achieving the 

maximum production rate at which the emissions unit will be operated, but not 

later than 180 days after initial startup of the emissions unit.

b. The emission testing shall be conducted to demonstrate compliance with the 

following emissions limitations:

i. CO emissions in lb/hr and lb/mmBtu; and

ii. NOx emissions in lb/hr and lb/mmBtu.

The emission testing shall also be conducted to determine the CO2 emission rate 

in lb/hr and lb/mmBtu.

c. The following test method(s) shall be employed to demonstrate compliance with 

the allowable mass emission rate(s):

for CO, Methods 1 thru 4 of 40 CFR Part 60, Appendix A; and

forNOx, Methods 1 thru 4 and 7E of 40 CFR Part 60, Appendix A.

Alternative U.S. EPA approved test methods may be used with prior approval 

from the Ohio EPA.

d. The test(s) shall be conducted under those representative conditions that 

challenge to the fullest extent possible a facility’s ability to meet the applicable 

emissions limits and/or control requirements, unless otherwise specified or 

approved by the appropriate Ohio EPA District Office or local air agency. 

Although this generally consists of operating the emissions unit at its maximum 

material input/production rates and results in the highest emission rate of the 

tested pollutant, there may be circumstances where a lower emissions loading is 

deemed the most challenging control scenario. Failure to test under these 
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conditions is justification for not accepting the test results as a demonstration of 

compliance.

e. Not later than 30 days prior to the proposed test date(s), the permittee shall 

submit an "Intent to Test" notification to the appropriate Ohio EPA District Office 

or local air agency. The "Intent to Test" notification shall describe in detail the 

proposed test methods and procedures, the emissions unit operating 

parameters, the time(s) and date(s) of the test(s), and the person(s) who will be 

conducting the test(s). Failure to submit such notification for review and approval 

prior to the test(s) may result in the Ohio EPA District Office's or local air 

agency's refusal to accept the results of the emission test(s).

f. Personnel from the appropriate Ohio EPA District Office or local air agency shall 

be permitted to witness the test(s), examine the testing equipment, and acquire 

data and information necessary to ensure that the operation of the emissions unit 

and the testing procedures provide a valid characterization of the emissions from 

the emissions unit and/or the performance of the control equipment.

g. A comprehensive written report on the results of the emissions test(s) shall be 

signed by the person or persons responsible for the tests and submitted to the 

appropriate Ohio EPA District Office or local air agency within 30 days following 

completion of the test(s). The permittee may request additional time for the 

submittal of the written report, where warranted, with prior approval from the 

appropriate Ohio EPA District Office or local air agency.

g) Miscellaneous Requirements

(1) None.
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2. P005, Wet Cooling Tower

Operations, Property and/or Equipment Description: 

11 cell mechanical draft wet cooling tower with high efficiency drift eliminator

a) The following emissions unit terms and conditions are federally enforceable with the exception 

of those listed below which are enforceable under state law only.

(1) None.

b) Applicable Emissions Limitations and/or Control Requirements

(1) The specific operation(s), property, and/or equipment that constitute each emissions unit 

along with the applicable rules and/or requirements and with the applicable emissions 

limitations and/or control measures are identified below. Emissions from each unit shall 

not exceed the listed limitations, and the listed control measures shall be specified in 

narrative form following the table.

Applicable Rules/Requirements Applicable Emissions Limitations/Control 

Measures

a. OAC rule 3745-31-05(A)(3), as 

effective 11/30/2001

see b)(2)a. and b.

b. OAC rule 3745-31-05(A)(3)(a)(ii), as 

effective 12/01/2006

see b)(2)c. 

c. OAC rules 3745-10 through 20

(Prevention of Significant 

Deterioration of Air Quality)

Particulate matter emissions less than 10 

microns in diameter (PM10) shall not 

exceed 1.03 pounds per hour and 4.5 

tons per rolling, 12-month period.

Particulate matter emissions less than 2.5 

microns in diameter (PM2.5) shall not 

exceed 3.4E-03 pound per hour and 

0.015 ton per rolling, 12-month period.

The permittee shall install a drift 

eliminator with a maximum drift rate of 

0.0005% on this emissions unit.

Visible particulate emissions shall not 

exceed 10% opacity as a 6-minute 

average. The presence of condensed 

water vapor shall not be deemed a 

violation for failure of stack emissions 

meeting this visible emission limitation.

see c)(1)

d. OAC rule 3745-17-07(A)(1) see b)(2)d.

e. OAC rule 3745-17-11(B) see b)(2)d.
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(2) Additional Terms and Conditions

a. The requirements of this rule include compliance with the requirements of OAC 

rule 3745-10 through 20.

b. The permittee has satisfied the Best Available Technology (BAT) requirements 

pursuant to Ohio Administrative Code (OAC) paragraph 3745-31-05(A)(3), as 

effective November 30, 2001, in this permit. On December 1, 2006, paragraph 

(A)(3) of OAC rule 3745-31-05 was revised to conform to the Ohio Revised Code 

(ORC) changes effective August 3, 2006 (Senate Bill 265 changes), such that 

BAT is no longer required by State regulations for National Ambient Air Quality 

Standards (NAAQS) pollutant(s) less than ten tons per year. However, that rule 

revision has not yet been approved by U.S. EPA as a revision to Ohio’s State 

Implementation Plan (SIP). Therefore, until the SIP revision occurs and the U.S. 

EPA approves the revisions to OAC rule 3745-31-05, the requirement to satisfy 

BAT still exists as part of the federally-approved SIP for Ohio. Once U.S. EPA 

approves the December 1, 2006 version of OAC rule 3745-31-05, then these 

emission limitations/control measures no longer apply.

c. This rule paragraph applies once U.S. EPA approves the December 1, 2006 

version of OAC rule 3745-31-05 as part of the State Implementation Plan.

The Best Available Technology (BAT) requirements under OAC rule 3745-31-

05(A)(3) do not apply to the PM10 and PM2.5 emissions from this air contaminant 

source since the calculated annual emission rate for PM10 and PM2.5 is less than 

10 tons per year taking into account the federally enforceable rule limit of 

0.0005% drift and a maximum TDS concentration of 2,030.5 mg/l under OAC rule 

3745-31-10 through 20.

d. The emission limitation specified by this rule is less stringent than the emission 

limitation established by OAC rule 3745-31-10 through 20.

c) Operational Restrictions

(1) The permittee shall maintain the total dissolved solids (TDS) concentration of the cooling 

water less than or equal to 2,030.5 milligrams per liter.

d) Monitoring and/or Recordkeeping Requirements

(1) The permittee shall properly install, operate, and maintain a conductivity meter or other 

equipment to continuously monitor and record the TDS concentration of the cooling 

tower water. The monitoring devices shall be installed, calibrated, operated, and 

maintained in accordance with the manufacturer’s recommendations, instructions, and 

operating manuals.

(2) Since the TDS data measured by the conductivity meter or other equipment is based on 

a correlation between conductivity and TDS, an exceedance measured by the 

conductivity meter or equivalent is not a violation of the TDS operational restriction, but 

rather serves as an indicator to initiate corrective action by the permittee to reduce the 

TDS concentration.
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e) Reporting Requirements

(1) The permittee shall submit quarterly deviation (excursion) reports that identify all hourly 

TDS readings in excess of 2030.5 mg/l. The reports shall identify corrective action taken 

to reduce the TDS concentration.

The quarterly deviation (excursion) reports shall be submitted in accordance with the 

reporting requirements of the Standard Terms and Conditions of this permit

(2) Prior to startup, the permittee shall submit written documentation provided by the 

vendor/manufacturer, of the maximum drift rate of 0.0005% for the drift eliminator and 

the premise, basis, and justification for the drift rate.

(3) Unless other arrangements have been approved by the Director, all notifications and 

reports shall be submitted through the Ohio EPA's eBusiness Center: Air Services online 

web portal.

f) Testing Requirements

(1) Compliance with the Emissions Limitations and/or Control Requirements specified in 

section b) of these terms and conditions shall be determined in accordance with the 

following methods:

a. Emission Limitation:

PM10 emissions shall not exceed 1.03 lbs/hr and 4.5 tons per rolling, 12-month 

period.

Applicable Compliance Method:

The lb/hr PM10 emission limitation is based on multiplying the maximum recirculating water flow rate (322,000 gal/min) by the maximum TDS concentration 

(2030.5/1E06) multiplied by the decimal fraction drift rate (0.000005) multiplied 

by the density of water (8.34 lbs/gal) multiplied by (60 min/hr) and multiplied by 

the decimal fraction of PM10 contained in the TDS (0.63). The permittee 

calculated the PM10 fraction using AWMA Abstract No. 216, Session No. AM-1b, 

Orlando, 2001.

The annual emission limitation is based on multiplying the hourly emission 

limitation (1.03 lbs/hr) by the maximum annual hours of operation (8,760 hrs/yr) 

and dividing by (2,000 lbs/ton) 

Compliance with the hourly and annual emissions limitation will be assumed 

provided that the TDS concentration recorded in d) remains below 2030.5 mg/l.

b. Emission Limitation:

PM2.5 emissions shall not exceed 3.4E-03 lb/hr and 0.015 ton/yr

The lb/hrPM2.5 emission limitation is based on multiplying the maximum recirculating water flow rate (322,000 gal/min) by the maximum TDS concentration 
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(2030.5/1E06) multiplied by the decimal fraction drift rate (0.000005) multiplied 

by the density of water (8.34 lbs/gal) multiplied by (60 min/hr) and multiplied by 

the decimal fraction of PM2.5 contained in the TDS (0.0021). The permittee 

calculated the PM2.5 fraction using AWMA Abstract No. 216, Session No. AM-1b, 

Orlando, 2001.

The annual emission limitation is based on multiplying the hourly emission 

limitation (3.4E-03 lb/hr) by the maximum annual hours of operation (8,760 

hrs/yr) and dividing by (2,000 lbs/ton) 

Compliance with the hourly and annual emissions limitation will be assumed 

provided that the TDS concentration recorded in d) remains below 2030.5 mg/l.

c. Emission Limitation:

The maximum drift rate shall not exceed 0.0005%.

Applicable Compliance Method:

Manufacturer's emissions data shall be used to demonstrate compliance with this 

limitation.

Within 90 days of startup, the permittee shall submit to the Toledo Division of 

Environmental Services written documentation provided by the 

vendor/manufacturer, of the maximum drift rate of 0.0005% for the drift eliminator 

and the premise, basis, and justification for the drift rate.

d. Emission Limitation:

The permittee shall maintain the TDS concentration of the cooling water less 

than or equal to 2,030.5 milligrams per liter.

Applicable Compliance Method:

The monitoring and recordkeeping requirements under d)(1) and d)(2) shall serve 

as demonstration of compliance.

If required, compliance shall be demonstrated using test procedures that conform 

to regulation 40 CFR 136, "Test Procedures for the Analysis of Pollutants". 

Alternative U.S. EPA approved test methods may be used with prior written 

approval from the Ohio EPA.

g) Miscellaneous Requirements

(1) None.
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3. Emissions Unit Group -P001, P002: P001,P002,

EU ID Operations, Property and/or Equipment Description

P001 Siemens SCC6-8000H combined cycle combustion turbine (2,936 mmBtu/hr heat input 

turbine and 300 mmBtu/hr heat input duct burner) with dry low NOx combustors, selective 

catalytic reduction (SCR), and catalytic oxidizer.

P002 Siemens SCC6-8000H combined cycle combustion turbine (2,936 mmBtu/hr heat input 

turbine and 300 mmBtu/hr heat input duct burner) with dry low NOx combustors, selective 

catalytic reduction (SCR), and catalytic oxidizer.

a) The following emissions unit terms and conditions are federally enforceable with the exception 

of those listed below which are enforceable under state law only:

(1) d)(12) through d)(15) and e)(6).

b) Applicable Emissions Limitations and/or Control Requirements

(1) The specific operation(s), property, and/or equipment that constitute each emissions unit 

along with the applicable rules and/or requirements and with the applicable emissions 

limitations and/or control measures are identified below. Emissions from each unit shall 

not exceed the listed limitations, and the listed control measures shall be specified in 

narrative form following the table.

Applicable Rules/Requirements Applicable Emissions Limitations/Control 

Measures

a. ORC 3704.03(T) Sulfur dioxide (SO2) emissions shall not 

exceed 1.5E-03 lb/mmBtu of heat input.

see b)(2)b.

b. OAC rule 3745-31-05(D) The combined SO2 emissions from P001 

and P002 shall not exceed 37.6 tons per 

rolling, 12-month period.

see b)(2)e. and f.

c. OAC rule 3745-31-10 through 20 Visible particulate emissions from the 

stack serving this emissions unit shall not 

exceed 10 percent opacity as a 6-minute 

average.

Carbon dioxide equivalent (CO2e) 

emissions shall not exceed 833 lb/MW-hr 

gross energy output and 371,029 lbs/hr.

see b)(2)c., b)(2)d., b)(2)g. through 

b)(2)j., and b)(2)r. through t.

d. OAC rule 3745-17-07(A) see b)(2)k.

e OAC rule 3745-17-11(B)(4) see b)(2)k.

f. OAC rule 3745-18-06(A) see b)(2)m.
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Applicable Rules/Requirements Applicable Emissions Limitations/Control 

Measures

g. OAC rule 3745-110-03(J)(19) Exemption from NOx RACT requirements

h. OAC rule 3745-114 see d)(12) through d)(15)

i. 40 CFR Part 60, Subpart A

(40 CFR 60.1 – 40 CFR 60.19)

see b)(2)n.

j. 40 CFR Part 60, Subpart KKKK

(40 CFR 60.4300 – 60.4420)

[In accordance with 40 CFR 

60.4305(a), this emissions unit is a 

stationary combustion turbine with a 

heat input at peak load greater than 

10 mmBtu/hr with a heat recovery 

steam generator/duct burners 

subject to the emissions 

limitations/control measures 

specified in this section.]

see b)(2)l. and b)(2)o.

k. 40 CFR Part 63, Subpart YYYY

(40 CFR 63.6080 – 63.6175)

see b)(2)p.

l. 40 CFR Part 63, Subpart JJJJJJ

(40 CFR 63.11193 – 63.11236)

see b)(2)q.

(2) Additional Terms and Conditions

a. All requirements specified for in this Section of the permit for Emissions Unit 

Group P001 and P002 apply to each combined cycle combustion turbine (P001 

and P002) unless a combined requirement is otherwise specified.

b. Compliance with the requirements of this rule for CO, NOx, PM10, PM2.5, and VOC 

includes compliance with the requirements of OAC rule 3745-31-10 through 20.

c. The emissions from this emissions unit shall be vented to the SCR and catalytic 

oxidation units at all times during which the emissions unit is in operation.

d. All particulate emissions are assumed to be less than 2.5 microns in diameter. 

The PM10/PM2.5 emissions limitations include both filterable and condensable 

particulate emissions.

e. The sulfur content of natural gas burned in this emissions unit shall not exceed 

0.5 grains per 100 standard cubic feet. 

f. The combined natural gas usage by emissions units P001 and P002 shall not 

exceed 48,484 mmscf per rolling, 12-month period. To ensure enforceability 

during the first 12 calendar months of operation or the first 12 calendar months 

following the issuance of this permit, the permittee shall not exceed the natural 

gas usage levels specified in the following table:
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Maximum Allowable Cumulative

Natural Gas Usage by 

P001 and P002 combined

(Million Standard Cubic Feet)

Month(s) mmscf

1 8,081

1-2 16,161

1-3 24,242

1-4 32,323

1-5 40,403

1-6 48,484

1-7 48,484

1-8 48,484

1-9 48,484

1-10 48,484

1-11 48,484

1-12 48,484

After the first 12 calendar months of operation or the first 12 calendar months 

following the issuance of this permit, compliance with the annual natural gas 

usage limitation shall be based upon a rolling, 12-month summation of the 

monthly natural gas usage.

g. The permittee shall comply with the following emissions limitations:

Allowable Emissions

Pollutant Operating 

Modea

Emission 

Rateb,e

Emission 

rate, 

lb/hrb

Emission rate, 

tons per rolling, 

12-month period

CO CT with DB 2.0c14.4 -

CT only 2.0c13.0 -
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Allowable Emissions

Pollutant Operating 

Modea

Emission 

Rateb,e

Emission 

rate, 

lb/hrb

Emission rate, 

tons per rolling, 

12-month period

All operating 

modes, including 

startup periods - - 91.3

NOx CT with DB 2.0c23.6 -

CT only 2.0c22.0 -

All operating 

modes, including 

startup periods 92.0

PM10/PM2.5 CT with DB 5.5E-03d15.1 -

CT only 5.4E-03d13.3 -

All operating 

modes, including 

startup periods - - 61.3

VOC CT With DB 1.9c5.9 -

CT only 1.0c3.9 -

All operating 

modes, including 

startup periods - - 38.5

H2SO4 CT with DB 7.0E-04d1.5 -

CT only 6.0E-04d1.6 -

All operating 

modes, including 

startup periods - - 6.6

CO2e All operating 

modes, including 

startup periods - - 1,477,071

a. CT = combustion turbine

 DB = duct burner

b. Limitation does not apply during periods of startup and shutdown.

c. Parts per million by volume dry (ppmvd) at 15% oxygen
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Allowable Emissions

Pollutant Operating 

Modea

Emission 

Rateb,e

Emission 

rate, 

lb/hrb

Emission rate, 

tons per rolling, 

12-month period

d. Pound per million Btu of heat input

e. Emissions limitations are based on an hourly average.

h. To ensure enforceability of the rolling, 12-month emissions limitations during the 

first 12 calendar months of operation or the first 12 calendar months following the 

issuance of this permit, the permittee shall not exceed the emission levels 

specified in the following table:

Maximum Allowable Cumulative Emissions

(Tons)

Month(s) CO NOx PM10/PM2.5 VOC H2SO4

1 15.2 15.3 10.2 6.4 1.10

1-2 30.4 30.7 20.4 12.8 2.19

1-3 45.6 46.0 30.7 19.2 3.29

1-4 60.8 61.3 40.9 25.7 4.3

1-5 76.1 76.7 51.1 32.1 5.48

1-6 91.3 92.0 61.3 38.5 6.57

1-7 91.3 92.0 61.3 38.5 6.57

1-8 91.3 92.0 61.3 38.5 6.57

1-9 91.3 92.0 61.3 38.5 6.57

1-10 91.3 92.0 61.3 38.5 6.57

1-11 91.3 92.0 61.3 38.5 6.57

1-12 91.3 92.0 61.3 38.5 6.57

After the first 12 calendar months of operation or the first 12 calendar months 

following the issuance of this permit, compliance with the annual emissions

limitations shall be based upon a rolling, 12-month summation of the monthly

emissions.
Final Permit-to-Install

Oregon Clean Energy Center

Permit Number: P0117413

Facility ID: 0448020102

Effective Date:9/30/2014

Page 33 of 55

i. The permittee shall comply with the following requirements during periods of 

startup and shutdown.

Emissions LimitationsDuring Startupand Shutdown 

(lbs/hr)

a

Cold 

Startup

Hot 

Startup

Warm 

Startup

Shutdown

CO 546 289 351 113

NOx 188 105 129 46

VOC 168 114 138 45

a Pound per hour emissions rates as presented are the maximum rates 

during any hour during the event from each unit.

“Cold Startup” is defined as a combustion turbine startup that occurs more than 

64 hours after a combustion turbine shutdown. The period of startup is defined 

as the lesser of the first 180 minutes of continuous fuel flow to the combustion 

turbine after fuel flow is initiated or the period of time from combustion turbine 

fuel flow initiation until the combustion turbine achieves ten consecutive CEM 

data points in compliance with the ppmvd emissions limitations for CO and NOx.

 “Hot Startup” is defined as a combustion turbine startup that occurs within 16 

hours of a combustion turbine shutdown. The period of hot startup is defined as 

the lesser of the first 82 minutes of continuous fuel flow to the combustion turbine 

after fuel flow is initiated or the period of time from combustion turbine fuel flow 

initiation until the combustion turbine achieves ten consecutive CEM data points 

in compliance with the ppmvd emissions limitations for CO and NOx.

“Warm Startup” is defined as a combustion turbine startup that occurs between 

16 hours of and 64 hours of a combustion turbine shutdown. The period of 

startup is defined as the lesser of the first 98 minutes of continuous fuel flow to 

the combustion turbine after fuel flow is initiated or the period of time from 

combustion turbine fuel flow initiation until the combustion turbine achieves ten 

consecutive CEM data points in compliance with the ppmvd emissions limitations 

for CO and NOx.

j. The design net plant base heat rate shall not exceed 7,227 Btu/kW-hr HHV (ISO 

conditions without duct firing).

k. The emission limitation specified by this rule is less stringent than the limitation 

established by OAC rule 3745-31-10 through 20.

l. The emission limitation specified by this rule is less stringent than the limitation 

established by ORC 3704.03(T).
Final Permit-to-Install

Oregon Clean Energy Center

Permit Number: P0117413

Facility ID: 0448020102

Effective Date:9/30/2014

Page 34 of 55

m. This emissions unit is exempt from the requirements of this rule, since only 

natural gas is burned.

n. 40 CFR Part 60 subpart A provides applicability provisions, definitions, and other 

general provisions that are pertinent to emissions units affected by 40 CFR Part 

60.

o. This emissions unit is subject to the applicable provisions of Subpart KKKK of the 

New Source Performance Standards (NSPS) as promulgated by the United 

States Environmental Protection Agency, 40 CFR Part 60. The application and 

enforcement of these standards are delegated to the Ohio EPA. The 

requirements of 40 CFR Part 60 are also federally enforceable.

p. This emissions unit is not subject to the requirements of 40 CFR Part 63, Subpart 

YYYY, since it is not located at a major source of HAP emissions.

q. The duct burner is exempt from the requirements of this rule per 40 CFR 

63.11195(e) due tocombusting only natural gas.

r. Each continuous NOx monitoring system shall be certified to meet the 

requirements of 40 CFR Part 60, Appendix B, Performance Specifications 2 and 

6. At least 45 days before commencing certification testing of the continuous 

NOx monitoring system(s), the permittee shall develop and maintain a written 

quality assurance/quality control plan designed to ensure continuous valid and 

representative readings of NOx emissions from the continuous monitor(s), in 

units of the applicable standard(s). Except as allowed below, the plan shall 

follow the requirements of 40 CFR Part 60, Appendix F and 40 CFR Part 75, 

Appendix B. The quality assurance/quality control plan and a logbook dedicated 

to the continuous monitoring system must be kept on site and available for 

inspection during regular office hours.

The plan shall include the requirement to conduct relative accuracy test audits for 

the continuous NOx monitoring system in accordance with the frequencies 

required pursuant to 40 CFR Part 60 and 40 CFR Part 75; or may follow relative 

accuracy test audit frequency requirements for monitoring systems subject to 40 

CFR 75, Appendix B, in lieu of frequencies required in 40 CFR Part 60. In either 

case, results shall be recorded and reported in units of the applicable standard(s) 

in accordance with 40 CFR Part 60.

The plan shall include the requirement to conduct quarterly cylinder gas audits or 

relative accuracy audits pursuant to 40 CFR Part 60, and linearity checks 

pursuant to 40 CFR Part 75; however, linearity checks completed pursuant to 40 

CFR Part 75, Appendix B, may be substituted for the quarterly cylinder gas or 

relative accuracy audits required per 40 CFR Part 60.

s. Each continuous carbon monoxide (CO) monitoring system shall be certified to 

meet the requirements of 40 CFR Part 60, Appendix B, Performance 

Specifications 4 or 4a and 6. At least 45 days before commencing certification 

testing of the continuous CO monitoring system(s), the permittee shall develop 

and maintain a written quality assurance/quality control plan designed to ensure 
Final Permit-to-Install

Oregon Clean Energy Center

Permit Number: P0117413

Facility ID: 0448020102

Effective Date:9/30/2014

Page 35 of 55

continuous valid and representative readings of CO emissions from the 

continuous monitor(s), in units of the applicable standard(s). The fuel flow 

monitor/meter shall be maintained as required in Part 75, Appendix D. Except as 

allowed below, the plan shall follow the requirements of 40 CFR Part 60, 

Appendix F. The quality assurance/quality control plan and a logbook dedicated 

to the continuous monitoring system must be kept on site and available for 

inspection during regular office hours.

The plan shall include the requirement to conduct relative accuracy test audits for 

the continuous CO monitoring system in accordance with the frequencies 

required for monitoring systems subject to 40 CFR 60, or may follow relative 

accuracy test audit frequency requirements for monitoring systems subject to 40 

CFR 75, Appendix B. In either case, results shall be recorded and reported in 

units of the applicable standard(s) in accordance with 40 CFR Part 60.

The plan shall include the requirement to conduct quarterly cylinder gas audits or 

relative accuracy audits as required in 40 CFR Part 60; however, the quarterly 

cylinder gas audit and relative accuracy audit frequency requirements may be 

adjusted to coincide with linearity checks completed for continuous emissions 

monitoring systems subject to 40 CFR Part 75, Appendix B requirements.

t. The continuous emission monitoring system consists of all the equipment used to 

acquire data to provide a record of emissions and includes the sample extraction 

and transport hardware, sample conditioning hardware, analyzers, and data 

recording/processing hardware and software.

c) Operational Restrictions

(1) The permittee shall only burn pipeline quality natural gas as fuel in this emissions unit.

(2) See 40 CFR Part 60, Subpart KKKK (40 CFR 60.4300 – 60.4420).

d) Monitoring and/or Recordkeeping Requirements

(1) For each day during which the permittee burns a fuel other than natural gas, the 

permittee shall maintain a record of the type and quantity of fuel burned in this emissions 

unit.

(2) For purposes of demonstrating compliance with the natural gas sulfur concentration 

restriction of 0.5 grain/scf, the permittee shall sample and analyze the natural gas 

burned in this emissions unit monthly to determine the sulfur content using the 

appropriate ASTM or Gas Processors Association standards. Fuel supplier data may be 

used to comply with this requirement, provided that it is demonstrated to be 

representative of the fuel received for burning at this emissions unit.

(3) The permittee may elect not to monitor the total sulfur content of the fuel combusted in 

the turbine as specified in d)(2), if the fuel is demonstrated not to exceed potential sulfur 

emissions of 1.5E-03 lb SO2/mmBtu. The permittee shall use one of the following 

sources of information to make the required demonstration:
Final Permit-to-Install

Oregon Clean Energy Center

Permit Number: P0117413

Facility ID: 0448020102

Effective Date:9/30/2014

Page 36 of 55

a. the fuel quality characteristics in a current, valid purchase contract, tariff sheet or 

transportation contract for the fuel, specifying that the maximum total sulfur 

content for natural gas is 0.5 grains of sulfur or less per 100 standard cubic feet, 

has potential sulfur emissions of less than less than 1.5E-03 lb SO2/mmBtu heat 

input;

b. representative fuel sampling data which show that the sulfur content of the fuel 

does not exceed 1.5E-03lb SO2/mmBtu heat input. At a minimum, the amount of 

fuel sampling data specified in section 2.3.1.4 or 2.3.2.4 of appendix D to part 75 

of this chapter is required; or

c. one of the custom sulfur monitoring schedules outlined in 40 CFR 60.4370(c) 

may be used to comply with the 1.5E-03 lb SO2/mmBtu standard.

(4) The permittee shall maintain monthly records of the following information:

a. the natural gas usage by P001 and P002 for each month;

b. the combined natural gas usage by P001 and P002 for each month; and

c. beginning after the first 12 calendar months of operation or the first 12 calendar 

months following the issuance of this permit, the rolling, 12-month summation of 

the combined natural gas usage by P001 and P002.

Also, during the first 12 calendar months of operation or the first 12 calendar months 

following the issuance of this permit, the permittee shall record the cumulative combined 

natural gas usage by P001 and P002 for each calendar month.

(5) The permittee shall maintain monthly records of the following information:

a. the CO, NOx, PM10/PM2.5, VOC, and H2SO4 emission rate for each month of 

operations; and

b. beginning after the first 12 calendar months of operation or the first 12 calendar 

months following the issuance of this permit, the rolling, 12-month summation of 

the CO, NOx, PM10/PM2.5, VOC, and H2SO4emissions.

Also, during the first 12 calendar months of operation or the first 12 calendar months 

following the issuance of this permit, the permittee shall record the cumulative CO, NOx, 

PM10/PM2.5, VOC, and H2SO4emissions for each calendar month.

(6) The permittee shall maintain monthly records of the following information for this 

emissions unit for purposes of calculating rolling, 12-month emissions: 

a. date, time, and duration of each cold, warm, hot startup and shutdown period;

b. the hours of operation of the combustion turbine;

c. the hours of operation of the duct burner;

d. the total duration of all cold startup periods in hours per rolling, 12-month period;
Final Permit-to-Install

Oregon Clean Energy Center

Permit Number: P0117413

Facility ID: 0448020102

Effective Date:9/30/2014

Page 37 of 55

e. the total duration of all hot startup periods in hours per rolling, 12-month period;

f. the total duration of all warm startup periods in hours per rolling, 12-month 

period;

g. the total duration of all shutdown periods in hours per rolling, 12-month period;

h. the total duration of steady-state operation without duct burner firing in hours per 

rolling, 12-month period;

i. the total duration of steady-state operation with duct burner firing in hours per 

rolling, 12-month period;

(7) Prior to the installation of the continuous NOx monitoring system, the permittee shall 

submit information detailing the proposed location of the sampling site in accordance 

with the siting requirements in 40 CFR Part 60, Appendix B, Performance Specification 

2. The Ohio EPA, Central Office shall approve the proposed sampling site and certify 

that the continuous NOx monitoring system meets the requirements of Performance 

Specifications 2 and 6; and the U.S. EPA shall certify that the continuous NOx

monitoring system meets the requirements under 40 CFR Part 75, which may be 

approved through the recommendation for certification by Ohio EPA to U.S. EPA. Once 

received, the letter(s)/document(s) of certification under Part 60 and certification or 

recommendation for certification under Part 75 shall be maintain on-site and made 

available to the Director (the appropriate Ohio EPA District Office or local air agency) 

upon request.

(8) The permittee shall install, operate, and maintain equipment to continuously monitor and 

record NOx emissions from this emissions unit in units of the applicable standard(s). 

The continuous monitoring and recording equipment shall comply with the requirements 

specified in 40 CFR Part 60 and 40 CFR Part 75.

The permittee shall maintain records of all data obtained by the continuous NOx

monitoring system including, but not limited to:

a. emissions of NOx in parts per million for each cycle time of the analyzer, with no 

resolution less than one data point per minute required;

b. emissions of NOx in pounds per hour and in units of the applicable standard(s) in 

the appropriate averaging period;

c. results of quarterly cylinder gas audits or linearity checks;

d. results of daily zero/span calibration checks and the magnitude of manual 

calibration adjustments;

e. results of required relative accuracy test audit(s), including results in units of the 

applicable standard(s);

f. hours of operation of the emissions unit, continuous NOx monitoring system, and 

control equipment;
Final Permit-to-Install

Oregon Clean Energy Center

Permit Number: P0117413

Facility ID: 0448020102

Effective Date:9/30/2014

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g. the date, time, and hours of operation of the emissions unit without the control 

equipment and/or the continuous NOx monitoring system;

h. malfunction of the control equipment and/or the continuous NOx monitoring 

system; as well as,

i. the reason (if known) and the corrective actions taken (if any) for each such 

event in (g) and (h).

All valid data points generated and recorded by the continuous emission monitoring and 

data acquisition and handling system shall be used in the calculation of the pollutant 

concentration and/or emission rate over the appropriate averaging period.

(9) Prior to the installation of the continuous carbon monoxide (CO) monitoring system, the 

permittee shall submit information detailing the proposed location of the sampling site in 

accordance with the siting requirements in 40 CFR Part 60, Appendix B, Performance 

Specification 4 or 4a (as appropriate). The Ohio EPA, Central Office shall approve the 

proposed sampling site and certify that the continuous CO monitoring system meets the 

requirements of Performance Specifications 4 or 4a and 6. Once received, the 

letter(s)/document(s) of certification shall be maintained on-site and shall be made 

available to the Director (the appropriate Ohio EPA District Office or local air agency) 

upon request.

(10) The permittee shall operate and maintain equipment to continuously monitor and record 

CO emissions from this emissions unit in units of the applicable standard(s). The 

continuous monitoring and recording equipment shall comply with the requirements 

specified in 40 CFR Parts 60.

The permittee shall maintain records of all data obtained by the continuous CO 

monitoring system including, but not limited to:

a. emissions of CO in parts per million for each cycle time of the analyzer, with no 

resolution less than one data point per minute required;

b. emissions of CO in pounds per hour and in units of the applicable standard(s) in 

the appropriate averaging period;

c. results of quarterly cylinder gas audits;

d. results of daily zero/span calibration checks and the magnitude of manual 

calibration adjustments;

e. results of required relative accuracy test audit(s), including results in units of the 

applicable standard(s);

f. hours of operation of the emissions unit, continuous CO monitoring system, and 

control equipment;

g. the date, time, and hours of operation of the emissions unit without the control 

equipment and/or the continuous CO monitoring system;
Final Permit-to-Install

Oregon Clean Energy Center

Permit Number: P0117413

Facility ID: 0448020102

Effective Date:9/30/2014

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h. the date, time, and hours of operation of the emissions unit during any 

malfunction of the control equipment and/or the continuous CO monitoring 

system; as well as,

i. the reason (if known) and the corrective actions taken (if any) for each such 

event in (g) and (h).

All valid data points generated and recorded by the continuous emission monitoring and 

data acquisition and handling system shall be used in the calculation of the pollutant 

concentration and/or emission rate over the appropriate averaging period.

(11) The permittee shall calculate and record the monthly CO2 emissions from P001 and 

P002 using data from the continuous flow monitor using the procedures set forth in 40 

CFR Part 75, Appendix G. From this data, the permittee shall calculate the CO2

emissions from P001 and P002 per rolling, 12-month period.

(12) The Permit to Install application for these emissions units, P001 and P002, was 

evaluated based on the actual materials and the design parameters of the emissions 

unit's(s’) exhaust system, as specified by the permittee. The “Toxic Air Contaminant 

Statute”, ORC 3704.03(F), was applied to this/these emissions unit(s) for each toxic air 

contaminant listed in OAC rule 3745-114-01, using data from the permit application; and 

modeling was performed for each toxic air contaminant(s) emitted at over one ton per 

year using an air dispersion model such as SCREEN3, AERMOD, or ISCST3, or other 

Ohio EPA approved model. The predicted 1-hour maximum ground-level concentration 

result(s) from the approved air dispersion model, was compared to the Maximum 

Acceptable Ground-Level Concentration (MAGLC), calculated as described in the Ohio 

EPA guidance document entitled “Review of New Sources of Air Toxic Emissions, 

Option A”, as follows:

a. the exposure limit, expressed as a time-weighted average concentration for a 

conventional 8-hour workday and a 40-hour workweek, for each toxic 

compound(s) emitted from the emissions unit(s), (as determined from the raw 

materials processed and/or coatings or other materials applied) has been 

documented from one of the following sources and in the following order of 

preference (TLV was and shall be used, if the chemical is listed):

i. threshold limit value (TLV) from the American Conference of 

Governmental Industrial Hygienists (ACGIH) “Threshold Limit Values for

Chemical Substances and Physical Agents Biological Exposure Indices”; 

or 

ii. STEL (short term exposure limit) or the ceiling value from the American 

Conference of Governmental Industrial Hygienists (ACGIH) “Threshold 

Limit Values for Chemical Substances and Physical Agents Biological 

Exposure Indices”; the STEL or ceiling value is multiplied by 0.737 to 

convert the 15-minute exposure limit to an equivalent 8-hour TLV.

b. The TLV is divided by ten to adjust the standard from the working population to 

the general public (TLV/10).
Final Permit-to-Install

Oregon Clean Energy Center

Permit Number: P0117413

Facility ID: 0448020102

Effective Date:9/30/2014

Page 40 of 55

c. This standard is/was then adjusted to account for the duration of the exposure or 

the operating hours of the emissions unit(s), i.e., “X = 24” hours per day and “Y = 

7” days per week, from that of 8 hours per day and 5 days per week. The 

resulting calculation was (and shall be) used to determine the Maximum 

Acceptable Ground-Level Concentration (MAGLC):

TLV/10 x 8/X x 5/Y = 4 TLV/XY = MAGLC

d. The following summarizes the results of dispersion modeling for the “worst case” 

toxic contaminant(s):

Toxic Contaminant: Formaldehyde

TLV (mg/m3): 0.272

Maximum Hourly Emission Rate (lbs/hr): 1.6 (Siemens Case #3)

Predicted 1-Hour Maximum Ground-Level Concentration (μg/m3): 0.151

MAGLC (μg/m3): 6.5

The permittee, has demonstrated that emissions of formaldehyde, from emissions unit(s) 

P001 and P002, is calculated to be less than eighty per cent of the maximum acceptable 

ground level concentration (MAGLC); any new raw material or processing agent shall 

not be applied without evaluating each component toxic air contaminant in accordance 

with the “Toxic Air Contaminant Statute”, ORC 3704.03(F).

(13) Prior to making any physical changes to or changes in the method of operation of the 

emissions unit(s), that could impact the parameters or values that were used in the 

predicted 1-hour maximum ground-level concentration, the permittee shall re-model the 

change(s) to demonstrate that the MAGLC has not been exceeded. Changes that can 

affect the parameters/values used in determining the 1-hour maximum ground-level 

concentration include, but are not limited to, the following:

a. changes in the composition of the materials used or the use of new materials, 

that would result in the emission of a new toxic air contaminant with a lower 

Threshold Limit Value (TLV) than the lowest TLV previously modeled;

b. changes in the composition of the materials, or use of new materials, that would 

result in an increase in emissions of any toxic air contaminant listed in OAC rule 

3745-114-01, that was modeled from the initial (or last) application; and

c. physical changes to the emissions unit(s) or its/their exhaust parameters (e.g., 

increased/ decreased exhaust flow, changes in stack height, changes in stack 

diameter, etc.).

If the permittee determines that the “Toxic Air Contaminant Statute” will be satisfied for

the above changes, the Ohio EPA will not consider the change(s) to be a "modification" 

under OAC rule 3745-31-01 solely due to a non-restrictive change to a parameter or 

process operation, where compliance with the “Toxic Air Contaminant Statute”, ORC 

3704.03(F), has been documented. If the change(s) meet(s) the definition of a 
Final Permit-to-Install

Oregon Clean Energy Center

Permit Number: P0117413

Facility ID: 0448020102

Effective Date:9/30/2014

Page 41 of 55

“modification”, the permittee shall apply for and obtain a final PTI prior to the change. 

The Director may consider any significant departure from the operations of the 

emissions unit, described in the permit application, as a modification that results in 

greater emissions than the emissions rate modeled to determine the ground level 

concentration; and he/she may require the permittee to submit a permit application for 

the increased emissions.

(14) The permittee shall collect, record, and retain the following information for each toxic 

evaluation conducted to determine compliance with the “Toxic Air Contaminant Statute”, 

ORC 3704.03(F):

a. a description of the parameters/values used in each compliance demonstration 

and the parameters or values changed for any re-evaluation of the toxic(s) 

modeled (the composition of materials, new toxic contaminants emitted, change 

in stack/exhaust parameters, etc.);

b. the Maximum Acceptable Ground-Level Concentration (MAGLC) for each 

significant toxic contaminant or worst-case contaminant, calculated in 

accordance with the “Toxic Air Contaminant Statute”, ORC 3704.03(F);

c. a copy of the computer model run(s), that established the predicted 1-hour 

maximum ground-level concentration that demonstrated the emissions unit(s) to 

be in compliance with the “Toxic Air Contaminant Statute”, ORC 3704.03(F), 

initially and for each change that requires re-evaluation of the toxic air 

contaminant emissions; and

d. the documentation of the initial evaluation of compliance with the “Toxic Air 

Contaminant Statute”, ORC 3704.03(F), and documentation of any determination 

that was conducted to re-evaluate compliance due to a change made to the 

emissions unit(s) or the materials applied.

(15) The permittee shall maintain a record of any change made to a parameter or value used 

in the dispersion model, used to demonstrate compliance with the “Toxic Air 

Contaminant Statute”, ORC 3704.03(F), through the predicted 1-hour maximum 

ground-level concentration. The record shall include the date and reason(s) for the 

change and if the change would increase the ground-level concentration.

(16) See 40 CFR Part 60, Subpart KKKK (40 CFR 60.4300 – 60.4420).

e) Reporting Requirements

(1) The permittee shall submit deviation (excursion) reports that identify each day when a 

fuel other than natural gas was burned in this emissions unit. Each report shall be 

submitted within 30 days after the deviation occurs.

(2) The permittee shall submit quarterly deviation (excursion) reports that identify the 

following:

a. Any monthly record showing an exceedance of the allowable sulfur content of 

natural gas,0.5 grain per 100 standard cubic feet; and
Final Permit-to-Install

Oregon Clean Energy Center

Permit Number: P0117413

Facility ID: 0448020102

Effective Date:9/30/2014

Page 42 of 55

b. all exceedances of the rolling, 12-monthcombined natural gas usage limitation; 

and for the first 12 calendar months of operation or the first 12 calendar months 

following the issuance of this permit, all exceedances of the maximum allowable 

cumulative combined natural gas usage levels.

The quarterly deviation (excursion) reports shall be submitted in accordance with the 

reporting requirements of the Standard Terms and Conditions of this permit.

(3) The permittee shall comply with the following quarterly reporting requirements for the 

emissions unit and its continuous NOx monitoring system:

a. Pursuant to the monitoring, record keeping, and reporting requirements for

continuous monitoring systems contained in 40 CFR 60.7 and 60.13(h) and the 

requirements established in this permit, the permittee shall submit reports within 

30 days following the end of each calendar quarter to the appropriate Ohio EPA 

District Office or local air agency, documenting all instances of NOx emissions in 

excess of any applicable limit specified in this permit, 40 CFR Part 60, 40 CFR 

Parts 75 and 76, OAC Chapters 3745-14 and 3745-23, and any other applicable 

rules or regulations. The report shall document the date, commencement and 

completion times, duration, and magnitude of each exceedance, as well as the 

reason (if known) and the corrective actions taken (if any) for each exceedance. 

Excess emissions shall be reported in units of the applicable standard(s).

b. These quarterly reports shall be submitted by January 30, April 30, July 30, and 

October 30 of each year and shall include the following:

i. the facility name and address;

ii. the manufacturer and model number of the continuous NOx and other 

associated monitors;

iii. a description of any change in the equipment that comprises the 

continuous emission monitoring system (CEMS), including any change to 

the hardware, changes to the software that may affect CEMS readings, 

and/or changes in the location of the CEMS sample probe;

iv. the excess emissions report (EER)*, i.e., a summary of any exceedances 

during the calendar quarter, as specified above;

v. the total NOx emissions for the calendar quarter (tons);

vi. the total operating time (hours) of the emissions unit;

vii. the total operating time of the continuous NOx monitoring system while 

the emissions unit was in operation;

viii. results and date of quarterly cylinder gas audits or linearity checks;

ix. unless previously submitted, results and date of the relative accuracy test 

audit(s), including results in units of the applicable standard(s), (during 

appropriate quarter(s));
Final Permit-to-Install

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Permit Number: P0117413

Facility ID: 0448020102

Effective Date:9/30/2014

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x. unless previously submitted, the results of any relative accuracy test audit 

showing the continuous NOx monitor out-of-control and the compliant 

results following any corrective actions;

xi. the date, time, and duration of any/each malfunction** of the continuous 

NOx monitoring system, emissions unit, and/or control equipment;

xii. the date, time, and duration of any downtime** of the continuous NOx

monitoring system and/or control equipment while the emissions unit was 

in operation; and

xiii. the reason (if known) and the corrective actions taken (if any) for each 

event in (b)(xi) and (xii).

Each report shall address the operations conducted and data obtained during the 

previous calendar quarter. Data substitution procedures from 40 CFR 75 are not to be 

used for showing compliance with the short term OAC 3745-31-05(A)(3) rule-based or 

NSPS-based limitation(s) in this permit.

* where no excess emissions have occurred or the continuous monitoring system(s) 

has/have not been inoperative, repaired, or adjusted during the calendar quarter, such 

information shall be documented in the EER quarterly report

** each downtime and malfunction event shall be reported regardless if there is an 

exceedance of any applicable limit

(4) The permittee shall comply with the following quarterly reporting requirements for the 

emissions unit and its continuous CO monitoring system:

a. Pursuant to the monitoring, record keeping, and reporting requirements for

continuous monitoring systems contained in 40 CFR 60.7 and 60.13(h) and the 

requirements established in this permit, the permittee shall submit reports within 

30 days following the end of each calendar quarter to the appropriate Ohio EPA 

District Office or local air agency, documenting all instances of CO emissions in 

excess of any applicable limit specified in this permit, 40 CFR Part 60, OAC 

Chapter 3745-21, and any other applicable rules or regulations. The report shall 

document the date, commencement and completion times, duration, and 

magnitude of each exceedance, as well as, the reason (if known) and the 

corrective actions taken (if any) for each exceedance. Excess emissions shall be 

reported in units of the applicable standard(s).

b. These quarterly reports shall be submitted by January 30, April 30, July 30, and 

October 30 of each year and shall include the following:

i. the facility name and address;

ii. the manufacturer and model number of the continuous CO and other 

associated monitors;
Final Permit-to-Install

Oregon Clean Energy Center

Permit Number: P0117413

Facility ID: 0448020102

Effective Date:9/30/2014

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iii. a description of any change in the equipment that comprises the 

continuous emission monitoring system (CEMS), including any change to 

the hardware, changes to the software that may affect CEMS readings, 

and/or changes in the location of the CEMS sample probe;

iv. the excess emissions report (EER)*, i.e., a summary of any exceedances 

during the calendar quarter, as specified above;

v. the total CO emissions for the calendar quarter (tons);

vi. the total operating time (hours) of the emissions unit;

vii. the total operating time of the continuous CO monitoring system while the 

emissions unit was in operation;

viii. results and dates of quarterly cylinder gas audits;

ix. unless previously submitted, results and dates of the relative accuracy 

test audit(s), including results in units of the applicable standard(s), 

(during appropriate quarter(s));

x. unless previously submitted, the results of any relative accuracy test audit 

showing the continuous CO monitor out-of-control and the compliant 

results following any corrective actions;

xi. the date, time, and duration of any/each malfunction** of the continuous 

CO monitoring system, emissions unit, and/or control equipment;

xii. the date, time, and duration of any downtime** of the continuous CO 

monitoring system and/or control equipment while the emissions unit was 

in operation; and

xiii. the reason (if known) and the corrective actions taken (if any) for each 

event in (b)(xi) and (xii).

Each report shall address the operations conducted and data obtained during the 

previous calendar quarter. Data substitution procedures from 40 CFR 75 are not to be 

used for showing compliance with the short term OAC 3745-31-05(A)(3) rule-based or 

NSPS-based limitation(s) in this permit.

* where no excess emissions have occurred or the continuous monitoring system(s) 

has/have not been inoperative, repaired, or adjusted during the calendar quarter, such 

information shall be documented in the EER quarterly report

** each downtime and malfunction event shall be reported regardless if there is an 

exceedance of any applicable limit

(5) The permittee shall collect, record, and maintain measurements, data, records, and 

reports required per 40 CFR Part 75; and shall submit certification, recertification, 

notifications, applications, monitoring plans, petitions for alternative monitoring systems, 
Final Permit-to-Install

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Permit Number: P0117413

Facility ID: 0448020102

Effective Date:9/30/2014

Page 45 of 55

electronic quarterly reports, and any other pertinent record and/or report to the 

Administrator (U.S. EPA), as required by this Part.

(6) The permittee shall submit annual reports that include any changes to any parameter or 

value used in the dispersion model used to demonstrate compliance with the “Toxic Air 

Contaminate Statute”, ORC 3704.03(F), through the predicted 1 hour maximum 

concentration. The report should include:

a. the original model input;

b. the updated model input;

c. the reason for the change(s) to the input parameter(s); and

d. a summary of the results of the updated modeling, including the input changes; 

and

e. a statement that the model results indicate that the 1-hour maximum ground-level 

concentration is less than 80% of the MAGLC.

If no changes to the emissions, emissions unit(s), or the exhaust stack have been made 

during the reporting period, then the report shall include a statement to that effect.

(7) See 40 CFR Part 60, Subpart KKKK (40 CFR 60.4300 – 60.4420).

f) Testing Requirements

(1) Compliance with the Emissions Limitations and/or Control Requirements specified in 

section b) of these terms and conditions shall be determined in accordance with the 

following methods:

a. Emission Limitation:

The sulfur content of natural gas burned shall not exceed 0.5 grain per standard 

cubic feet.

Applicable Compliance Method:

Compliance with the lb/mmBtu limitation will be determined by the monitoring and 

recordkeeping specified in 40 CFR 60.4365 or 40 CFR 60.4370.

If required, the permittee shall demonstrate compliance using the procedures 

specified in 40 CFR 60.4415(a)(1). Alternative U.S. EPA approved test methods 

may be used with prior approval from the Ohio EPA.

b. Emission Limitation:

SO2 emissions shall not exceed 1.5E-03 lb/mmBtu of heat input.
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Permit Number: P0117413

Facility ID: 0448020102

Effective Date:9/30/2014

Page 46 of 55

Applicable Compliance Method:

The lb/mmBtu limitation was established based on using pipeline quality natural 

gas having a maximum sulfur content of 0.5 grains per 100 cubic feet according 

to the following calculation. Multiply the maximum sulfur content of natural gas 

(0.5 grain S/100 scf) by the molecular weight of SO2 (64.07 lb SO2/lb-mole) 

divide by the molecular weight of sulfur (32.06 lb S/lb-mole) divide by (7,000 

grains/lb), divide by the manufacturer’s gas specification (983 Btu/scf), and 

multiply by (106 Btu/mmBtu).

If required, compliance shall be demonstrated according to 40 CFR 60.4415.

c. Emission Limitation:

Visible particulate emissions from any stack serving this emissions unit shall not 

exceed 10 percent opacity as a 6-minute average.

Applicable Compliance Method:

If required, the permittee shall demonstrate compliance with this emissions 

limitation using Method 9 of 40 CFR Part 60, Appendix A. Alternative U.S. EPA 

approved test methods may be approved with prior approval from Ohio EPA.

d. Emission Limitation:

CO emissions from this emissions unit shall not exceed 2.0 ppmvd at 15% 

oxygen as an hourly average and 13.0 lbs/hr when the duct burner is not in 

operation; and, 2.0 ppmvd at 15% oxygen as an hourly average and 14.4 lbs/hr 

when the duct burner is in operation.

Applicable Compliance Method:

These emissions limitations are based on manufacturer’s data. Ongoing 

compliance with the CO emission limitations shall be demonstrated through the 

data collected as required in the Monitoring and Record keeping Section of this 

permit; and through demonstration of compliance with the quality 

assurance/quality control plan, which shall meet the requirements of 40 CFR Part 

60.

If required, the permittee shall demonstrate compliance using Methods 1 thru 4 

and 10 of 40 CFR Part 60, Appendix A. Alternative U.S. EPA approved test 

methods may be used with prior approval from the Ohio EPA.

e. Emission Limitation:

CO emissions from this emissions unit shall not exceed 546 lbs/hr during cold 

startup, 289 lbs/hr during hot startup, 351 lbs/hr during warm startup, and 113 

lbs/hr during shutdown.
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Facility ID: 0448020102

Effective Date:9/30/2014

Page 47 of 55

Applicable Compliance Method:

These emissions limitations are based on manufacturer’s data. Ongoing 

compliance with the CO emission limitations shall be demonstrated through the 

data collected as required in the Monitoring and Record keeping Section of this 

permit; and through demonstration of compliance with the quality 

assurance/quality control plan, which shall meet the requirements of 40 CFR Part 

60.

f. Emission Limitation:

CO emissions from this emissions unit shall not exceed 91.3 tons per rolling, 12-

month period.

Applicable Compliance Method:

This emissions limitation is based on the following anticipated worst case 

emissions: 250 hot startups per year, with an annual average downtime 

preceding hot startup of 8 hours, and a hot startup duration of 98 minutes; 

shutdown duration of 26 minutes; maximum combined CO emissions of 351 

pounds during each hot startup period and 113 pounds during each shutdown 

period; hourly CO emissions during steady state operation (Siemens Case #31 of 

PSD Dispersion Modeling) of 13.0 lbs/hr based on manufacturer’s data; and 

steady state operating hours was determined by the following equation.

8,760 h − 250 8 h +

() 

 







 = 6,310 hours

The allowable annual emission rate was determined by the following calculation 

using the above information.







, .











= 91.3 tons/yr

Where:

HS = hot starts

Ongoing compliance with this emissions limitation shall be based on the pounds 

per hour emission data from the CO CEMS and the actual hours of operation of 

this emissions unit.

g. Emission Limitation:

NOx emissions from this emissions unit shall not exceed 2.0 ppmvd at 15% 

oxygen as an hourly average and 22.0 lbs/hr when the duct burner is not in 

operation; and, NOx emissions shall not exceed 2.0 ppmvd at 15% oxygen as an 

hourly average and 23.6 lbs/hr when the duct burner is in operation.
Final Permit-to-Install

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Permit Number: P0117413

Facility ID: 0448020102

Effective Date:9/30/2014

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Applicable Compliance Method:

These emissions limitations are based on manufacturer’s data. Ongoing 

compliance with the NOx emissions limitations shall be demonstrated through the 

data collected as required in the Monitoring and Record keeping Section of this 

permit; and through demonstration of compliance with the quality 

assurance/quality control plan, which shall meet the testing and recertification 

requirements of 40 CFR Part 60 and 40 CFR Part 75.

If required, the permittee shall demonstrate compliance using Methods 1 thru 4 

and 7E of 40 CFR Part 60, Appendix A, and the procedures specified in 40 CFR 

60.4400. Alternative U.S. EPA approved test methods may be used with prior 

approval from the Ohio EPA.

h. Emission Limitation:

NOx emissions shall not exceed 92.0 tons per rolling, 12-month period.

Applicable Compliance Method:

This emission limitation was developed by multiplying the NOx emissions during 

steady state operation (Siemens Case #31 of PSD Dispersion Modeling) of 21.0 

lbs/hr by the maximum annual hours of operation (8,760 hours), and then 

dividing by 2,000 pounds per ton. Therefore, if compliance is shown with the 

short-term allowable emission limitation, compliance shall also be shown with the 

annual emission limitation.

Ongoing compliance with this emissions limitation shall be determined using the 

pounds per hour emission data from the NOx CEMS and the actual hours of 

operation of this emissions unit.

i. Emission Limitation:

NOx emissions from this emissions unit shall not exceed 188 lbs/hr during cold 

startup, 105 lbs/hr during hot startup, 129 lbs/hr during warm startup, and 46 

lbs/hr during shutdown.

Applicable Compliance Method:

These emissions limitations are based on manufacturer’s data. Ongoing 

compliance with the NOx emissions limitations shall be demonstrated through the 

data collected as required in the Monitoring and Record keeping Section of this 

permit; and through demonstration of compliance with the quality 

assurance/quality control plan, which shall meet the testing and recertification 

requirements of 40 CFR Part 60 and 40 CFR Part 75.

j. Emission Limitation:

PM10 emissions and PM2.5 emissions shall not exceed 5.4E-03 lb/mmBtu of heat 

input and 13.3 lbs/hr when the duct burner is not in operation; and, PM10 and 
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Permit Number: P0117413

Facility ID: 0448020102

Effective Date:9/30/2014

Page 49 of 55

PM2.5 shall not exceed 5.5E-03 lb/mmBtu of heat input and 15.1 lbs/hr when the 

duct burner is in operation.

Applicable Compliance Method:

These emissions limitations are based on manufacturer’s data. If required, the 

permittee shall demonstrate compliance with these emissions limitations using 

Methods 201A and 202 of 40 CFR Part 51, Appendix M. Alternative U.S. EPA 

approved test methods may be used with prior approval from the Ohio EPA.

k. Emission Limitation:

PM10 and PM2.5 emissions from this emissions unit shall not exceed 61.3 tons per 

rolling, 12-month period.

Applicable Compliance Method:

This emission limitation was developed by multiplying the PM10/PM2.5 emissions 

during steady state operation (Siemens Case #3 of PSD Dispersion Modeling) of 

15.1 lbs/hr by the maximum annual hours of operation (8,760 hours), and then 

dividing by 2,000 pounds per ton. Therefore, if compliance is shown with the 

short-term allowable emission limitation, compliance shall also be shown with the 

annual emission limitation.

l. Emission Limitation:

The combined SO2 emissions from P001 and P002 shall not exceed 37.6 tons 

per rolling, 12-month period.

Applicable Compliance Method:

Compliance with this emissions limitation shall be determined by the following 

calculation based on the records required by d). Multiply the maximum sulfur 

content of natural gas (0.5 gr S/100 scf) by the molecular weight of SO2 (64.07 

lb/lb-mole), divide by the molecular weight of sulfur (32.06 lb/lb-mole), divide by 

(7,000 gr/lb), multiply by the monthly natural gas usage (scf), and divide by 

(2,000 lbs/ton) to determine the monthly SO2 emissions (tons). Add the SO2

emissions calculated for the current month to the total SO2 emissions calculated 

for the previous 11 months to determine the tons SO2 emissions per rolling, 12-

month period.

m. Emission Limitation:

VOC emissions shall not exceed 1.0 ppmvd at 15% oxygen as an hourly average 

and 3.9 lbs/hr when the duct burner is not in operation; and, VOC emissions shall 

not exceed 1.9 ppmvd at 15% oxygen as an hourly average and 5.9 lbs/hr when 

the duct burner is in operation.
Final Permit-to-Install

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Permit Number: P0117413

Facility ID: 0448020102

Effective Date:9/30/2014

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Applicable Compliance Method:

These emissions limitations are based on manufacturer’s data. If required, the 

permittee shall demonstrate compliance with this emission limitation through 

emission testing performed in accordance with Methods 1 through 4 and 18, 25 

or 25A, as appropriate, of 40 CFR Part 60, Appendix A. Use of Method 18, 25 or 

25A is to be selected based on the results of pre-survey stack sampling and U.S. 

EPA guidance documents. Alternative U.S. EPA approved test methods may be 

used with prior approval from Ohio EPA.

n. Emission Limitation:

VOC emissions shall not exceed 38.5 tons per rolling, 12-month period.

Applicable Compliance Method:

This emissions limitation is based on the following anticipated worst case 

emissions: 250 hot startups per year, with an annual average downtime 

preceding hot startup of 8 hours, and a hot startup duration of 98 minutes; 

shutdown duration of 26 minutes; maximum VOC emissions of 114 pounds 

during each hot startup period and 45 pounds during each shutdown period; 

hourly VOC emissions during steady state operation (Siemens Case #31 of PSD 

Dispersion Modeling) of 5.9 lbs/hr based on manufacturer’s data; and steady 

state operating hours was determined by the following equation.

8,760 h − 250 8 h +

() 

 







 = 6,310 hours

The allowable annual emission rate was determined by the following calculation 

using the above information.



, .











= 38.5 tons/yr

Where:

HS = hot starts

Ongoing compliance with this emissions limitation shall be based on the following 

calculation. 

(#)

(#)(#) (#) (#).





(#).











= VOC
Final Permit-to-Install

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Permit Number: P0117413

Facility ID: 0448020102

Effective Date:9/30/2014

Page 51 of 55

Where:

VOC = tons VOC emissions per rolling, 12-month period

#CS = number of cold startups per rolling, 12-month period

#HS = number of hot startups per rolling, 12-month period

#WS = number of warm startups per rolling, 12-month period

#SD = number of shutdowns per rolling, 12-month period

#SSDB = hours operated in steady state with duct burner per rolling, 12-month 

period

#SSNDB = hours operated in steady state without duct burner per rolling, 12-

month period 

o. Emission Limitation:

VOC emissions from this emissions unit shall not exceed 168 lbs/hr during cold 

startup, 114 lbs/hr during hot startup, 138 lbs/hr during warm startup, and 45 

lbs/hr during shutdown.

Applicable Compliance Method:

These emissions limitations are based on manufacturer’s data. If required, the 

permittee shall demonstrate compliance with this emission limitation through 

emission testing performed in accordance with Methods 1 through 4 and 18, 25 

or 25A, as appropriate, of 40 CFR Part 60, Appendix A. Use of Method 18, 25 or 

25A is to be selected based on the results of pre-survey stack sampling and U.S. 

EPA guidance documents. Alternative U.S. EPA approved test methods may be 

used with prior approval from Ohio EPA.

p. Emission Limitation:

H2SO4 emissions shall not exceed 6.0E-04 lb/mmBtu of heat input and 1.6 lbs/hr 

when the duct burner is not in operation; and, H2SO4 emissions shall not exceed 

7.0E-04 lb/mmBtu of heat input and 1.5 lbs/hr when the duct burner is in 

operation.

These emissions limitations are based on manufacturer’s data. If required, the 

permittee shall demonstrate compliance using Methods 1 thru 4 and 8 of 40 CFR 

Part 60, Appendix A. Alternative U.S. EPA approved test methods may be used 

with prior approval from the Ohio EPA.

q. Emission Limitation:

H2SO4 emissions shall not exceed 6.6 tons per rolling, 12-month period.
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Effective Date:9/30/2014

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Applicable Compliance Method:

This emission limitation was developed by multiplying the short-term allowable 

H2SO4 emission limitation (1.5 lbs/hr) by the maximum annual hours of operation 

(8,760 hours), and then dividing by 2,000 pounds per ton. Therefore, if 

compliance is shown with the short-term allowable emission limitation, 

compliance shall also be shown with the annual emission limitation.

r. Emission Limitation:

CO2e emissions shall not exceed 371,029 lbs/hr and 1,477,071 tons per rolling, 

12-month period.

Applicable Compliance Method:

The hourly emission limitation is based on the sum of following manufacturer’s 

data Siemens Case #3 (370,652 lbs/hr CO2, 6.876 lbs/hr CH4, and 0.688 lbs/hr 

N2O) multiplied by the associated global warming potential for each pollutant 

(CO2=1, CH4=25, N2O=298 from Table A-1 of 40 CFR 98).

370,652



h

 (1) + 6.876 +



h

 (25) + 0.688



h

 (298) = 371,029 /h

Since the CO2e emissions are estimated to consist of more than 99% CO2, 

compliance with this emission limitation will be assumed provided that the hourly 

CO2 emission rate does not exceed 370,652 lbs/hr. If required, the permittee 

shall conduct emissions testing using Methods 1, 2, 3A and 4 of 40 CFR Part 60, 

Appendix A to determine the hourly CO2 emission rate.

The annual emission limitation is based on the sum of following manufacturer’s 

data modeling Siemens Case #3 (336,888.4 lbs/hr CO2, 6.25 lbs/hr CH4, and 

0.625 lbs/hr N2O) multiplied by the associated global warming potential for each 

pollutant (CO2=1, CH4=25, N2O=298 from Table A-1 of 40 CFR 98) by the

maximum annual hours of operation (8,760 hrs/yr) and dividing by (2,000 

lbs/ton).

336,888.4



h

 (1) + 6.25



h

 (25) + 0.625



h

 (298) 8,760

h

  



2000

= 1,477,071 /

Since the CO2e emissions are estimated to consist of more than 99% CO2, 

compliance with this emission limitation will be assumed provided that the rolling, 

12-month CO2 emissions as calculated in section d) above do not exceed 

1,475,570 tons per rolling, 12-month period (336,888 lbs/hr x 8760 hrs/yr x 

ton/2000 lb = 1,475,570 tons/yr).

(2) The permittee shall conduct, or have conducted, emission testing for this emissions unit 

in accordance with the following requirements:
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a. The emission testing shall be conducted within 60 days after achieving the 

maximum production rate at which the emissions unit will be operated, but not 

later than 180 days after initial startup of the emissions unit.

b. The emission testing shall be conducted to demonstrate compliance with the 

allowable mass emission rate(s) for CO, NOx, PM10, PM2.5, VOC, and H2SO4, in 

the appropriate averaging period(s).

The emission testing shall also be conducted to determine a site-specific 

emission factor for CO2.

c. The following test method(s) shall be employed to demonstrate compliance with 

the allowable mass emission rate(s):

For CO, Methods 1 thru 4 and 10 of 40 CFR Part 60, Appendix A;

For NOx, Methods 1 thru 4 and 7E of 40 CFR Part 60, Appendix A, and the 

procedures specified in 40 CFR 60.4400;

For PM10 and PM2.5, Methods 201A and 202 of 40 CFR Part 52, Appendix M;

For SO2, 40 CFR 60.4415;

For VOC, Methods 1 through 4 and 18, 25 or 25A, as appropriate, of 40 CFR 

Part 60, Appendix A.Use of Method 18, 25 or 25A is to be selected based on the 

results of pre-survey stack sampling and U.S. EPA guidance documents;

For H2SO4, Methods 1 thru 4 and 8 of 40 CFR Part 60, Appendix A; and

For CO2, Methods 1, 2, 3A, and 4 of 40 CFR Part 60, Appendix A.

Alternative U.S. EPA approved test methods may be used with prior approval 

from the Ohio EPA.

d. The test(s) shall be conducted under those representative conditions that 

challenge to the fullest extent possible a facility’s ability to meet the applicable 

emissions limits and/or control requirements, unless otherwise specified or 

approved by the appropriate Ohio EPA District Office or local air agency. 

Although this generally consists of operating the emissions unit at its maximum 

material input/production rates and results in the highest emission rate of the 

tested pollutant, there may be circumstances where a lower emissions loading is 

deemed the most challenging control scenario. Failure to test under these 

conditions is justification for not accepting the test results as a demonstration of 

compliance.

e. Not later than 30 days prior to the proposed test date(s), the permittee shall 

submit an "Intent to Test" notification to the appropriate Ohio EPA District Office 

or local air agency. The "Intent to Test" notification shall describe in detail the 

proposed test methods and procedures, the emissions unit operating 

parameters, the time(s) and date(s) of the test(s), and the person(s) who will be 
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Facility ID: 0448020102

Effective Date:9/30/2014

Page 54 of 55

conducting the test(s). Failure to submit such notification for review and approval 

prior to the test(s) may result in the Ohio EPA District Office's or local air

agency's refusal to accept the results of the emission test(s).

f. Personnel from the appropriate Ohio EPA District Office or local air agency shall 

be permitted to witness the test(s), examine the testing equipment, and acquire 

data and information necessary to ensure that the operation of the emissions unit 

and the testing procedures provide a valid characterization of the emissions from 

the emissions unit and/or the performance of the control equipment.

g. A comprehensive written report on the results of the emissions test(s) shall be 

signed by the person or persons responsible for the tests and submitted to the 

appropriate Ohio EPA District Office or local air agency within 30 days following 

completion of the test(s). The permittee may request additional time for the 

submittal of the written report, where warranted, with prior approval from the 

appropriate Ohio EPA District Office or local air agency.

(3) Within 60 days of achieving the maximum production rate at which the emissions unit(s) 

will be operated, but not later than 180 days after initial startup, the permittee shall 

conduct certification tests of the continuous NOx monitoring system, in units of the 

applicable standard(s), to demonstrate compliance with 40 CFR Part 60, Appendix B, 

Performance Specification 2; Performance Specification 6 relative accuracy 

requirements; ORC section 3704.03(I); and 40 CFR Part 75.

The permittee shall certify that the fuel flow monitor/meter meets 40 CFR 75 certification 

requirements prior to the performance specification test and shall demonstrate how the 

pound per hour emissions of NOx will be calculated stoichiometrically from the fuel flow 

rate.

Personnel from the Ohio EPA Central Office and the appropriate Ohio EPA District 

Office or local air agency shall be notified 45 days prior to initiation of the applicable 

tests and shall be permitted to examine equipment and witness the certification tests. 

Two copies of the test results shall be submitted to Ohio EPA, one copy to the 

appropriate Ohio EPA District Office or local air agency and one copy to Ohio EPA 

Central Office, and pursuant to OAC rule 3745-15-04, within 30 days after the test is 

completed.

Certification, or recommendation for certification by Ohio EPA to U.S. EPA, of the 

continuous NOx monitoring system shall be granted upon determination by the Ohio 

EPA, Central Office that the system meets the requirements of 40 CFR Part 60, 

Appendix B, Performance Specification 2; Performance Specification 6 relative accuracy 

requirements; ORC section 3704.03(I); and 40 CFR Part 75.

Ongoing compliance with the NOx emissions limitations contained in this permit, 40 CFR 

Parts 60 and 75, and any other applicable standard(s) shall be demonstrated through 

the data collected as required in the Monitoring and Record keeping Section of this 

permit; and through demonstration of compliance with the quality assurance/quality 

control plan, which shall meet the testing and recertification requirements of 40 CFR Part 

60 and 40 CFR Part 75.
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(4) Within 60 days of achieving the maximum production rate at which the emissions unit(s) 

will be operated, but not later than 180 days after initial startup, the permittee shall 

conduct certification tests of the continuous CO monitoring system in units of the 

applicable standard(s), to demonstrate compliance with 40 CFR Part 60, Appendix B, 

Performance Specification 4 or 4a (as appropriate); Performance Specification 6 relative 

accuracy requirements; and ORC section 3704.03(I).

The permittee shall certify that the fuel flow monitor/meter is calibrated prior to the 

performance specification test and shall demonstrate how the pound per hour emissions 

of CO will be calculated stoichiometrically from the fuel flow rate.

Personnel from the Ohio EPA Central Office and the appropriate Ohio EPA District 

Office or local air agency shall be notified 30 days prior to initiation of the applicable 

tests and shall be permitted to examine equipment and witness the certification tests. 

Two copies of the test results shall be submitted to Ohio EPA, one copy to the 

appropriate Ohio EPA District Office or local air agency and one copy to Ohio EPA 

Central Office, and pursuant to OAC rule 3745-15-04, within 30 days after the test is 

completed.

Certification of the continuous CO monitoring system shall be granted upon 

determination by the Ohio EPA Central Office that the system meets the requirements of 

40 CFR Part 60, Appendix B, Performance Specification 4 or 4a (as appropriate); 

Performance Specification 6 relative accuracy requirements; and ORC section 

3704.03(I).

Ongoing compliance with the CO emission limitations contained in this permit, 40 CFR 

Part 60, and any other applicable standard(s) shall be demonstrated through the data 

collected as required in the Monitoring and Record keeping Section of this permit; and 

through demonstration of compliance with the quality assurance/quality control plan, 

which shall meet the requirements of 40 CFR Part 60.

g) Miscellaneous Requirements

(1) None.
Oregon Clean Energy Center 

Lucas County, Oregon, Ohio 

Application for Prevention of Significant Deterioration 

Preconstruction Permit

Submitted by: 

Oregon Clean Energy, LLC 

20 Park Plaza, Suite #471 

Boston, MA 02116 

Prepared by: 

One Executive Drive 

Suite 303 

Chelmsford, MA 01824 

August 2012
Table of Contents Page i 

Oregon Clean Energy Center 

 Lucas County, OH 

PSD Permit Application 

1. Introduction 1-1

1.1 Project Overview 1-1

1.2 Regulatory Overview 1-2

1.3 Application Overview 1-2

1.3.1 Application Organization 1-2

1.3.2 Application Contacts 1-3

2. Project Description 2-1

2.1 Overview 2-1

2.2 Site Location 2-1

2.3 Combined Cycle Combustion Turbines 2-2

2.3.1 Combustion Turbine Generators 2-2

2.3.2 Heat Recovery Steam Generators and Duct Burners 2-3

2.3.3 Steam Turbine Generator 2-3

2.3.4 Cooling Tower 2-3

2.4 Air Pollution Control Equipment 2-3

2.4.1 Selective Catalytic Reduction 2-4

2.4.2 Oxidation Catalyst 2-4

2.5 Ancillary Equipment 2-4

2.5.1 Auxiliary Boiler 2-5

2.5.2 Emergency Diesel Generator 2-5

2.5.3 Emergency Diesel Fire Pump 2-5

2.5.4 Aqueous NH3 Storage Tank 2-5

2.6 Emissions Estimates 2-5

2.6.1 Combined Cycle Combustion Turbine Emissions – Steady State 

Operation 2-7

2.6.2 Combined Cycle Combustion Turbine Emissions – Start-up and 

Shutdown Operations 2-8

2.6.3 Ancillary Equipment 2-10
Table of Contents Page ii 

Oregon Clean Energy Center 

 Lucas County, OH 

PSD Permit Application 

2.6.4 Potential Annual Emissions 2-11

3. Regulatory Applicability Evaluation 3-1

3.1 PSD New Source Review 3-1

3.1.1 Best Available Control Technology 3-2

3.1.2 Air Quality Impact Analysis 3-2

3.1.3 PSD Class I Area Impact Analysis 3-3

3.1.4 Additional Impact Analyses 3-4

3.2 New Source Performance Standards 3-5

3.2.1 40 CFR 60 – Subpart A – General Provisions 3-5

3.2.2 40 CFR 60 – Subpart KKKK – Stationary Combustion Turbines 3-5

3.2.3 40 CFR 60 – Subpart Dc – Small Industrial-CommercialInstitutional Steam Generating Units 3-6

3.2.4 40 CFR 60 – Subpart IIII – Stationary Compression Ignition 

Internal Combustion Engines 3-6

3.3 State of Ohio Best Available Technology 3-7

3.4 Operating Permit 3-8

3.5 National Emission Standards for Hazardous Air Pollutants (40 CFR Parts 

61 and 63) 3-9

3.6 Acid Rain Program 3-10

3.7 Cross-State Air Pollution Rule 3-10

3.8 State Regulations 3-11

4. Control Technology Evaluation – BACT/BAT 4-1

4.1 Regulatory Applicability of Control Requirements 4-1

4.1.1 PSD Pollutants Subject to BACT/BAT 4-1

4.1.2 Emission Units Subject to BACT Analyses 4-2

4.2 BACT Analysis Approach 4-2

4.2.1 Best Available Control Technology 4-2

4.2.1.1 Identification of Technically Feasible Control Options 4-2

4.2.1.2 Economic (Cost-Effectiveness) Analysis 4-3
Table of Contents Page iii 

Oregon Clean Energy Center 

 Lucas County, OH 

PSD Permit Application 

4.2.1.3 Energy Impact Analysis 4-3

4.2.1.4 Environmental Impact Analysis 4-4

4.3 BACT Analysis for NOx 4-4

4.3.1 Identification of Control Options 4-5

4.3.2 Search of RBLC Determinations 4-6

4.3.2.1 Combustion Turbine Generators and Duct Burners 4-6

4.3.2.2 Auxiliary Boiler 4-6

4.3.3 BACT Determinations 4-7

4.3.3.1 Combustion Turbine Generators and Duct Burners 4-7

4.3.3.2 Auxiliary Boiler 4-7

4.4 BACT Analysis for VOC 4-7

4.4.1 Identification of Control Options 4-8

4.4.2 Search of RBLC Determinations 4-8

4.4.2.1 Combustion Turbine Generators and Duct Burners 4-8

4.4.2.2 Auxiliary Boiler 4-9

4.4.3 BACT Determinations 4-9

4.4.3.1 Combustion Turbine Generators and Duct Burners 4-9

4.4.3.2 Auxiliary Boiler 4-9

4.5 BACT Analysis for CO 4-9

4.5.1 Identification of Control Options 4-10

4.5.2 Search of RBLC Determinations 4-10

4.5.2.1 Combustion Turbine Generators and Duct Burners 4-10

4.5.2.2 Auxiliary Boiler 4-11

4.5.3 BACT Determinations 4-12

4.5.3.1 Combustion Turbine Generators and Duct Burners 4-12

4.5.3.2 Auxiliary Boiler 4-12

4.6 BACT Analysis for Particulate Matter (PM10/PM2.5) 4-12
Table of Contents Page iv 

Oregon Clean Energy Center 

 Lucas County, OH 

PSD Permit Application 

4.6.1 Search of RBLC Determinations 4-13

4.6.1.1 Combustion Turbine Generators and Duct Burners 4-13

4.6.1.2 Auxiliary Boiler 4-13

4.6.1.3 Wet Cooling Tower 4-13

4.6.2 BACT Determinations 4-14

4.6.2.1 Combustion Turbine Generators and Duct Burners 4-14

4.6.2.2 Auxiliary Boiler 4-14

4.6.2.3 Wet Cooling Tower 4-14

4.7 BACT Analysis for Sulfur Dioxide and Sulfuric Acid 4-14

4.7.1 Search of RBLC Determinations 4-15

4.7.1.1 Combustion Turbine Generators and Duct Burners 4-15

4.7.1.2 Auxiliary Boiler 4-15

4.7.2 BACT Determinations 4-16

4.7.2.1 Combustion Turbine Generators and Duct Burners 4-16

4.7.2.2 Auxiliary Boiler 4-16

4.8 BACT Analysis for Greenhouse Gases 4-16

4.8.1.1 Search of RBLC Determinations 4-19

4.9 Emission Limit and Control Technology Summaries 4-20

5. References 5-1
Table of Contents Page v 

Oregon Clean Energy Center 

 Lucas County, OH 

PSD Permit Application 

List of Tables 

TABLE 1‐1:  SUMMARY OF PROPOSED POTENTIAL EMISSIONS AND  APPLICABLE REGULATORY THRESHOLDS....1‐2

TABLE 2‐1:  SUMMARY OF PROPOSED EMISSION LIMITS FOR COMBINED CYCLE COMBUSTION TURBINES (STEADY

STATE FULL LOADOPERATION)....................................................................................................2‐6

TABLE 2‐2:  SUMMARY OF SHORT TERM EMISSION RATES FOR A SINGLE COMBUSTION TURBINE....................2‐8

TABLE 2‐3:  EMISSIONS AND DOWNTIMES ASSOCIATED WITH START‐UP AND SHUTDOWN EVENTS .................2‐9

TABLE 2‐4:  AVERAGE HOURLY EMISSIONS FOR START‐UP AND SHUTDOWN EVENTS  (INCLUDING DOWNTIME).2‐9

TABLE 2‐5:  SHORT‐TERM POTENTIAL EMISSIONS FROM ANCILLARY EQUIPMENT .......................................2‐11

TABLE 2‐6:  POTENTIAL ANNUAL EMISSIONS FROM ANCILLARY EQUIPMENT..............................................2‐11

TABLE 2‐7:  SUMMARY OF ANNUAL POTENTIAL EMISSIONS ....................................................................2‐12

TABLE 3‐1:  “Q/D” SCREENING ANALYSIS FOROCE FOR CLASS I AREAS .....................................................3‐4

TABLE 3‐2:  OHIO EPA APPLICABLE REGULATIONS................................................................................3‐11

TABLE 4‐1:  SUMMARY OF PROPOSED BACT/BAT EMISSION LIMITS AND ASSOCIATED CONTROL TECHNOLOGIES

FOR THE COMBUSTION TURBINES ...............................................................................................4‐21

TABLE 4‐2:  SUMMARY OF PROPOSED BACT/BAT EMISSION LIMITS AND ASSOCIATED CONTROL TECHNOLOGIES

FOR THE AUXILIARY BOILER........................................................................................................4‐22

List of Figures (provided following text)

FIGURE 1: SITE LOCATION

Appendices 

APPENDIX A: PRINTOUT OF OHIO EPA PERMIT FORMS

APPENDIX B: SUPPORTING CALCULATIONS

APPENDIX C: RBLC TABLES

 
Table of Contents Page vi 

Oregon Clean Energy Center 

 Lucas County, OH 

PSD Permit Application 

List of Acronyms and Abbreviations 

°F degrees Fahrenheit 

% percent 

AQRV Air Quality Related Values 

BAAMD Bay Area Air Quality Management District 

BACT Best Available Control Technology 

BAT Best Available Technology 

BP British Petroleum 

Btu British thermal units 

Btu/kW-hr British thermal unit per kilowatt-hour 

CAA Clean Air Act 

CAIR Clean Air Interstate Rule 

CARB California Air Resource Board 

CATEF California Air Toxics Emission Factor 

CCGT combined cycle gas turbine 

CCS carbon capture and sequestration 

CEMS continuous emissions monitoring systems 

CFR Code of Federal Regulations 

CH4 methane 

CI compression ignition 

CO carbon monoxide 

CO2 carbon dioxide 

the Court U.S. Court of Appeals for the D.C. Circuit 

CSAPR Cross-State Air Pollution Rule 

CTG combustion turbine generator 

DB duct burner 

DLN dry low NOx

FGD flue gas desulfurization 

FLM Federal Land Manager 

GHG greenhouse gas 
Table of Contents Page vii 

Oregon Clean Energy Center 

 Lucas County, OH 

PSD Permit Application 

g/hp-hr grams per horsepower-hour 

g/kW-hr grams per kilowatt-hour 

HAP hazardous air pollutant 

HHV higher heating value 

H2O water 

hp horsepower 

HRSG heat recovery steam generator 

H2SO4 sulfuric acid mist 

ISO International Organization for Standards 

km kilometer 

kV kilovolts 

kW kilowatts 

LAER Lowest Achievable Emission Rate 

lb pounds 

lb/hr pounds per hour 

lb/MMBtu pounds per million British thermal units 

lb/MW-hr pounds per megawatt-hour 

MACT Maximum Achievable Control Technology 

MAGLC Maximum Acceptable Ground-Level Concentration 

mg/l milligrams per liter 

MMBtu million British thermal units 

MMBtu/hr million British thermal units per hour 

MW megawatts 

N2 nitrogen gas 

n/a not applicable 

NESHAP National Emission Standards for Hazardous Air Pollutants 

ng/J nanograms per Joule 

NH3 ammonia 

NO nitrogen oxide 

NO2 nitrogen dioxide 
Table of Contents Page viii 

Oregon Clean Energy Center 

 Lucas County, OH 

PSD Permit Application 

N2O nitrous oxide 

NOx nitrogen oxides 

NSPS New Source Performance Standards 

O2 oxygen 

OAC Ohio Administrative Code 

OCE Oregon Clean Energy, LLC 

Ohio EPA Ohio Environmental Protection Agency 

Pb lead 

PM10 particulate matter with a diameter equal to or less than 10 microns 

PM2.5 particulate matter with a diameter equal to or less than 2.5 microns 

ppm parts per million 

ppmv parts per million by volume 

ppmw parts per million by weight 

the Project Oregon Clean Energy Center 

PSD Prevention of Significant Deterioration 

psia pound per square inch absolute 

PTI Permit to Install 

RACT Reasonably Available Control Technology 

RBLC RACT/BACT/LAER Clearinghouse 

scf standard cubic feet 

SCR selective catalytic reduction 

SIL Significant Impact Level 

SIP State Implementation Plan 

SO2 sulfur dioxide 

SO3 sulfur trioxide 

SO4 sulfate 

STG steam turbine generator 

TES Toledo Environmental Services 

TLV threshold limit value 

tpy tons per year 
Table of Contents Page ix 

Oregon Clean Energy Center 

 Lucas County, OH 

PSD Permit Application 

TSP total suspended particulates 

ULSD ultra low sulfur diesel 

USEPA United States Environmental Protection Agency 

VCAPCD Ventura County Air Pollution Control District 

VOC volatile organic compounds 
Introduction Page 1-1 

PSD Permit Application 

Oregon Clean Energy Center 

 Lucas County, OH 

1. INTRODUCTION

1.1 Project Overview 

Oregon Clean Energy, LLC (OCE) is proposing to construct the Oregon Clean Energy 

Center, a nominal 800-megawatt (MW) combined cycle gas turbine (CCGT) facility (the 

Project). The Project will utilize combined cycle combustion turbine technology in a 2 x 2 x 

1 configuration. Accordingly, the major equipment will include two combustion turbine 

generators (CTGs), two supplementary-fired heat recovery steam generators (HRSGs), 

one steam turbine generator (STG), a mechanical draft wet cooling tower, and associated 

auxiliary and balance of plant equipment and systems. The Project is anticipated to be 

fired with natural gas; no oil backup is proposed. Where necessary, ancillary equipment 

utilizing fuel oil will utilize ultra-low sulfur (0.0015%) diesel (ULSD) fuel. The Project is 

intended to operate as a base load facility and is proposing to be available to operate up to 

8,760 hours per year, incorporating a range of load conditions. The Project seeks the 

flexibility to operate with frequent starts in order to meet energy demand (anticipating 

potential operation for 16 hours per day, five days per week). 

OCE proposes to construct the Project within an approximately 30-acre parcel of land 

located entirely within Lucas County in the city of Oregon, Ohio. The site is industrially 

zoned within the Cedar Point Development Park, a designated Foreign Trade Zone. Its 

setting is within a mixed industrial, commercial and agricultural area that is located east 

of Lallendorf Road, west of farmland located at 4632 Cedar Point Road, north of the 

Norfolk Southern Railroad, and south of the John Gradel and Sons’ Farms. Access to 

the Site is via Lallendorf Road. The western edge of the site is transected by Johlin 

Ditch, while a tributary of Driftmeyer Ditch transects the eastern portion of the site. Both 

ditches flow north to Lake Erie, located less than 2 miles north of the site. FirstEnergyowned transmission lines extend in an east-west direction just to the north of the site. 

Air emissions from the proposed Project primarily consist of products of combustion from 

the combustion turbines, HRSG duct burners, and ancillary equipment. Pollutants that are 

regulated under federal and Ohio programs, such as Prevention of Significant 

Deterioration (PSD), include carbon monoxide (CO), nitrogen dioxide (NO2), sulfur dioxide 

(SO2), total suspended particulates (TSP), particulate matter with a diameter equal to or 

less than 10 microns (PM10), particulate matter with a diameter equal to or less than 2.5 

microns (PM2.5), volatile organic compounds (VOC), greenhouse gases (GHGs), lead (Pb), 

sulfuric acid mist (H2SO4), and air toxics. Potential emissions from the proposed Project, 

on a tons per year (tpy) basis, are presented in Table 1-1. 
Introduction Page 1-2 

PSD Permit Application 

Oregon Clean Energy Center 

 Lucas County, OH 

 

Table 1-1: Summary of Proposed Potential Emissions and Applicable Regulatory Thresholds 

Pollutant 

Annual 

Emissions 

(tpy) 

PSD 

Major Source 

Threshold (tpy) 

PSD Significant 

Emission Rate 

(tpy) 

PSD Applies? 

(Yes/No) 

NOx 210.4 100 40 a Yes 

VOC 120.7 100 40 Yes 

CO 178.2 100 100 Yes 

PM10 173.0 100 15 Yes 

PM2.5 173.0 100 10 Yes 

SO2 40.6 100 40 Yes 

H2SO4 21.6 100 7 Yes 

GHGsb 3,287,836 100,000 75,000 Yes 

Pb 0.00005 10 0.6 No 

a. PSD significant emission rate for NO2. 

b. GHGs are expressed as CO2. 

1.2 Regulatory Overview 

The Project will include emissions control technology that will reflect Best Available Control 

Technology (BACT) and Best Available Technology (BAT), as applicable. In addition to 

the use of clean-burning natural gas, emissions of nitrogen oxides (NOx) will be controlled 

with selective catalytic reduction (SCR). Emissions of CO and VOC will be controlled with 

oxidation catalyst systems. 

1.3 Application Overview 

1.3.1 Application Organization 

This permit application is divided into five sections. Section 2 provides a detailed 

description of the proposed Project, including a facility description and estimated 

emissions. Section 3 provides a review of regulations applicable to the proposed Project. 

Section 4 provides the BACT/BAT control technology evaluations. Section 5 provides a 
Introduction Page 1-3 

PSD Permit Application 

Oregon Clean Energy Center 

 Lucas County, OH 

list of references. The air quality modeling analysis for the Project will be provided in a 

separate report. 

A printout of the information submitted to the Toledo Environmental Services (TES) via the 

Ohio Environmental Protection Agency (Ohio EPA) Air Services eBusiness Center is 

included as Appendix A. Emission calculation spreadsheets providing supporting 

calculations for the application are provided in Appendix B. Appendix C presents 

summary tables supporting the BACT/BAT analysis. 

1.3.2 Application Contacts 

To facilitate agency review of this application, individuals familiar with the Project and this 

application are identified below. 

William J. Martin 

Oregon Clean Energy, LLC 

20 Park Plaza, Suite #471 

Boston, MA 02116 

Phone: 617-945-2165 

Email: wmartin@cme-energy.com 

Lynn Gresock 

ARCADIS 

One Executive Drive, Suite 303 

Chelmsford, MA 01824 

Phone: 978-322-4520 

e-mail: lynn.gresock@arcadis-us.com
Project Description Page 2-1 

PSD Permit Application 

Oregon Clean Energy Center 

 Lucas County, OH 

2. PROJECT DESCRIPTION

2.1 Overview 

OCE proposes development of a nominal 800-MW electric generating facility at an 

industrially zoned site in the city of Oregon, Ohio. Figure 1 presents the proposed Project 

location on a topographic map. The facility will include the following major and ancillary 

equipment: 

 Two CTGs; 

 Two HRSGs with supplemental duct firing; 

 One STG; 

 One mechanical draft wet cooling tower; 

 One 1,500-kilowatt (kW) emergency diesel generator; 

 One natural gas-fired, 90-million British thermal units (MMBtu) steam production 

auxiliary boiler; and 

 One 250-horsepower (hp) fire pump. 

The Project will be fueled by clean-burning natural gas to be provided by a new natural 

gas pipeline lateral connection from the nearby natural gas networks of 

NiSource/Columbia Gas or ANR Pipeline/TransCanada. Electrical interconnection will be 

to the 345-kilovolt (kV) FirstEnergy transmission line, located just north of the site. 

Steam condenser cooling will utilize a 12-cell mechanical draft wet cooling tower system 

with average consumptive water use of 6 - 7 million gallons per day. A combination of 

treated effluent and/or raw water from the city of Oregon is being considered for process 

use. Discharge of wastewater is anticipated to be to the Oregon sanitary sewer system for 

treatment at the wastewater treatment plant, located within 1 mile of the site. 

2.2 Site Location 

The proposed site consists of an irregularly shaped parcel of land, totaling approximately 

30 acres, located entirely within Lucas County in the city of Oregon, Ohio. The site is 

industrially zoned within the Cedar Point Development Park, a designated Foreign Trade 

Zone. Its setting is within a mixed industrial, commercial and agricultural area that is 

located east of Lallendorf Road, west of farmland located at 4632 Cedar Point Road, 

north of the Norfolk Southern Railroad, and south of the John Gradel and Sons’ Farms. 
Project Description Page 2-2 

PSD Permit Application 

Oregon Clean Energy Center 

 Lucas County, OH 

Access to the site is via Lallendorf Road. The western edge of the site is transected by 

Johlin Ditch, while a tributary of Driftmeyer Ditch transects the eastern portion of the site. 

Both ditches flow north to Lake Erie, located less than 2 miles north of the site. 

FirstEnergy-owned transmission lines extend in an east-west direction just to the north of 

the site. 

The site consists of farmland with associated structures, including two single-family 

dwellings, a garage and a barn. The majority of the parcel is in active agricultural use. 

Site topography is relatively flat, at an elevation of approximately 590 feet above mean 

sea level. The Maumee River, which flows southwest to northeast to its confluence with 

Lake Erie, is situated approximately 2 miles northwest of the site. 

The Project is located approximately 2 miles south of First Energy’s existing Bay Shore 

coal-fired power plant on Lake Erie. British Petroleum’s (BP’s) expansive Toledo 

Refinery is located less than 0.5 mile to the north, beyond the electric transmission 

corridor. Land uses east and southeast of the site are primarily agricultural, with some 

residences along the roads which divide the land in a grid-like fashion. A cluster of 

commercial/industrial uses border the site to the south-southwest, including several 

manufacturing and warehouse facilities, among them, Fresenius Medical Care (a 

manufacturer of dialysis machines) and Caraustar (a manufacturer of gypsum facing 

paper and spiral-wound paper tubes). More densely developed residential areas are 

located about a mile southwest of the site. 

Pearson Park is located approximately 1.5 miles south of the site, Collins Park is 1.5 

miles west-southwest of the site, and Maumee Bay State Park is approximately 2 miles 

east-northeast of the site. Further east-northeast, along the shore of Lake Erie, are 

Mallard Club Wilderness Area and Cedar Point National Wildlife Refuge. 

2.3 Combined Cycle Combustion Turbines 

The Project’s major equipment will include two CTGs, two supplementary-fired HRSGs, 

one STG, and a 12-cell mechanical draft wet cooling tower. This equipment is described in 

more detail below. The information provided in this application are based upon a Siemens 

“F” class CTG, or equivalent. 

2.3.1 Combustion Turbine Generators 

Thermal energy will be produced in the two CTGs through the combustion of natural gas 

as the sole fuel. Each CTG is capable of running independently of the other. The thermal 
Project Description Page 2-3 

PSD Permit Application 

Oregon Clean Energy Center 

 Lucas County, OH 

energy is converted to mechanical energy in the CTG turbine that drives the CTG 

compressor and electric generator. The maximum heat input rate of each CTG for 100 

percent load at International Organization for Standards (ISO) temperature (59 degrees 

Fahrenheit [°F]), relative humidity of 71 percent and a site pressure of 14.5 pounds per 

square inch absolute (psia) is 2,266 MMBtu per hour (MMBtu/hr) at the higher heating 

value (HHV) for natural gas. 

2.3.2 Heat Recovery Steam Generators and Duct Burners 

In the combined cycle configuration, each CTG will exhaust through a dedicated HRSG to 

generate steam from the waste heat energy in the exhaust gas. Each HRSG will be 

equipped with supplemental fuel firing via a duct burner. The duct burners provide 

additional energy to the HRSG, to provide more steam to the STG during periods of high 

demand. The duct burners will be natural gas fired and each will have a maximum input 

capacity of 841 MMBtu/hr (HHV), although the duct burners will not always operate at 

maximum capacity. The use of the duct burner will vary based upon different temperature 

and operating conditions. 

2.3.3 Steam Turbine Generator 

Steam generated in the HRSGs will be expanded through a STG multi-stage, reheat, 

condensing turbine and associated electric generator to generate additional electricity. 

2.3.4 Cooling Tower 

The steam condenser cooling will utilize a 12-cell mechanical draft wet cooling tower 

system. In the cooling tower, circulating water is distributed among multiple cells of the 

cooling tower, where it cascades downward through each cell and then collects in the 

cooling tower basin. The mechanical draft cooling tower employs electric motor-driven 

fans to move air through each cooling tower cell. The cascading circulating water is 

partially evaporated and the evaporated water is dispersed to the atmosphere as part of 

the moist air leaving each cooling tower cell. The circulating water is cooled primarily 

through its partial evaporation. The cooling tower will be equipped with a high-efficiency 

drift eliminator with an efficiency of 0.0005 percent. 

2.4 Air Pollution Control Equipment 

The emission control technologies proposed for the combustion turbine and duct burner 

exhaust gases include dry low-NOx (DLN) combustors which are integrated within the 
Project Description Page 2-4 

PSD Permit Application 

Oregon Clean Energy Center 

 Lucas County, OH 

combustion turbines, and SCR systems and oxidation catalysts which are located within 

each HRSG to control NOx, CO and VOC emissions. The DLN combustion controls NOx

formation by pre-mixing fuel and air immediately prior to combustion. Pre-mixing inhibits 

NOx formation by minimizing both the flame temperature and the concentration of oxygen 

at the flame front. The SCR systems further control NOx emissions, while the oxidation 

catalysts control emissions of CO and VOC. Emissions of SO2, PM10/PM2.5, and H2SO4

will be minimized through the exclusive use of pipeline quality natural gas in the 

combustion turbines. The SCR and oxidation catalyst are discussed further in the sections 

below. 

2.4.1 Selective Catalytic Reduction 

SCR, a post-combustion chemical process, will be installed in the HRSGs to treat exhaust 

gases downstream of the CTGs. The SCR process will use 19 percent aqueous ammonia 

(NH3) as a reagent. Aqueous NH3 will be injected into the flue gas stream, upstream of the 

SCR catalyst, where it will mix with NOx. The catalyst bed will be located in a temperature 

zone of the HRSG where the catalyst is most effective. The mixture will pass over the 

catalyst and the NOx will be reduced to nitrogen gas (N2) and water (H2O). The SCR 

system will reduce NOx concentrations to 2.0 parts per million by volume (ppmv) at 15 

percent oxygen (O2) with or without duct firing at all load conditions and ambient 

temperatures. A small amount of NH3 will remain un-reacted through the catalyst, which is 

called the “ammonia slip.” The NH3 slip will be limited to 5.0 ppmv at all load conditions 

and ambient temperatures. 

2.4.2 Oxidation Catalyst 

An oxidation catalyst system will be located within each HRSG to control emissions of CO 

and VOC. Exhaust gases from the turbines will be passed over a catalyst bed where 

excess air will oxidize the CO and VOC to form carbon dioxide (CO2) and H2O. The 

oxidation catalyst system will reduce CO concentrations to 2.0 ppmv (at 15% O2) in the 

exhaust gas under all load conditions and ambient temperatures. The oxidation catalyst 

will also reduce VOC emissions, to between 1.0 ppm to 3.5 ppm, depending on the 

amount of supplemental duct firing. 

2.5 Ancillary Equipment 

The proposed Project will utilize a variety of ancillary equipment to support the facility 

including an auxiliary boiler, an emergency generator, an emergency fire pump, and 

storage tanks. This equipment is discussed further in the sections below. 
Project Description Page 2-5 

PSD Permit Application 

Oregon Clean Energy Center 

 Lucas County, OH 

2.5.1 Auxiliary Boiler 

An auxiliary boiler will operate as needed to keep the HRSG warm during periods of 

turbine shutdown and provide sealing steam to the steam turbine during warm and hot 

starts. The auxiliary boiler will have a maximum input capacity of 90 MMBtu/hr. 

2.5.2 Emergency Diesel Generator 

The Project will have a 1,500-kW emergency diesel generator to provide on-site 

emergency power capabilities independent of the utility grid. The emergency generator 

will fire ULSD fuel and will typically only operate for testing and to maintain operational 

readiness in the event of an emergency. Routine operation of the generator will be limited 

to a maximum of 500 operating hours per year. 

2.5.3 Emergency Diesel Fire Pump 

The Project will have an emergency fire pump to provide on-site fire fighting capabilities 

independent of the utility grid. The emergency fire pump will fire ULSD fuel and will 

typically only operate for testing and to maintain operational readiness in the event of an 

emergency. Similar to the emergency generator, it will be limited to a maximum of 500 

operating hours per year. 

2.5.4 Aqueous NH3 Storage Tank 

The proposed facility will have tanks that will store 19 percent aqueous NH3 for use in the 

SCR system. The tanks will be equipped with secondary containment sized to 

accommodate the entire volume of one tank and sufficient freeboard for precipitation. The 

tanks will be located outdoors within an impermeable containment area, surrounded by a 

wall. The floor of the containment area will be covered with plastic balls designed to float 

on the liquid surface in the event of a spill, thereby reducing the exposed surface area, and 

minimizing potential emissions. 

2.6 Emissions Estimates 

The combined cycle units will typically operate at or near full load capacity to respond to 

electricity demands as needed. However, depending upon the demand, each unit can 

operate at loads ranging from approximately 50 percent turbine load without 

supplemental duct firing to 100 percent load with supplemental duct firing (full capacity). 

The emissions provided in this application are based upon 100 percent load steady state 
Project Description Page 2-6 

PSD Permit Application 

Oregon Clean Energy Center 

 Lucas County, OH 

operation of a Siemens “F” Class turbine, or equivalent. Combustion turbine 

performance and emissions are affected by ambient conditions: humidity, pressure and 

temperature; with turbine fuel consumption, power output and emissions increasing at 

lower ambient temperatures. Supplemental duct firing performance and emissions are 

affected indirectly by ambient conditions, with fuel consumption, heat output and 

emissions increasing at higher ambient temperatures. As the combustion turbine 

decreases heat output to the HRSG at higher ambient temperatures, the supplemental 

duct firing increases to make up the loss of heat output to maintain maximum steam 

production to the steam turbine. 

Table 2-1 presents a summary of the proposed limits for pollutants emitted from 

combined cycle combustion turbines at steady state full load operation. The limits 

incorporate BACT/BAT as applicable (Section 4.0). 

Table 2-1: Summary of Proposed Emission Limits for Combined Cycle Combustion 

Turbines (Steady State Full Load Operation)a

Pollutant Case 

Emission Rate 

(lb/MMBtu)b

Emission Rate 

(ppmv)

c

NOx CT Only 

CT with DBd

0.0076 

0.0077 

2.0 

2.0 

VOC CT Only 

CT with DB 

0.0013 

0.0048 

1.0 

3.5 

CO CT Only 

CT with DB 

0.0048 

0.0048 

2.0 

2.0 

PM10/PM2.5 CT Only 

CT with DB 

0.0049 

0.0065 

n/a 

n/a 

SO2 CT Only 

CT with DB 

0.0015 

0.0015 

n/a 

n/a 

H2SO4 CT Only 

CT with DB 

0.0008 

0.0008 

n/a 

n/a 

a. Facility may exceed these limits during defined periods of startup and shutdown. 

b. Emission rates are based on HHV of natural gas. 

c. Concentrations are ppmv at 15% O2. 

d. Duct burner. 

Because of the different emission rates and exhaust characteristics, a matrix of 

operation modes, including partial load operation, will be evaluated in the OCE 

Dispersion Modeling Report. 
Project Description Page 2-7 

PSD Permit Application 

Oregon Clean Energy Center 

 Lucas County, OH 

Combined cycle start-up and shutdown scenarios are also addressed in this air permit 

application. Emissions during start-up and shutdown may, for some pollutants, result in 

an increase in short term (pounds per hour [lb/hr]) emission rates. There is a minimum 

turbine downtime and maximum duration associated with each type of start-up. There is 

also a maximum duration associated with each shutdown. Potential annual emissions 

estimates for the proposed Project include emissions from start-up and shutdown. 

The following sections provide estimated emissions from the combined cycle combustion 

turbines and from the facility’s ancillary equipment. Emissions of air contaminants from 

this equipment have been estimated based upon vendor emission guarantees, United 

States Environmental Protection Agency (USEPA) emission factors, mass balance 

calculations and engineering estimates. 

2.6.1 Combined Cycle Combustion Turbine Emissions – Steady State Operation 

Table 2-2 presents short term (lb/hr) emissions estimates from each combined cycle 

turbine under ISO conditions at 100 percent load conditions including duct burner 

operations. These emissions were developed from vendor estimates. The PM10/PM2.5

emissions estimates include filterable and condensable particulate matter and an 

allowance for sulfate and/or ammonia salt formation due to the reaction of sulfur trioxide 

(SO3) with H2O and/or excess NH3 in the SCR and oxidation catalyst systems. Emission 

rates for all base load operating conditions are provided in Appendix B. 

Potential non-criteria pollutant emissions from the operation of the combustion turbines 

and ancillary equipment were estimated using AP-42 emission factors (USEPA, 2000) with 

the following exceptions. Emissions of formaldehyde from the combustion turbine 

generators were estimated using an emission factor from a California Air Resource Board 

(CARB) database. The California Air Toxics Emission Factor (CATEF) database contains 

air toxics emission factors calculated from source test data collected for California’s Air 

Toxics Hot Spots Program (CARB, 1996). Emissions of hexane from the duct burner and 

the auxiliary boiler were estimated using an emission factor from the Ventura County Air 

Pollution Control District (VCAPCD, 2001). In both cases, the AP-42 emission factors had 

a very low emission factor rating and were not considered representative of the proposed 

equipment. The CARB and VCAPCD emission factors are considered more appropriate 

for the advanced technology of the combustion turbines. Potential emissions of 

Hazardous Air Pollutants (HAPs) and Ohio EPA air toxics from operation of the 

combustion turbines and duct burners are also provided in Appendix B. 
Project Description Page 2-8 

PSD Permit Application 

Oregon Clean Energy Center 

 Lucas County, OH 

Table 2-2: Summary of Short Term Emission Rates for a Single Combustion 

Turbinea

Pollutant 

100% Load 

with Duct Burning 

(lb/hr) 

100% Load 

without Duct Burning 

(lb/hr) 

NOx 23.0 17.0 

VOC 13.0 3.0 

CO 14.0 10.0 

PM10/PM2.5 19.0 11.0 

SO2 4.6 3.4 

H2SO4 2.5 1.8 

NH3 21.0 16.0 

a. Emissions presented in table are for ISO conditions. These may not represent worstcase conditions for air quality dispersion modeling. Appropriate worst-case 

conditions will be used for these analyses in the Dispersion Modeling Report. 

2.6.2 Combined Cycle Combustion Turbine Emissions – Start-up and Shutdown Operations 

Potential emissions associated with start-up and shutdown of the combustion turbines 

were developed using vendor supplied information. Table 2-3 presents the emissions and 

downtimes (minimum number of hours the turbines would be off before a re-start) 

associated with startup and shutdown events for the combined cycle turbines. In most 

cases, emissions from these events are “self correcting” on an annual basis. In other 

words, the average hourly emissions for each startup event (including downtime) are less 

than the corresponding steady state emission rate for the minimum downtime that would 

precede a start. Table 2-3 identifies the pollutants that are self-correcting for each event. 

Permitted annual emission limits for the facility incorporates those conditions that are not 

considered self-correcting. Table 2-4 presents the average hourly emission rates 

associated with each start-up/shutdown event. These emission rates incorporate the 

minimum downtime that would precede each event. These average hourly rates were 

used to determine if the event was considered self-correcting compared to steady state 

emission rates. Emissions of SO2 will always be self-correcting because SO2 emissions 

are dependent upon the amount of fuel burned, and steady state is always worst-case. 
Project Description Page 2-9 

PSD Permit Application 

Oregon Clean Energy Center 

 Lucas County, OH 

Table 2-3: Emissions and Downtimes Associated with Start-up and Shutdown 

Events 

Cold 

Startup 

Hot 

Startup 

Warm 

Start-up Shutdown 

Number of Events per Year 50 250a

 0 300 

Minimum Downtime 

Preceding Event (hrs)b 64 2 16 1 

Duration of Event (min)c 178 80 88 42 

 Emissions Per Event (lb)d

PM10/PM2.5 24 12 14 6 

NOx 76 64 67 32 

CO 253 130 130 80 

VOC 63 51 52 31 

 Self-Correcting 

PM10/PM2.5 Yes Yes Yes Yes 

NOx Yes Yes Yes Yes 

CO Yes No Yes No 

VOC Yes No Yes No 

a. Total hot start and warm start emissions are 250 starts. 

b. hours 

c. minutes 

d. pounds 

Table 2-4: Average Hourly Emissions for Start-up and Shutdown Events 

(including downtime) 

Pollutant Cold Startup 

(lb/hr) 

Hot Startup 

(lb/hr) 

Warm Start-up 

(lb/hr) 

Shutdown 

(lb/hr) 

PM10/PM2.5 0.36 3.60 0.80 3.65 

NOx 1.13 19.20 3.84 18.82 

CO 3.78 39.00 7.44 47.06 

VOC 0.94 15.30 2.98 18.24 
Project Description Page 2-10 

PSD Permit Application 

Oregon Clean Energy Center 

 Lucas County, OH 

2.6.3 Ancillary Equipment 

This section presents estimated criteria pollutant emissions from the ancillary equipment at 

the facility. The proposed ancillary equipment includes one auxiliary boiler, one 

emergency generator, one emergency fire pump, and the cooling tower. The following 

assumptions were used in evaluating emissions from this equipment: 

 The natural gas-fired auxiliary boiler will have a maximum input capacity of 90.0 

MMBtu/hr with unlimited hours of operation per year. 

 The diesel-fired emergency fire pump will have a maximum heat input of 1.3 

MMBtu/hr (9.3 gallons per hour) and will be limited to 500 hours of operation per 

year. 

 The diesel-fired emergency generator will have a maximum heat input of 14.1 

MMBtu/hr (101 gallons per hour) and will be limited to 500 hours of operation per 

year. 

 The cooling tower is expected to have a recirculating flow rate of 133,700 gallons 

per minute and 3,000 milligrams per liter (mg/l) of TDS. 

Criteria pollutant emissions from the ancillary equipment were estimated based on 

vendor supplied information except for SO2 emissions from the emergency equipment, 

which are based on a mass balance assuming ULSD. PM10/PM2.5 emissions from the 

cooling tower are based upon design values and conservatively assume five cycles of 

concentration. The cooling tower will utilize a high efficiency drift eliminator. 

Tables 2-5 and 2-6 summarize estimated short-term (lb/hr) and annual emissions of 

criteria pollutants from the ancillary equipment. Supporting calculations are located in 

Appendix B. 

 
Project Description Page 2-11 

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Oregon Clean Energy Center 

 Lucas County, OH 

Table 2-5: Short-Term Potential Emissions from Ancillary Equipment 

Pollutant Auxiliary Boiler 

(lb/hr) 

Emergency Fire 

Pump 

(lb/hr) 

Emergency 

Generator 

(lb/hr) 

Cooling Tower

(lb/hr) 

PM10 0.45 0.08 0.66 1.00 

PM2.5 0.45 0.08 0.66 1.00 

SO2 0.06 0.003 0.021 -- 

NOx 0.90 1.44 18.53 -- 

CO 3.33 1.44 11.56 -- 

VOC 0.36 0.20 2.62 -- 

Pb 0.00 0.00002 0.0002 -- 

Table 2-6: Potential Annual Emissions from Ancillary Equipment 

Pollutant 

Auxiliary 

Boiler 

(tpy) 

Emergency 

Fire Pump 

(tpy) 

Emergency 

Generator 

(tpy) 

Cooling 

Tower 

(tpy) 

Total 

(tpy) 

PM10 1.97 0.021 0.17 4.4 6.56 

PM2.5 1.97 0.021 0.17 4.4 6.56 

SO2 0.28 0.0007 0.005 -- 0.29 

NOx 3.94 0.36 4.63 -- 8.93 

CO 14.59 0.36 2.89 -- 17.84 

VOC 1.58 0.05 0.65 -- 2.28 

Pb 0.00 0.000006 0.00005 -- 0.00006 

HAP emissions will be less than major source thresholds, less than 10 tpy for any 

individual HAP and 25 tpy for total HAPs. 

2.6.4 Potential Annual Emissions 

Potential annual emissions from the proposed facility were estimated using the following 

worst-case assumptions: 
Project Description Page 2-12 

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Oregon Clean Energy Center 

 Lucas County, OH 

 Full load operation of the combustion turbines (at 59°F ambient temperature); 

 Duct burning for 8,760 hours per year during steady state operation of each 

combustion turbine; 

 Incorporation of start-up/shutdown events as described in Section 2.6.2; for 

start-up/shutdown events that are not self correcting, a total of 300 combined 

start-up events per year and 300 shutdown events per year were assumed (see 

Table 2-3); and 

 Incorporation of emissions from ancillary equipment as discussed in Section 

2.6.3 (see Table 2-6). 

Potential annual emissions for the proposed Project are summarized in Table 2-7. 

Table 2-7: Summary of Annual Potential Emissions 

Pollutant 

Combustion 

Turbines 

(tpy) 

Ancillary 

Equipment 

(tpy) 

Total 

(tpy) 

PM10 166.4 6.6 173.0 

PM2.5 166.4 6.6 173.0 

SO2 40.3 0.3 40.6 

NOx 201.5 8.9 210.4 

CO 160.3 17.8 178.2 

VOC 118.5 2.3 120.7 

H2SO4 21.6 0.02 21.6 

NH3 184.0 0.0 184.0 

Pb 0.0 0.00006 0.00006 

.
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 Lucas County, OH 

3. REGULATORY APPLICABILITY EVALUATION

OCE is requesting approval to construct a nominal 800-MW combined cycle electric 

generating facility in the city of Oregon, Lucas County, Ohio. The Project is considered a 

new major stationary combustion source under PSD regulations because the potential 

annual emissions from the facility exceed major source thresholds as illustrated in 

Table 1-1. 

This section contains an analysis of the applicability of federal and state air quality 

regulations to the proposed Project. The specific regulations and programs that are 

included in this review include: 

 PSD New Source Review; 

 Federal New Source Performance Standards (NSPS); 

 Federal National Emission Standards for Hazardous Air Pollutants (NESHAP); 

 Federal Acid Rain Program; 

 Other Ohio EPA requirements; and 

 Accidental Release requirements. 

3.1 PSD New Source Review 

Combined cycle power plants with potential emissions greater than 100 tpy of one or more 

criteria pollutants are considered new major stationary sources under the PSD program. 

As shown in Table 1-1, the potential emissions of at least one regulated criteria pollutant 

will exceed this threshold. As such, the proposed facility is subject to PSD New Source 

Review. Under the PSD regulations, once a major source threshold is triggered, PSD 

review must be completed for all pollutants whose potential emissions exceed their 

Significant Emission Rate increase. 

On April 2, 2007, the U.S. Supreme Court found that GHGs, including CO2, are air 

pollutants covered by the Clean Air Act (CAA). On May 13, 2010, the USEPA issued a 

final rule (called the “Tailoring Rule”) that establishes an approach to GHG emissions from 

stationary sources under the CAA. This final rule “tailors” the requirements of the CAA 

permitting program to limit which facilities will be required to obtain PSD permits. The CAA 

permitting program emissions thresholds for criteria pollutants are 100 tpy or 250 tpy, 

depending on the source category. While these thresholds are appropriate for criteria 
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Oregon Clean Energy Center 

 Lucas County, OH 

pollutants, they are not feasible for GHG emissions as they are emitted in much greater 

quantities. USEPA will phase in the CAA permitting requirements in two phases: 

 Only sources already subject to the PSD program (i.e., new major sources such 

as the OCE Project) are subject to permitting requirements for their GHG 

emissions under PSD. For these projects, those with GHG emission increases of 

75,000 tpy or greater are required to determine BACT for their GHG emissions. 

This phase began on January 2, 2011. 

 In the second phase, PSD permitting requirements will cover new construction 

projects that exceed 100,000 tpy of GHG emissions, even if they do not exceed 

any other permitting thresholds. This began on July 1, 2011. 

As presented in Table 1-1, the Project has triggered major source thresholds for GHGs. In 

addition, PSD review is required for NOx, CO, VOC, SO2, H2SO4 and PM10/PM2.5

emissions. 

PSD review requirements include application of BACT, an ambient air quality modeling 

analysis demonstrating compliance with NAAQS and PSD increments, and an additional 

impacts analysis. Ohio EPA has been delegated PSD review authority by USEPA. For an 

air contaminant subject to BACT, compliance with BACT requirements also represents 

Ohio EPA BAT. 

3.1.1 Best Available Control Technology 

Pollutants subject to PSD review are required to apply BACT for control of emissions of 

PSD pollutants. BACT is defined as an emission limitation based on the maximum degree 

of reduction, on a case-by-case basis, taking into account energy, environmental and 

economic considerations. In establishing the final BACT limit, USEPA may consider any 

new information, including recent permit decisions, subsequent to submittal of a complete 

application. The BACT analyses for NOx, CO, VOC, SO2, H2SO4 and PM10/PM2.5 are 

presented in Section 4.0. 

3.1.2 Air Quality Impact Analysis 

An ambient air quality analysis must be performed to demonstrate compliance with 

NAAQS and PSD increments. Proposed new sources subject to PSD review may not 

cause or significantly contribute to a violation of the NAAQS. As part of this 

demonstration, the USEPA has established Significant Impact Levels (SILs) for all of the 

criteria pollutants. SILs represent concentrations of pollutants that are considered to be 
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Oregon Clean Energy Center 

 Lucas County, OH 

insignificant with respect to demonstration of NAAQS compliance. By definition, proposed 

new sources whose air quality impacts are less than SILs neither cause nor significantly 

contribute to NAAQS violations. Proposed new sources whose air quality impacts exceed 

the SILs must complete a cumulative analysis taking into consideration existing 

background air quality levels and contributions from other sources. 

The air quality impact analysis for the Project will be included in the OCE Dispersion 

Modeling Report. 

3.1.3 PSD Class I Area Impact Analysis 

PSD regulations require that proposed major sources within 100 kilometers (km) of a PSD 

Class I area perform an assessment of potential impacts in the PSD Class I area. PSD 

Class I areas are specifically designated areas of special national or regional value from a 

natural, scenic, recreational or historic perspective. These areas are administered by the 

National Park Service, U.S. Fish and Wildlife Service, or the U.S. Forest Service. These 

Federal Land Managers (FLMs) are responsible for evaluating proposed projects’ air 

quality impacts in the Class I areas and may make recommendations to the permitting 

agency to approve or deny permit applications. 

PSD Class I area impact analyses consist of: 

 An air quality impact analysis; 

 A visibility impairment analysis; and 

 An analysis of impacts on other air quality related values (AQRVs) such as 

impacts to flora and fauna, water, and cultural resources. 

There are no PSD Class I areas within 100 km of the proposed Project site. The nearest 

PSD Class I Areas are the Otter Creek and Dolly Sods Wilderness Areas in West Virginia, 

and the Mammoth Cave National Park in Kentucky. These PSD Class I areas are located 

over 250 miles from the Project. 

Ohio EPA recommends that a screening formula be used to determine if a Class I Area is 

close enough to warrant analysis. The screening formula, which is found in The Federal 

Land Managers AQRV Workgroup (FLAG) Phase I Report – Revised (FLAG 2010) is 

provided below: 

 
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Oregon Clean Energy Center 

 Lucas County, OH 

A PSD Class I area analysis is not required if Q (tpy)/d (km) < 10, 

where: 

Q = the combined emissions increase from a source of SO2, NOx, PM10, and 

H2SO4 in tpy based on 24-hour maximum allowable emissions (which are 

annualized); and 

d = the nearest distance (km) to a Class I area from the source. 

Table 3-1: “Q/d” Screening Analysis for OCE for Class I Areas 

Class I 

Area 

d, 

Distance 

to Class I 

Area 

(km) 

SO2

Emissions 

(tpy) 

NOx

Emissions 

(tpy) 

PM10

Emissions 

(tpy) 

H2SO4

Emissions 

(tpy) 

Q, Total 

Emissions 

(tpy) 

Q/d 

(tpy/km) 

Otter Creek 439.0 40.6 210.4 173.0 21.6 445.6 1.0 

Dolly Sods 457.0 40.6 210.4 173.0 21.6 445.6 1.0 

Mammoth 

Cave 548.0 40.6 210.4 173.0 21.6 445.6 0.8 

Table 3-1 presents results of the screening calculation performed in accordance with the 

screening formula. The calculations show that “Q/d” is below 10 for the nearest Class I 

areas to the proposed source. Accordingly, based on the level of proposed emissions from 

the Project, the distances to the nearest PSD Class I areas, and the screening calculation 

above, a PSD Class I impact analysis is not required for the Project. 

3.1.4 Additional Impact Analyses 

Additional impact analyses are also required as part of PSD review and Ohio EPA 

regulations. These additional analyses include an assessment of impacts on community 

growth resulting from the Project, an assessment of visibility impairment and an 

assessment of impacts to soils and vegetation. These impact analyses will be presented 

in the OCE Dispersion Modeling Report. 

Federal actions, such as the issuance of PSD permits (in this case, delegated to the state), 

require review and consideration of the potential implications of a proposed project to 

endangered or threatened species and their habitats, as well as cultural resources. OCE 

will consult with applicable agencies to determine whether such resources will require 
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Oregon Clean Energy Center 

 Lucas County, OH 

specific consideration, and records of these communications will be provided in the OCE 

Dispersion Modeling Report. 

3.2 New Source Performance Standards 

NSPS are technology-based standards applicable to new and modified stationary sources. 

NSPS have been established for approximately 70 source categories. Based upon a 

review of these standards, several subparts are applicable to the proposed Project. The 

Project’s compliance with each of these standards is presented in the sections below. 

3.2.1 40 CFR 60 – Subpart A – General Provisions 

Any source subject to an applicable standard under 40 Code of Federal Regulations 

(CFR) 60 is also subject to the general provisions under Subpart A. Because the Project 

is subject to other Subparts of the regulation, the requirements of Subpart A will also apply. 

OCE will comply with the applicable notifications, performance testing, recordkeeping and 

reporting outlined in Subpart A. 

3.2.2 40 CFR 60 – Subpart KKKK – Stationary Combustion Turbines 

Subpart KKKK places emission limits on NOx and SO2 from new combustion turbines. The 

proposed combustion turbines and duct burners would be subject to this standard. For 

new combustion turbines firing natural gas with a rated heat input greater than 850 

MMBtu/hr, NOx emissions are limited to: 

 15 ppmv at 15 percent O2; or 

 54 nanograms per Joule (ng/J) of useful output (0.43 pounds per megawatt-hour 

[lb/MW-hr]). 

Additionally, SO2 emissions must meet one of the following: 

 Emissions limited to 110 ng/J (0.90 lb/MW-hr) gross output; or 

 Emissions limited to 26 ng/J (0.060 lb/MMBtu). 

As described in Section 2.0, the proposed Project will use an SCR system to reduce NOx

emissions to 2 ppmv at 15 percent O2 and pipeline natural gas to limit SO2 emissions to 

0.0015 lb/MMBtu. As such, the Project will meet the emission limits under Subpart KKKK. 
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Oregon Clean Energy Center 

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Additionally, the provisions of this Subpart require continuous monitoring of water-to-fuel 

ratio, but allow for the use of either a 40 CFR Part 60 or Part 75 certified NOx continuous 

emissions monitoring system (CEMS) in lieu of this requirement. OCE is proposing to use 

a 40 CFR Part 75 certified NOx CEMS, which will satisfy this requirement. 

3.2.3 40 CFR 60 – Subpart Dc – Small Industrial-Commercial-Institutional Steam Generating Units 

Subpart Dc is applicable to steam generating units with a maximum input capacity greater 

than 10 MMBtu/hr and less than 100 MMBtu/hr. The proposed auxiliary boiler has a 

maximum input capacity of 90 MMBtu/hr, and is, therefore, subject to the standard. For 

units combusting natural gas, the standard requires initial notifications at the start of 

construction and at startup. In addition, records must be maintained regarding the amount 

of fuel burned on a monthly basis; however, since natural gas is the only fuel burned in the 

proposed boiler, there are no specific reporting requirements to the USEPA under Subpart 

Dc. 

3.2.4 40 CFR 60 – Subpart IIII – Stationary Compression Ignition Internal Combustion Engines 

Subpart IIII is applicable to owners and operators of stationary compression ignition (CI) 

internal combustion engines that commence operation after July 11, 2005. Relevant to the 

proposed project, this rule applies to the emergency generator and emergency fire pump. 

For model year 2009 and later fire pump engines with a displacement less than 30 liters 

per cylinder and an energy rating between 300 and 600 hp, Subpart IIII provides the 

following emission limits: 

 4.0 grams per kilowatt-hour (g/kW-hr) (3.0 grams per horsepower-hour [g/hp-hr]) 

of VOC + NOx

 3.5 g/kW-hr (2.6 g/hp-hr) of CO 

 0.2 g/kW-hr (0.15 g/hp-hr) of particulate matter 

The Project will install a fire pump meeting these emission standards. 

To comply with Subpart IIII, the emergency generator must meet the emission standards 

for new non-road CI engines (Tier 2 or 3). Engines with a model year 2006 or later with a 

power rating of 560 kW (750 hp) or greater must meet the following limits: 

 
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Oregon Clean Energy Center 

 Lucas County, OH 

 6.4 g/kW-hr (4.8 g/hp-hr) of VOC + NOx

 3.5 g/kW-hr (2.6 g/hp-hr) of CO 

 0.2 g/kW-hr (0.15 g/hp-hr) of particulate matter 

The emergency generator associated with the proposed Project will be certified to meet 

non-road emission standards. 

3.3 State of Ohio Best Available Technology 

“Best available technology," or BAT, means any combination of work practices, raw 

material specifications, throughput limitations, source design characteristics, an 

evaluation of the annualized cost per ton of air pollutant removed, and air pollution 

control devices that have been previously demonstrated to the director of environmental 

protection to operate satisfactorily in this state or other states with similar air quality on 

substantially similar air pollution sources (Ohio Administrative Code [OAC] Rule 3745-

31-01 (T)). 

Ohio EPA has published several memoranda (inter-office communications) and 

engineering guides that explain the implementation of the BAT program. Under the BAT 

program, sources with pollutants meeting certain other standards also meet BAT. For 

pollutants subject to BACT requirements, BACT is presumed to meet BAT requirements. 

For pollutants subject to NSPS, compliance with NSPS represents BAT. If there is a 

Reasonably Available Control Technology (RACT) minimum limit anywhere in the state, 

BAT is determined to be at a minimum, equivalent to most stringent pollutant emission rate 

limit no matter where in the state the RACT limit applies. Where the above prescriptive 

approach is not applicable to a criteria pollutant, a case-by-case BAT determination may 

be conducted using a “top down” approach, similar to a BACT analysis. BAT for criteria 

pollutants is described in Section 4.0. 

For HAPs subject to Maximum Available Control Technology (MACT), compliance with 

MACT represents BAT. In addition, BAT is applied to any air toxic (non-criteria pollutant) 

for which there is no federal or state standard using Ohio EPA’s Air Toxics policy. Ohio 

EPA’s Air Toxic policy is contained in the guidance document titled “Option A – Review of 

New Sources of Air Toxics.” The guidelines are: 

 Determine if a threshold limit value (TLV) exists for the specific compound, which is 

emitted from the source. 

 
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Oregon Clean Energy Center 

 Lucas County, OH 

 Divide the TLV by ten to adjust the standard from the working population to the 

general public (TLV/10). 

 Adjust the standard to account for the duration of the exposure (operating hours of 

source) of “X” hours per day and “Y” days per week from 8 hours per day and 5 days 

per week. This formula is used to obtain the Maximum Acceptable Ground-Level 

Concentration (MAGLC) or Acceptable Incremental Impact: 

MAGLC

XY

TLV

X

TLV             Y5   x     x    4  8

10

 Compare the one-hour averaging time ambient pollutant emissions, predicted by an 

appropriate air dispersion model, with the corresponding MAGLC for compliance 

with the air toxic’s policy. 

A comprehensive list of air toxics to which the policy applies is contained in Appendix B of 

OAC Rule 3745-114. For these air toxics, Ohio EPA requires only those emitted above 

one ton per year to be subject to review. For the Project, the following air toxics will be 

subject to “Option A” review or require a BAT determination: ammonia; formaldehyde; 

toluene; xylene; and sulfuric acid. 

3.4 Operating Permit 

OAC Rule 3745-77 specifies that a facility with an annual potential to emit equal to or 

exceeding any of the following thresholds is required to obtain an Operating Permit from 

Ohio EPA: 

 CO – 100 tpy; 

 PM10 – 100 tpy; 

 TSP – 100 tpy; 

 SO2 – 100 tpy; 

 NOx – 100 tpy; 

 VOC – 100 tpy; 

 Pb – 10 tpy; 

 Any other contaminant, except CO2 – 100 tpy; 

 Any single HAP – 10 tpy; and 
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PSD Permit Application 

Oregon Clean Energy Center 

 Lucas County, OH 

 Combination of HAPs – 25 tpy. 

Potential NOx, CO, VOC, and PM10 emissions for the Project exceed the Title V Operating 

Permit applicability threshold, triggering the need to apply for the Operating Permit. The 

Project is also required to obtain an Operating Permit due to the combustion turbines 

being subject to New Source Performance Standards Subpart KKKK. 

An Operating Permit application is a comprehensive document that includes: potential to 

emit data for all sources across the facility; supporting information and calculations; control 

equipment data; a review of state and federal regulations; a description of proposed 

monitoring methods; fuel data; stack and vent information; a proposed compliance plan; 

proposed operating hours; and descriptions of normal source operation and startup and 

shutdown conditions for each source at the facility along with emissions data for those 

operating modes. Permit applications are submitted using the Ohio EPA Air Services 

system. 

Pursuant to OAC rule 3745-77-04, a timely and complete Title V operating permit is 

required to be submitted within 12 months after commencing operations. As per OAC rule 

3745-77-08, the state shall take final action on the application within 18 months of 

receiving a complete application. The draft permit shall be issued no later than 45 days 

before the aforementioned deadline for final action on the permit. 

3.5 National Emission Standards for Hazardous Air Pollutants (40 CFR Parts 61 and 

63) 

There are no 40 CFR Part 61 standards applicable to the proposed facility operations. 

Current USEPA AP-42 emission factors, other emission factors and vendor information 

were reviewed in determining if the proposed project was subject to a standard under 40 

CFR Part 63. Based on potential emission calculations, the potential emissions of a single 

HAP will not exceed the major source threshold of 10 tpy. In addition, potential emissions 

of combined HAPs will be less than the major source threshold of 25 tpy. Therefore, the 

major source NESHAP standards under 40 CFR Part 63 are not applicable to this Project. 

The USEPA has also promulgated a variety of standards applicable to area sources, those 

sources that are not considered major sources of HAPs. USEPA recently promulgated an 

area source standard for industrial, commercial and institutional boilers. This standard 

does not have requirements for boilers that are natural gas fired. As such, the boiler 

associated with the proposed Project does not have any requirements under this standard. 
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3.6 Acid Rain Program 

Title IV of the Clean Air Act Amendments required USEPA to establish a program to 

reduce emissions of acid rain forming pollutants, called the Acid Rain Program. The 

overall goal of this program is to achieve significant environmental benefits through 

reduction in SO2 and NOx emissions. To achieve this goal, the program employs both 

traditional and market-based approaches for controlling air pollution. Under the marketbased aspect of the program, affected units are allocated SO2 allowances by the USEPA, 

which may be used to offset emissions, or traded under the market allowance program. In 

addition, in order to ensure that facilities do not exceed their allowances, affected units are 

required to monitor and report their emissions using a CEMS system, as approved under 

40 CFR Part 75. 

The Project is subject to the Acid Rain Program based on the provisions of 40 CFR 

72.6(a)(3) because the turbines are considered utility units under the program definition 

and they do not meet the exemptions listed under paragraph (b) of this Section. The 

Project will be required to submit an acid rain permit application at least 24 months prior to 

the date on which the affected unit commences operation. OCE will submit an acid rain 

permit application in compliance with these requirements prior to this deadline. 

3.7 Cross-State Air Pollution Rule 

On March 10, 2005, USEPA issued the Clean Air Interstate Rule (CAIR) which requires 

reductions in emissions of NOx and SO2 from large fossil fueled electric generating units 

using a cap and trade system. The rule provides both annual emissions budgets and an 

ozone season emission budget for each state. On July 11, 2008, the U.S. Court of 

Appeals for the D.C. Circuit (the Court) issued an opinion vacating and remanding these 

rules. However, on December 23, 2008, the Court granted rehearing only to the extent 

that it remanded the rules to USEPA without vacating them. The December 23, 2008 

ruling leaves CAIR in place until the USEPA issues a new rule to replace CAIR in 

accordance with the July 11, 2008 provisions. On July 6, 2011, the USEPA issued the 

Cross-State Air Pollution Rule (CSAPR) which replaced CAIR. Ohio power generation 

sources of 25 MW or greater would be subject to this rule. CSAPR was to go into effect 

January 1, 2012 and would have imposed new cap-and-trade programs for ozone season 

NOx, annual NOx, and annual SO2 emissions. However, a ruling issued by the Court on 

December 30, 2011 stayed CSAPR until further resolution of petitions filed by several 

entities. On August 21, 2012, the Court vacated CSPAR and ruled that the former CAIR 

remain in effect until a viable replacement to CSAPR is made. Under CSAPR, electric 
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Oregon Clean Energy Center 

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generating facilities in Ohio would have been required to obtain allowances for ozone 

season NOx, annual NOx, and annual SO2 emissions. 

Under CAIR, assets holding excess allowances will be able to sell or trade allowances to 

those without sufficient allowances. The Project will comply with the rules currently in 

effect at the time of operational start. 

3.8 State Regulations 

In addition to regulations already discussed in preceding sections, state regulations that 

pertain to this facility are listed in Table 3-2. Titles shown in capital letters in the table are 

permits, notifications, and/or reports that will be needed for construction and operation of 

this facility. 

Table 3-2: Ohio EPA Applicable Regulations 

RULE DESCRIPTION 

OAC 3745-17-07 Control of visible particulate emissions from 

stationary sources 

OAC 3745-17-10 Restrictions on particulate emissions from fuel 

burning equipment 

OAC 3745-18-06 General emission limit provisions for sulfur 

dioxide 

OAC 3745-21-07 Control of emissions of organic materials from 

stationary sources 

OAC 3745-21-09 Control of emissions of volatile organic 

compounds from stationary sources 

OAC 3745-23-06 Control of nitrogen oxides emissions from 

stationary sources 

OAC 3745-25-03 Emission control action programs 

OAC 3745-31 PERMIT TO INSTALL NEW SOURCES OF 

POLLUTION 

OAC 3745-71-02 Emissions test methods and procedures for new 

and existing sources 
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Oregon Clean Energy Center 

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RULE DESCRIPTION 

OAC 3745-77 TITLE V PERMITS 

OAC 3745-100 TOXIC CHEMICAL RELEASE REPORTING 

OAC 3745-103 ACID RAIN PERMITS AND COMPLIANCE 

OAC 3745-104 ACCIDENTAL RELEASES PREVENTION 

PROGRAM 

Federal authority is delegated to the State of Ohio, and all permit applications will be 

submitted to Ohio EPA through the delegated local permitting agency. In Lucas County, 

the TES in Toledo, Ohio will handle these permit applications. The Permit to Install (PTI) 

will serve as the air construction permit and initial operating permit for emission testing 

purposes. As explained in preceding sections, the following list of air permits is applicable 

to the proposed facility: 

1) OEPA PTI: OAC Chapter 3745-31 – Permit to Install New Source of 

Pollution. The PTI will serve as the submission vehicle for the 

preconstruction permit. 

2) Title V Permit: OAC Chapter 3745-77 – Title V Permits 

3) Acid Rain Permit: OAC Chapter 3745-103 – Title IV Acid Rain Permits and 

Compliance 
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4. CONTROL TECHNOLOGY EVALUATION – BACT/BAT 

Control technology evaluations for new major stationary sources involve an evaluation of 

BACT for pollutants subject to PSD pre-construction review and State of Ohio BAT for 

other pollutants not subject to PSD. A control technology analysis has been performed for 

the proposed facility based upon the USEPA guidance document New Source Review 

Workshop Manual (USEPA, 1990). The PSD and State of Ohio BAT requirements for each 

pollutant were defined in Section 3.0 of this application, and are briefly summarized in the 

sections below. 

4.1 Regulatory Applicability of Control Requirements 

This section provides a brief summary of the control technology requirements under the 

PSD and state of Ohio permitting programs for each pollutant. Control technology 

requirements are generally based on the potential emissions from the new or modified 

source and the attainment status of the area in which the source is located. A detailed 

determination of applicable regulatory requirements under PSD rules are provided in 

Section 3.0. The following sections discuss the applicability of BACT and BAT 

requirements for emissions from the equipment associated with the project. 

4.1.1 PSD Pollutants Subject to BACT/BAT 

Pollutants subject to PSD review are subject to a BACT analysis. The proposed Project is 

considered a major source for PSD purposes since potential emissions exceed major 

source thresholds. Therefore, individual pollutants are subject to BACT requirements if 

their potential emissions exceed the Significant Emission Rates presented in Table 1-1. 

As shown in this table, the Project is subject to PSD review for the criteria pollutants: NO2, 

CO, VOC, SO2, H2SO4, CO2 and PM10/PM2.5 and is therefore required to implement BACT 

for these pollutants. Criteria pollutants for which BACT is not required to be implemented 

are subject to BAT. 

As described in Section 3.3 of this report, sources with pollutants meeting certain other 

standards also meet BAT. For pollutants subject to BACT requirements, compliance with 

BACT meets BAT requirements. For HAPs subject to MACT, compliance with MACT 

meets BAT requirements. For pollutants subject to NSPS, compliance with NSPS 

represents BAT. Sources subject to BAT may comply with the levels achieved by similar 

sources or may conduct a case-by-case BAT determination using a “top down” approach, 

similar to a BACT analysis. BAT for non-criteria or air toxic pollutants are addressed by an 
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“Option A” evaluation described in Section 3.3. The evaluation will be included in the Air 

Dispersion Report submitted for the Project. 

4.1.2 Emission Units Subject to BACT Analyses 

For a facility subject to a BACT analysis, each pollutant emitted in amounts greater than 

the regulatory thresholds are subject to a prescribed level of control technology review for 

each emission unit that emits that pollutant. For the proposed Project, the source 

responsible for the majority of the Project’s emissions will be the combined cycle 

combustion turbines with supplemental duct burning. Therefore, the primary focus of the 

BACT analyses presented in the following sections is on the combined cycle combustion 

turbines. Evaluation of the ancillary equipment is conducted consistent with proposed 

small annual emission levels and with limited hours of operation. 

4.2 BACT Analysis Approach 

The sections below outline the approach used to conduct the BACT/BAT analyses 

presented in this application. 

4.2.1 Best Available Control Technology 

BACT is defined as the optimum level of control applied to a pollutant emissions based 

upon consideration of energy, economic and environmental factors. In a BACT analysis, 

the energy, environmental, and economic factors associated with each alternate control 

technology are evaluated, as necessary, in addition to the benefit of reduced emissions 

that each technology would provide. The BACT analyses presented in the following 

sections consist of up to four steps as outlined below. 

4.2.1.1 Identification of Technically Feasible Control Options 

The first step in a BACT analysis is the identification of technically feasible and available 

control technology options, including consideration of transferable and innovative control 

measures that may not have been previously applied to the source type under analysis. 

The minimum requirement for a BACT proposal is an option that meets federal NSPS 

limits or other minimum state or local requirements, such as RACT or Ohio EPA emission 

standards. After elimination of technically infeasible control technologies, the remaining 

options are ranked by control effectiveness. 
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If there is only a single feasible option, or if the most stringent alternative is proposed, then 

no further analysis is required. Technical considerations and site-specific sensitive issues 

will often play a role in BACT determinations. Generally, if the most stringent technology is 

rejected as BACT, the next most stringent technology is evaluated and so on. 

In order to identify options for each class of equipment, a search of the USEPA’s 

RACT/BACT/LAER Clearinghouse (RBLC) database was performed. Individual searches 

were performed for each pollutant emitted from each emission unit. The most recently 

issued permits from Ohio and other permits listed on the RBLC were also analyzed if 

available. Information was found for several hundred large combined cycle power plant 

projects permitted in the past decade. Appendix C provides a summary of recent similar 

energy projects from around the country. Less recent projects were also included due to 

regional proximity and/or very stringent emission limits. Using these criteria, lists for each 

pollutant for each equipment source were compiled and are presented in Appendix C. 

If two or more technically feasible options are identified, the next three steps (as presented 

below) are applied to identify and compare the economic, energy and environmental 

impacts of the options. 

4.2.1.2 Economic (Cost-Effectiveness) Analysis 

This analysis consists of an estimation of cost and calculation of the cost-effectiveness of 

each control technology, on a dollar per ton of pollution removed basis. Annual emissions 

with a control option are subtracted from base case emissions to calculate tons of pollutant 

controlled per year. The base case may be uncontrolled emissions or the maximum 

emission rate allowed with BACT considerations (such as an NSPS or RACT limit). 

Annual costs are calculated by adding annual operation and maintenance costs to the 

annualized capital cost of a control option. Cost-effectiveness (dollars per ton) of a control 

option is the annual cost (dollars per year) divided by the annual reduction in emissions 

(tpy). If either the most effective control option is proposed, or if there are no technically 

feasible control options, an economic analysis is not required. 

4.2.1.3 Energy Impact Analysis 

Two types of energy impacts are normally considered quantifiable. First, when the 

installation of a particular option would result in a reduction in either the power output 

capacity or reliability of a unit, this reduction is a quantifiable energy impact. Second, the 

consumption of energy by the control option itself is a quantifiable energy impact. These 
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impacts can be quantified by either an increase in fuel consumption due to reduced 

efficiency or fuel consumption to power the equipment. 

4.2.1.4 Environmental Impact Analysis 

The primary focus of the environmental impact analysis is the reduction in ambient 

concentrations of the pollutant being emitted. Increases or decreases in emissions of 

other criteria or non-criteria pollutants may occur with some technologies and should be 

identified. Non-air related impacts such as solid waste generation, increased water 

consumption or waste water generation may also be an issue associated with a control 

option. These additional impacts should be identified and qualitatively or quantitatively 

evaluated. 

4.3 BACT Analysis for NOx

NOx is formed during the combustion of fuel and is generally classified as either thermal 

NOx or fuel-related NOx. Thermal NOx results when atmospheric nitrogen is oxidized at 

high temperatures to produce nitrogen oxide (NO), NO2, and other oxides of nitrogen. The 

major factors influencing the formation of thermal NOx are temperature, concentrations of 

oxygen in the inlet air and residence time within the combustion zone. Fuel-related NOx is 

formed from the oxidation of chemically bound nitrogen in the fuel. Fuel-related NOx is 

generally minimal for natural gas combustion. As such, NOx formation from combustion of 

natural gas is due mostly to thermal NOx formation. 

Reduction in NOx formation can be achieved using combustion controls and/or flue gas 

treatment. Available combustion controls include water or steam injection and low 

emission combustors. Typical gas turbines are designed to operate at a nearly 

stoichiometric ratio of fuel in the combustion zone, with additional air introduced 

downstream. Fuel-to-air ratios below stoichiometric are referred to as fuel-lean mixtures. 

This type of fuel mixture limits the formation of NOx because there is lower flame 

temperature with a lean fuel mixture. Using this concept, lean combustors are designed to 

operate below the stoichiometric ratio, thereby reducing the thermal NOx formation within 

the combustion chamber. 

The turbines proposed for the Project utilize a lean fuel technology. In addition, exhaust 

gases from the turbine (and duct burner) will exhaust through an SCR system (discussed 

below) to further reduce NOx emissions to 2.0 ppmv at 15 percent O2, with and without duct 

burning. 
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The Project will also utilize an auxiliary boiler. The auxiliary boiler will utilize flue gas 

recirculation and low-NOx burner technology, two combustion optimization techniques that 

also reduce the formation of NOx. Using these enhanced combustion techniques, 

emissions from the auxiliary boiler will be limited to 0.01 lb/MMBtu. 

The following discussion will demonstrate that the proposed NOx emission rates for the 

combined cycle turbines and auxiliary boiler are considered BACT. 

4.3.1 Identification of Control Options 

SCR is an add-on NOx control technology that is placed in the exhaust stream following 

the gas turbine/duct burner. SCR involves the injection of ammonia into the exhaust gas 

upstream of a catalyst bed. On the catalyst surface, NH3 reacts with the NOx contained 

within the flue gas to form nitrogen gas and water in accordance with the following 

chemical reactions: 

4NH3 + 4NO + O2 → 4N2 + 6H2O 

8NH3 + 6NO2 → 7N2 + 12H2O 

The catalyst’s active surface is usually a noble metal (platinum), base metal (titanium or 

vanadium) or a zeolite-based material. Metal-based catalysts are usually applied as a 

coating over a metal or ceramic substrate. Zeolite catalysts are typically a homogeneous 

material that forms both the active surface and the substrate. NH3 is fed and mixed into 

the combustion gas upstream of the catalyst bed in greater than stoichiometric amounts to 

achieve maximum conversion of NOx. Excess NH3 which is not reacted in the catalyst bed 

is subsequently emitted through the stack; this is called “ammonia slip.” 

An important factor that affects the performance of an SCR system is the operating 

temperature. The optimal temperature range for standard base metal catalysts is between 

400°F and 800°F. Because the optimal temperature is below the CTG exhaust 

temperature but above the stack exhaust temperature, the catalyst needs to be located 

within the HRSG. 

An undesirable side effect of the use of SCR systems is the potential for formation of 

ammonium bisulfate and ammonium sulfate, referred to as ammonium salts. These salts 

are reaction products of SO3 and NH3. Ammonium salts are corrosive and can stick to the 

heat exchanger surfaces, duct work or the stack at low temperatures. In addition, 

ammonia salts are considered PM10/PM2.5, and, therefore, increase the emissions of these 
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criteria pollutants. Use of low sulfur fuels such as natural gas minimizes the formation of 

SO3 and the subsequent formation of these ammonium salts. 

4.3.2 Search of RBLC Determinations 

4.3.2.1 Combustion Turbine Generators and Duct Burners 

The search of the RBLC and other available permits identified several natural gas fired 

combined cycle combustion turbine projects. As described previously, representative 

projects were selected based upon recent decisions, local proximity, or stringent limits. 

Details for representative facilities are presented in Appendix C. The lowest permitted NOx

limit for a natural gas fired combined cycle turbine with duct burning was 2.0 ppmv at 15 

percent O2. All of these projects use SCR systems in combination with combustion 

optimization technology such as low-NOx burners. It is our understanding that several of 

these projects have demonstrated compliance with the 2.0 ppmv emission limits under 

primary operating modes. Some of these projects have permit limits above 2.0 ppmv to 

accommodate alternative operating modes such as duct burning. 

In general, BACT determinations have focused on the level that can be achieved in the 

primary operating mode (typically gas-fired 100 percent load), with NOx levels being set for 

alternative modes (duct burning, partial load, etc.) at the levels that result from application 

of the same degree of control used to achieve BACT in the primary mode. 

4.3.2.2 Auxiliary Boiler 

The RBLC and recent air permit search for natural gas-fired boilers between 10 and 100 

MMBtu/hr in size identified close to 100 installations. NOx emission limits for these boilers 

widely range from approximately 0.009 lb/MMBtu to 0.08 lb/MMBtu. Details on 

approximately 40 of the installations that were determined to be most representative for 

the proposed boiler are provided in Appendix C. The projects with emission limits less 

than 0.011 lb/MMBtu are generally industrial/commercial boilers less than 30 MMBtu/hr 

that are operated continuously to support industrial processes or other operations; these 

were not considered relevant to the project. Beyond these projects, other determinations 

generally proposed NOx emission limits greater than 0.03 lb/MMBtu. The most recent 

determination for an auxiliary boiler in Ohio proposed a NOx emission limit of 0.037 

lb/MMBtu. 
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4.3.3 BACT Determinations 

4.3.3.1 Combustion Turbine Generators and Duct Burners 

OCE is proposing a NOx emission limit of 2.0 ppmv at 15 percent O2 (with and without duct 

burning) as BACT for the proposed Project. This level of emissions will be achieved 

through the application of DLN burners in combination with SCR. This emission level is 

consistent with the most stringent level of control found during the RBLC search and has 

been demonstrated in practice. 

4.3.3.2 Auxiliary Boiler 

OCE is proposing a NOx emission limit of 0.01 lb/MMBtu. The auxiliary boiler will use flue 

gas recirculation in combination with low-NOx burners. These technologies, used in 

combination, are capable of reducing NOx emissions by 60 to 90 percent. This limit is 

consistent with the results from the RBLC database search. 

4.4 BACT Analysis for VOC 

Combustion turbines have inherently low VOC emission rates. Emissions of VOC from a 

combustion turbine occur as a result of incomplete combustion of organic compounds 

within the fuel. In an ideal combustion process, all carbon and hydrogen contained within 

the fuel are oxidized to form CO2 and water. VOC emissions can be minimized by the use 

of good combustion controls and add-on controls as described below. 

The turbines proposed for the project will utilize good combustion controls and exhaust 

through an oxidation catalyst to further reduce VOC emissions. Emissions of VOC from 

the exhaust stack will be limited to 1.0 ppmv at 15 percent O2 without duct burning and 3.5 

ppmv with duct burning. 

The Project will also utilize an auxiliary boiler. The auxiliary boiler will utilize combustion 

optimization technologies to minimize incomplete combustion and subsequent emissions 

of VOC. Using good combustion controls, emissions from the auxiliary boiler will be 

limited to 0.004 lb/MMBtu. 
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4.4.1 Identification of Control Options 

There are only two practical methods for controlling VOC emissions from combustion 

processes: efficient combustion and add-on control equipment. The most stringent level of 

control is through the use of add-on control equipment. The only post-combustion control 

that can be practically implemented is catalytic oxidation. Oxidation catalyst systems 

consist of a passive reactor comprised of a grid of metal panels with a platinum catalyst. 

The optimal location for VOC control, in the 900°F to 1,100°F temperature range, would be 

upstream of the HRSG or in the front-end section of the HRSG. However, at the high 

temperatures necessary to make the oxidation catalyst optimized for VOC reduction, there 

is the undesirable result of causing substantially more conversion of SO2 to SO3. As 

described previously, SO3 may react with water and/or NH3 to form H2SO4 and/or 

ammonium salt (PM10/PM2.5). Therefore, the placement of the oxidation catalyst in the 

“cooler” section of the HRSG, which is necessary for CO control, is the optimal design. 

VOC emissions from the auxiliary boiler will also occur due to incomplete combustion. As 

such, VOC emissions are minimized by combustion practices that promote high 

combustion temperatures, long residence times, and turbulent mixing of fuel and 

combustion air. In practice, post-combustion control methods are not routinely 

implemented for the reduction of VOC emissions from auxiliary boilers, as supported by 

the search of the RBLC determinations presented below. 

4.4.2 Search of RBLC Determinations 

4.4.2.1 Combustion Turbine Generators and Duct Burners 

The search of the RBLC and other available permits identified many natural gas-fired 

combined cycle combustion turbine projects. Details for approximately 30 of these 

facilities have been included in Appendix C. Based on this search, use of an oxidation 

catalyst appears to be the most stringent level of VOC control for natural gas fired 

combined cycle turbines. VOC limits range from 0.7 ppmv to 6 ppmv. The variation in VOC 

concentrations between different projects is not unexpected due to differences in turbine 

and HRSG manufacturers and overall engineering design. Based on the review of the 

RBLC, BAT for VOC is utilization of an oxidation catalyst system to achieve an outlet VOC 

concentration in the 1 to 3.5 ppmv range. 
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4.4.2.2 Auxiliary Boiler 

The RBLC and recent air permit search for natural gas fired boilers between 10 and 100 

MMBtu/hr in size identified close to 100 installations. VOC emission limits for these 

installations range from approximately 0.002 lb/MMBtu to 0.08 lb/MMBtu. Details on 

approximately 30 of the installations that were determined to be most applicable to the 

proposed boiler are provided in Appendix C. 

The most recent determination in the database is for a commercial boiler with a VOC 

BACT limit of 0.0054 lb/MMBtu. Most of the boilers that operate in a similar manner to the 

proposed boiler also have operational restrictions on hours. There are several 

determinations for auxiliary boilers at energy generating facilities in the database. The 

majority of the installations have emission limits of 0.005 lb/MMBtu or greater. Based on 

the review of the RBLC, BAT for VOC is good combustion practices to achieve a VOC 

emission limit in the 0.004 to 0.005 lb/MMBtu range. 

4.4.3 BACT Determinations 

4.4.3.1 Combustion Turbine Generators and Duct Burners 

OCE is proposing a VOC emission limit of 1.0 ppmv at 15 percent O2 without duct burning 

and 3.5 ppmv at 15 percent O2 while duct burning as BACT for the proposed Project. This 

level of emissions will be achieved via good combustion control and an oxidation catalyst. 

4.4.3.2 Auxiliary Boiler 

OCE is proposing a VOC emission limit of 0.004 lb/MMBtu from the auxiliary boiler using 

good combustion practices. 

4.5 BACT Analysis for CO 

Emissions of CO from combustion occur as a result of incomplete combustion of fuel. CO 

emissions are minimized by the use of proper combustor design, good combustion 

practices and add-on controls. The combined cycle turbines and the auxiliary boiler will be 

sources of CO emissions. Since the potential emissions from the project exceed PSD 

significance thresholds, BACT is required for CO emissions. As indicated previously, 

pollutants that comply with BACT meet BAT requirements. 
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The turbines proposed for the Project will utilize good combustion controls and exhaust 

through an oxidation catalyst to reduce CO emissions. Emissions of CO from the exhaust 

stack will be limited to 2.0 ppmv at 15 percent O2 with and without duct burning. 

The auxiliary boiler will utilize good combustion practices to minimize incomplete 

combustion and subsequent emissions of CO. Using good combustion controls, 

emissions from the auxiliary boiler will be limited to 0.037 lb/MMBtu. 

The following discussion demonstrates that the proposed CO emission rates for the 

combined cycle turbines and auxiliary boiler are considered BACT. 

4.5.1 Identification of Control Options 

There are only two practical methods for controlling CO emissions from combustion 

processes: efficient combustion and add-on control equipment. The most stringent level of 

control is the use of add-on equipment. The only post-combustion control that can be 

practically implemented is catalytic oxidation. Oxidation catalyst systems consist of a 

passive reactor comprised of a grid of metal panels with a platinum catalyst. CO reduction 

efficiencies in the range of 80 to 90 percent can be expected, although CO reduction may 

at times be less than these values due to the low inlet concentrations expected from the 

turbines. 

CO emissions from the auxiliary boiler will also occur due to incomplete combustion. As 

such, combustion design that promotes high combustion temperatures, long residence 

times, and turbulent mixing of fuel and combustion air is the common practice used to 

minimize CO emissions. Although it is technologically feasible to control CO emissions 

from a boiler in the 10 to 100 MMBtu/hr size range using an oxidation catalyst, current 

combustion technology results in very low emissions of CO such that add-on control would 

not be considered cost-effective. 

4.5.2 Search of RBLC Determinations 

4.5.2.1 Combustion Turbine Generators and Duct Burners 

The search of the RBLC available permits identified almost 300 natural gas fired combined 

cycle combustion turbine projects. Based on this search, use of an oxidation catalyst 

appears to be the most stringent level of control for natural gas fired combined cycle 

turbines. 
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CO emission limits from recently permitted projects generally ranged from 0.9 ppmv to 15 

ppmv (or greater). The lowest CO limit found in a permit for a natural gas fired combined 

cycle turbine was 0.9 ppmv without duct burning and 1.8 ppmv with duct burning, issued to 

Kleen Energy Systems in Connecticut. While the duct burning limit is consistent with other 

determinations, the 0.9 ppmv limit is an outlier. It is important to note that Kleen Energy 

has a VOC BACT limit of 5.0 ppmv, which is significantly higher than the proposed VOC 

limit for the Project. This is indicative of the fact that it is difficult to design a system that 

provides a very high level of control for CO while simultaneously providing a very high level 

of control for VOC. As such, systems are more commonly designed to provide substantial 

control for both CO and VOC simultaneously. This is illustrated by two recent BACT/LAER 

determinations for proposed combined-cycle power plants in New Jersey. Draft permits 

for the Woodbridge Energy Center and the Newark Energy Center were issued in June 

2012. Both facilities proposed CO BACT limits of 2.0 ppmv and VOC LAER limits of 1.0 

ppmv (without duct burning) For these facilities, the turbine train was designed to optimize 

control of both CO and VOC. There are many facilities in the RBLC with recently permitted 

BACT CO emission limits of 2.0 ppmv (or greater). For example, the Empire Generating 

and Caithness Long Island Energy projects in New York State have permit limits of 2.0 

ppmv for CO, which is considered representative of BACT. It is our understanding that 

several of these facilities are operating in compliance with their 2.0 ppmv limit. 

4.5.2.2 Auxiliary Boiler 

The RBLC and recent air permit search for natural gas-fired boilers between 10 and 100 

MMBtu/hr in size identified close to 100 installations. CO emission limits for these 

installations range from approximately 0.0073 lb/MMBtu to 0.08 lb/MMBtu. Details on 

approximately 30 of the installations that were determined to be most applicable to the 

proposed boiler are provided in Appendix C. 

The most stringent limit for an auxiliary boiler at an energy generating facility is 0.0164 

lb/MMBtu at Emery Generating Station in Iowa, which was permitted in 2002. This 

installation is operational and it utilizes a catalytic oxidizer with an estimated control 

efficiency of 80 percent to achieve this emission rate. Since this installation, there have 

been many projects permitted without add-on controls that utilize good combustion 

practices to achieve CO control. The most recent auxiliary boiler installation listed in the 

RBLC has a CO limit of 0.15 lb/MMBtu. There are several other recent determinations 

with CO limits between 0.02 and 0.04 lb/MMBtu. These installations also utilize good 

combustion practices to control CO emissions. 
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4.5.3 BACT Determinations 

4.5.3.1 Combustion Turbine Generators and Duct Burners 

OCE is proposing a CO emission limit of 2.0 ppmv at 15 percent O2 with and without duct 

burning as BACT for the proposed project. This level of emissions will be achieved via 

good combustion control and an oxidation catalyst. This proposal is consistent with the 

limits and control technologies found in the RBLC and with recent BACT determinations in 

Ohio and in other states. 

4.5.3.2 Auxiliary Boiler 

OCE is proposing a CO emission limit of 0.037 lb/MMBtu from the auxiliary boiler using 

good combustion practices. This is consistent with BACT determinations for this type of 

equipment. 

4.6 BACT Analysis for Particulate Matter (PM10/PM2.5) 

Emissions of particulate matter from combustion occur as a result of inert solids contained 

in the fuel, unburned fuel hydrocarbons which agglomerate to form particles, and mineral 

matter in water that may be injected for NOx control during diesel firing. Particulate 

emissions can also result from the formation of ammonium sulfates due to the conversion 

of SO2 to SO3, which is then available to react with ammonia to form ammonium sulfate. 

All of the particulate matter emitted from the turbines is conservatively assumed to be less 

than 2.5 microns in diameter. Therefore, PM10 and PM2.5 emission rates are assumed to 

be the same. 

The combustion of clean burning fuels is the most effective means for controlling 

particulate emissions from combustion equipment. The project is proposing to use natural 

gas as the only fuel for the turbines. Natural gas is a very clean burning fuel with very low 

associated particulate emissions. OCE is not aware of any combustion turbine projects in 

existence that have add-on particulate control. 

The turbines proposed for the project will utilize natural gas as their only fuel to minimize 

particulate emissions. Emissions of PM10/PM2.5 from the exhaust stack will be limited to 

0.0049 lb/MMBtu without duct burning and 0.0065 lb/MMBtu with duct burning. 

The Project will also utilize an auxiliary boiler. The auxiliary boiler will combust only natural 

gas, resulting in a PM10/PM2.5 emission limit of 0.005 lb/MMBtu. The cooling tower will 
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also be a source of PM10/PM2.5 emissions. The Project is proposing use of a high 

efficiency drift eliminator (0.0005%). 

The following discussion will demonstrate that the proposed PM10/PM2.5 emission rates for 

the combined cycle turbines and auxiliary boiler are considered BACT. 

4.6.1 Search of RBLC Determinations 

4.6.1.1 Combustion Turbine Generators and Duct Burners 

The search of the RBLC and other available permits identified over 300 natural gas fired 

combined cycle combustion turbine projects. Based on this search, use of clean burning 

fuels is the primary control for particulate emissions. Particulate matter emission limits in 

the RBLC database generally ranged from approximately 0.003 lb/MMBtu to 0.3 lb/MMBtu 

(or greater). The lowest PM10/PM2.5 limit found in a permit for an F-series natural gas fired 

combined cycle turbine was 0.0051 lb/MMBtu, which was issued to Kleen Energy Systems 

in Connecticut. Similarly, Caithness Long Island Energy has a limit of 0.0055 lb/MMBtu. 

Beyond these examples, there are many facilities in the RBLC with permitted BACT 

PM10/PM2.5 emission limits in the range of 0.006 lb/MMBtu to 0.01 lb/MMBtu. Generally, all 

of these projects utilize clean burning fuel as their primary control technology and their 

emission limits are based upon the overall quality of their commercial natural gas source. 

4.6.1.2 Auxiliary Boiler 

A review of the RBLC indicates that good combustion practices and clean burning fuels 

have typically been determined to be BACT for boilers. PM10/PM2.5 emission limits for 

natural gas fired boilers vary widely, ranging from 0.002 lb/MMBtu through 0.6 lb/MMBtu. 

PM10/PM2.5 emission limits for gas-fired auxiliary boilers of similar size are as low as 0.003 

lb/MMBtu. The most recent listing in the RBLC for an auxiliary boiler proposed a 

PM10/PM2.5 limit of 0.005 lb/MMBtu. 

4.6.1.3 Cooling Tower 

A review of the RBLC provides very few entries for cooling towers, the most recent being 

in 2005. In the RBLC listings, BACT for PM10 and PM2.5 was determined to be utilization of 

a high efficiency drift eliminator with a removal efficiency of 0.0005 percent. A removal 

efficiency of 0.0005 is the most effective drift eliminator commercially available. 
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4.6.2 BACT Determinations 

4.6.2.1 Combustion Turbine Generators and Duct Burners 

OCE is proposing a PM10/PM2.5 emission limit of 0.0049 lb/MMBtu lb/MMBtu without duct 

burning and 0.0065 lb/MMBtu with duct burning as BACT for the proposed project. This 

level of emissions will be achieved by combusting only commercially available, pipeline 

quality natural gas in the turbines. This emission level is consistent with the limits and 

control technologies found in the RBLC for recent BACT determinations in Ohio and in 

other states. 

4.6.2.2 Auxiliary Boiler 

OCE is proposing the exclusive use of clean-burning pipeline quality natural gas in 

conjunction with good combustion practices as BACT for the auxiliary boiler. The Project 

proposes a PM10/PM2.5 emission limit of 0.005 lb/MMBtu boiler using natural gas as the 

only fuel. This is consistent with other BACT determinations for this type of equipment. 

4.6.2.3 Wet Cooling Tower 

OCE is proposing use of a 0.0005 percent high efficiency drift eliminator as BACT and for 

PM10 and PM2.5. This equates to hourly emission rate of 1.0 lb/hr for PM10 and PM2.5. Use 

of high efficiency drift eliminators is consistent with recent BACT determinations in Ohio 

and in other states. 

4.7 BACT Analysis for Sulfur Dioxide and Sulfuric Acid 

Emissions of SO2 are formed from the oxidation of sulfur in the fuel. Normally, all sulfur 

compounds contained in the fuel will oxidize, and virtually all will oxidize to form SO2. A 

small percentage will oxidize to sulfur trioxide (SO3) and sulfate (SO4), dependent on a 

number of factors including: combustor design; temperature; pressure; oxygen level; and 

moisture level in the combustion zone and downstream in the combined-cycle system, 

exhaust stack, and ambient air proximate to the stack. After being formed, the SO3 and 

SO4 will react to form H2SO4 and sulfate particulate. SO2 and H2SO4 emissions can be 

controlled using pre- and post-combustion controls. Pre-combustion controls involve the 

use of low sulfur fuels such as natural gas or ULSD. Post-combustion controls involve the 

use of add-on control technology such as wet and dry flue gas desulfurization (FGD) 

processes. Installation of such systems is an established technology principally on coalfired and high sulfur oil-fired steam electric generation stations. However, FGD systems 
Control Technology Evaluation Page 4-15 

PSD Permit Application 

Oregon Clean Energy Center 

 Lucas County, OH 

are not practical for combustion turbines due to several factors including the large exhaust 

flow (and corresponding pressure drop) and the low inlet concentration in the flue gas. 

The use of natural gas and ULSD are the most common methods for controlling 

SO2/H2SO4emissions from combustion turbines. 

The turbines proposed for the Project will utilize natural gas as their only fuel to minimize 

SO2 and H2SO4 emissions. Emissions of SO2 and H2SO4 from the exhaust stack will be 

limited to 0.0015 lb/MMBtu and 0.0008 lb/MMBtu with and without duct burning, 

respectively. 

The project will also utilize an auxiliary boiler. The auxiliary boiler will combust only natural 

gas, resulting in SO2 and H2SO4 emission limits of 0.0007 lb/MMBtu and 0.00005 

lb/MMBtu, respectively. 

The following discussion will demonstrate that the proposed SO2 and H2SO4 emission 

rates for the combined cycle turbines and auxiliary boiler are considered BACT. 

4.7.1 Search of RBLC Determinations 

4.7.1.1 Combustion Turbine Generators and Duct Burners 

The search of the RBLC and other available permits identified more than 300 natural gas 

fired combined cycle projects. Based on this search, use of low sulfur fuels is the primary 

control for SO2 emissions, with emission limits being dependent upon the sulfur content of 

the fuel and engine design. SO2 emission limits in the RBLC generally ranged from 

0.0003 lb/MMBtu to 0.01 lb/MMBtu (or greater). Most projects proposed limits in the range 

of 0.002 to 0.005 lb/MMBtu and utilized commercially available pipeline quality natural gas. 

Similarly, a search of permits for natural gas-fired combined cycle units indicated H2SO4

emissions ranging from 0.0001 lb/MMBtu to 0.002 lb/MMBtu (or greater). Similar to SO2, 

BACT for these sources was the use of low sulfur fuels and emission limits are dependent 

upon the sulfur content of the fuel and engine design. 

4.7.1.2 Auxiliary Boiler 

A review of the RBLC indicates that combustion of clean burning low-sulfur fuels has 

typically been determined to be BACT for SO2 and H2SO4. The most stringent SO2

emission limit for an auxiliary boiler found the RBLC was 0.0006 lb/MMBtu. The most 
Control Technology Evaluation Page 4-16 

PSD Permit Application 

Oregon Clean Energy Center 

 Lucas County, OH 

recent project listed in the RBLC proposes an SO2 emission limit of 0.0009 lb/MMBtu. This 

limit is based upon the sulfur content of the natural gas supply. 

A search of the RBLC for H2SO4 emissions only identified two boilers of similar size to the 

proposed auxiliary boiler. Of these listings, only one was for an auxiliary boiler at an 

energy facility. This project, CPV Saint Charles, proposed an H2SO4 limit of 0.0001 

lb/MMBtu. 

4.7.2 BACT Determinations 

4.7.2.1 Combustion Turbine Generators and Duct Burners 

OCE is proposing a SO2 emission limit of 0.0015 lb/MMBtu (with and without duct burning) 

as BACT for the proposed project. This level of emissions will be achieved by combusting 

commercially available, pipeline quality natural gas with a maximum sulfur content of 0.5 

grains per 100 standard cubic foot (scf) by weight in the combustion turbines. This 

emission level is consistent with the limits and control technologies found in the RBLC. 

4.7.2.2 Auxiliary Boiler 

OCE is proposing a SO2 emission limit of 0.0007 lb/MMBtu as BACT for the proposed 

project. This is consistent with other BACT determinations for this type of equipment. 

4.8 BACT Analysis for Greenhouse Gases 

The principal GHGs associated with the project are CO2, methane (CH4), and nitrous oxide 

(N2O). Because these gases differ in their ability to trap heat, one ton of CO2 in the 

atmosphere has a different effect on warming than one ton of CH4 or one ton of N2O. For 

example, CH4 and N2O have 21 times and 298 times the global warming potential of CO2, 

respectively. GHG emissions from the proposed Project are primarily attributable to 

combustion of fuels. The Project will not have any other industrial processes releasing 

GHGs. By far the greatest proportion of potential GHGs emissions are from CO2. Trace 

amounts of CH4 and N2O, would be emitted in varying quantities depending on operating 

conditions. However, emissions of CH4 and N2O are negligible when compared to total 

CO2 emissions, and would not be considered significant to climate change issues. In 

addition, as presented previously, the project is proposing to implement BACT for both 

VOC (expressed as CH4) and NOx, such that these pollutants are being effectively 

controlled. As such, the remainder of this section will focus on BACT for CO2. 
Control Technology Evaluation Page 4-17 

PSD Permit Application 

Oregon Clean Energy Center 

 Lucas County, OH 

CO2 is a product of combusting any carbon containing fuel, including natural gas. All fossil 

fuel contains significant amounts of carbon. During complete combustion, the fuel carbon 

is oxidized into CO2 via the following reaction: 

C + O2 → CO2

Full oxidation of carbon in fuel is desirable because CO, a product of partial combustion, 

has long been a regulated pollutant and because full combustion results in more useful 

energy. In fact, emission control technologies required for CO emissions (oxidation 

catalysts) increase CO2 emission by oxidizing CO to CO2. 

There are limited alternatives available for controlling CO2. The USEPA has indicated in 

the document, PSD and Title V Permitting Guidance for Greenhouse Gases, that carbon 

capture and sequestration (CCS) should be considered in BACT analyses as a technically 

feasible add-on control option for CO2. Currently, there are no combined cycle power 

plants utilizing CCS, and although theoretically feasible, this technology is not 

commercially available. 

CCS requires three distinct processes: 

1. Isolation of CO2 from the waste gas stream; 

2. Transportation of the captured CO2 to a suitable storage location; and 

3. Safe and secure storage of the captured and delivered CO2. 

The first step in the CCS process is capture of the CO2 from the process in a form that is 

suitable for transport. There are several methods that may be used for capturing CO2 from 

gas streams including chemical and physical absorption, cryogenic separation, and 

membrane separation. Only physical and chemical absorption would be considered 

technically implementable for a high volume, low concentration gas stream. Currently, 

there are no combined cycle power plants utilizing CO2 absorption systems. As such, this 

technology, while theoretically feasible, has not been demonstrated in practice for 

combined cycle facilities. Even if it were commercially available, the cost for designing, 

installing and operating this type of capture system would be prohibitive. In addition, the 

costs of compressing the captured CO2 to pressures needed for transportation would 

result in a large parasitic load to the facility, reducing its efficiency and increasing overall 

emissions of CO2 and all other regulated pollutants on a per megawatt-hour basis. 
Control Technology Evaluation Page 4-18 

PSD Permit Application 

Oregon Clean Energy Center 

 Lucas County, OH 

The next step in the CCS process is transportation of the captured CO2 to a suitable 

storage location. Currently CO2 storage is available at only a very limited number of sites. 

Geologic conditions at the proposed project site are not suitable for carbon sequestration. 

OCE does not own or control any other sites that would be appropriate for CO2

sequestration. The closest commercially available CO2 sequestration site is in 

Saskatchewan Canada, over 1,700 miles from the project site. Accordingly, to remain a 

viable control technology, captured CO2 would have to be transported to the storage site in 

order to achieve any environmental benefit. Pipelines are the most common method for 

transporting large quantities of CO2 over long distances. There are currently 

approximately 3,600 miles of existing pipeline located in the United States. However, 

there is no existing pipeline located near the project site. As such, a CO2 transportation 

pipeline would need to be constructed to tie into the existing pipeline structure. The cost 

for permitting and constructing this pressurized pipeline would be economically prohibitive. 

Based upon the large costs associated with the capture, transportation and storage of 

CO2, in addition to the large parasitic load, CCS is considered cost prohibitive and 

economically infeasible for the project. 

Apart from CCS, the only other technology with the potential to reduce GHG from the 

proposed facility is pollution prevention or the use of inherently lower-emitting processes, 

practices and designs. Because emissions of CO2 are directly related to the amount of 

fuel combusted, an effective means of reducing GHG emissions is through highly efficient 

combustion technologies. By utilizing more efficient technology, less fuel is required to 

produce the same amount of output electricity. 

The Project is designed for baseload electricity generation and will utilize state-of-the-art 

combustion turbine technology in combined cycle mode. Combined cycle generation 

takes advantage of the waste heat from the combustion turbines, capturing that heat in the 

HRSG and generating steam which then powers a conventional steam turbine. Use of 

waste heat in this manner makes combined cycle projects considerably more efficient than 

conventional boiler technology. 

The Project is proposing to use combustion turbines which utilize highly efficient 

combustion technology. In addition, the combustion turbines will combust natural gas as 

their only fuel source. Other fossil fuels generate a greater amount of CO2 per megawatthour of power produced or MMBtu of fuel consumed. As such, using natural gas as the 

only fuel source effectively minimizes the production of CO2 from combustion. The 

proposed project has a “Design Base Heat Rate” of approximately 6,687 British thermal 
Control Technology Evaluation Page 4-19 

PSD Permit Application 

Oregon Clean Energy Center 

 Lucas County, OH 

units per kilowatt-hour (Btu/kW-hr), HHV at ISO conditions (59°F, 71 percent relative 

humidity) with no duct firing. 

4.8.1.1 Search of RBLC Determinations 

OCE is aware of several projects that have been issued draft or final permits incorporating 

GHG requirements. These projects include: 

 Russell City Energy Center (final permit) 

 Cricket Valley Energy Center (draft permit) 

 Lower Colorado River Authority (final permit) 

 Woodbridge Energy Center (draft permit) 

 Newark Energy Center (draft permit) 

The GHG emissions limits in these permits are based upon engine efficiency expressed as 

heat rate and range from 7,522 to 7,730 Btu/kW-hr (operating at 100 percent load, ISO 

conditions without duct firing). Several of these permits also incorporate emission limits for 

CO2 in lb CO2/MW-hr. These limits range from 887 lb CO2/MW-hr gross to 918 lb 

CO2/MW-hr net, while combusting natural gas. 

The heat rate limits for the above referenced projects incorporate a margin over the design 

heat rate to account for degradation over the life of the equipment. Documentation 

associated with Russell City Energy Center provides a methodology for determining a 

reasonable estimate of degradation. The Bay Area Air Quality Management District 

(BAAQMD) in California issued a permit in February 2010 for the Russell City Energy 

Center that included a BACT limit. Russell City is a proposed combined-cycle generating 

facility with a nominal capacity of 600 MW utilizing two Siemens F-class combustion 

turbines. In its analysis, the BAAQMD evaluated factors that could be reasonably 

expected to degrade the theoretical design efficiency of the turbines and increase the heat 

rate. They considered a number of factors including: 

 A design margin to reflect that the equipment as constructed and installed 

may not fully achieve the assumptions that went into the design calculations; 

 A reasonable performance degradation margin to reflect normal wear and 

tear; and 

 A reasonable degradation margin based on normal wear and tear caused by 

variability in the operation of the auxiliary plant equipment. 
Control Technology Evaluation Page 4-20 

PSD Permit Application 

Oregon Clean Energy Center 

 Lucas County, OH 

Based on their analysis, BAAMD concluded that 12.8 percent was a reasonable 

compliance margin to add to the design base heat rate to develop a numerical BACT limit. 

BACT Determination 

The turbines operating in combined-cycle mode proposed for the Project have a design 

base heat rate of approximately 6,687 Btu/kW-hr at ISO HHV conditions with no duct firing. 

This value is superior to the efficiency proposed in the Russell City Energy Center BACT 

analysis and Cricket Valley Energy design base heat rate. Based upon this design, and 

adding a reasonable margin of compliance consistent with the BAAQMD analysis for 

Russell City Energy Center, OCE is proposing the following limits as BACT: 

 7,409 Btu/kW-hr HHV (ISO conditions without duct firing);and 

 896 lb CO2/MW-hr gross (ISO conditions while firing natural gas). 

These limits are consistent with recently permitted projects and can reasonably be assured 

under all operating scenarios. This level of emissions will be achieved through utilization 

of high efficiency, state-of-the-art, combustion turbine technology and combusting only 

commercially available, pipeline quality natural gas in the turbines. 

4.9 Emission Limit and Control Technology Summaries 

Tables 4-1 and 4-2 summarize the proposed emission limits and associated control 

technology for the Project. 
Control Technology Evaluation Page 4-21 

PSD Permit Application 

Oregon Clean Energy Center 

 Lucas County, OH 

Table 4-1: Summary of Proposed BACT/BAT Emission Limits and Associated 

Control Technologies for the Combustion Turbines 

Pollutant 

Emission 

Rate 

(lb/MMBtu) 

Emission 

Rate (ppmv)

at 15% O2

Control 

Technology Represents 

NOx 

CT only 

CT w/ DB 

0.0076 

0.0077 

2.0 

2.0 

DLN and 

SCR BACT/BAT 

VOC 

CT only 

CT w/ DB 

0.0013 

0.0048 

1.0 

3.5 

Good combustion 

controls and 

oxidation catalyst BACT/BAT 

CO 

CT only 

CT w/ DB 

0.0048 

0.0048 

2.0 

2.0 

Good combustion 

controls and 

oxidation catalyst BACT/BAT 

PM10/PM2.5 

CT only 

CT w/ DB 

0.0049 

0.0065 

n/a 

n/a 

Low sulfur fuel BACT/BAT 

SO2 

CT only 

CT w/ DB 

0.00015 

0.00015 

n/a 

n/a 

Low sulfur fuel BACT/BAT 

H2SO4 

CT only 

CT w/ DB 

0.0008 

0.0008 n/a 

n/a 

Low sulfur fuel BACT/BAT 
Control Technology Evaluation Page 4-22 

PSD Permit Application 

Oregon Clean Energy Center 

 Lucas County, OH 

Table 4-2: Summary of Proposed BACT/BAT Emission Limits and Associated 

Control Technologies for the Auxiliary Boiler 

Pollutant 

Emission Rate 

(lb/MMBtu) Control Technology Represents 

NOx 0.01 LNG and FGR BACT/BAT 

VOC 0.004 Good combustion 

controls BACT/BAT 

CO 0.037 Good combustion 

controls BACT/BAT 

PM10/PM2.5 0.005 Low sulfur fuel BACT/BAT 

SO2 0.0007 Low sulfur fuel BACT/BAT 
References Page 5-1 

PSD Permit Application 

Oregon Clean Energy Center 

 Lucas County, OH 

5. REFERENCES

CARB, 1996. California Air Toxics Emission Factor Database (CATEF) 1996. 

USEPA, 1990. New Source Review Workshop Manual (Draft). October 1990. 

USEPA, 1993. Alternative Control Techniques Document – NOx Emissions from 

Stationary Reciprocating Internal Combustion Engines. Office of Air and 

Radiation. EPA-453/R-93-032. July 1993. 

USEPA, 2000. Compilation of Air Pollutant Emission Factors AP-42, Fifth Edition, 

Volume I: Stationary Point and Area Sources. 

USEPS, 2010. “PSD and Title V Permitting Guidance for Greenhouse Gases”, Office of 

Air Quality Planning and Standards, November 2010 

VCAPCD, 2001. AB2588 Combustion Emission Factors 2001. 
Figures
0 1,000 2,000

Feet

I

City: Chicago Author: MNesta Path: G:\Aproject\GIS\OCE\MXD\OCE_ProjectLocation.mxd

Legend

Property Boundary

Project Facilities

PROJECT

LOCATION

FIGURE 1

OREGON CLEAN

ENERGY, LLC

Lucas County, Ohio

PROJECT LOCATION

LUCAS COUNTY, OHIO

Date: 08/17/2012

Topographic Base Image Source: ArcGIS Online

Services, Access date: 08/17/2012, via ArcGIS v. 10.

This image is not for re-sale or distribution outside

of the use of this PDF.

PROPERTY
Appendix A: Printout of Ohio EPA Permit Forms
PTI/PTIO Application A0045417

Oregon Clean Energy Center

0448020102

August 23, 2012
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Oregon Clean Energy Center - 0448020102 Page 1 PTI/PTIO Application - A0045417

Division of Air Pollution Control Aug 23 2012, 15:04:46

Application for Permit-to-Install or Permit-to-Install and Operate

This section should be filled out for each permit to install (PTI) or Permit to Install and Operate (PTIO) application. A PTI is

required for all air contaminant sources (emissions units) installed or modified after January 1, 1974 that are subject to OAC

Chapter 3745-77. A PTIO is required for all air contaminant sources (emissions units) that are not subject to OAC Chapter

3745-77 (Title V). See the application instructions for additional information.

For OEPA use only: x Installation x Request Federally enforceable restrictions

Modification General Permit

Renewal Other

Please summarize the reason for this permit application. This text will be in the public notice that will appear in the newspaper

of the county where the facility is located.

A permit-to-install (PTI) application is being submitted for the construction of

the Oregon Clean Energy Center - a nominal 800 megawatt (MW) combined cycle gas

turbine (CCGT) facility to be located in the City of Oregon, Lucas County, Ohio.

Is the purpose of this application to transition from OAC Chapter 3745-77 (Title V) to OAC Chapter 3745-31 (PTIO)?

No

Establish PER Due Date - Select an annual Permit Evaluation Report (PER) due date for this facility (does not apply to

facilities subject to Title V, OAC Chapter 3745-77). If the PER has previously been established and a change is now desired,

a PER Change Request form must be filed instead of selecting a date here.

PER not applicable (Title V) or due date already established

Federal Rules Applicability

New Source Performance Standards (NSPS)

New Source Performance Standards are listed under 40

CFR 60 - Standards of Performance for New Stationary

Sources.

Subject to subpart:

Dc - Small Industrial Steam

Generating Units

IIII - Stationary Compression

Ignition Internal Combustion

Engines

KKKK - Stationary Combustion

Turbines

National Emission Standards for Hazardous Air

Pollutants (NESHAP)

National Emissions Standards for Hazardous Air Pollutants

are listed under 40 CFR 61. (These include asbestos,

benzene, beryllium, mercury, and vinyl chloride).

Not affected

Maximum Achievable Control Technology (MACT)

The Maximum Achievable Control Technology standards

are listed under 40 CFR 63 and OAC rule 3745-31-28.

Not affected

Prevention of Significant Deterioration (PSD)

These rules are found under OAC rule 3745-31-10 through

OAC rule 3745-31-20.

Subject to Regulation

Non-Attainment New Source Review

These rules are found under OAC rule 3745-31-21 through

OAC rule 3745-31-27.

Not affected

112 (r) - Risk Management Plan

These rules are found under 40 CFR 68.

Not affected

Title IV (Acid Rain Requirements)

These rules are found under 40 CFR 72 and 40 CFR 73.

Subject to Regulation

Express PTI/PTIO - Do you qualify for express PTI or PTIO processing?

No

Air Contaminant Sources in this Application - Identify the air contaminant source(s) for which you are applying below.

Attach additional pages if necessary. Section II of this application and an EAC form should be completed for each air
6.

7.

Oregon Clean Energy Center - 0448020102 Page 2 PTI/PTIO Application - A0045417

contaminant source. 

Emissions Unit ID Company Equipment ID (company's name for

air contaminant source)

Equipment Description (List all equipment that

are a part of this air contaminant source)

TMP173331 CTG #1

TMP173332 CTG #2

TMP173333 Auxiliary Boiler

TMP173334 Emergency Generator

TMP173335 Emergency Fire Pump

TMP173336 Wet Cooling Tower

The Emissions Unit ID would have been created when a previous air permit was issued. If no previous permits

have been issued for this air contaminant source, leave this field blank. If this air contaminant source was

previously identified in STARShip applications as a Z source (e.g., Z001), please provide that identification and a

new ID will be assigned when the PTI/PTIO is issued.

Trade Secret Information - Is any information included in this application being claimed as a trade secret per Ohio Revised

Code (ORC) 3704.08?

No

Permit Application Contact - Person to contact for questions about this application:

Lynn Gresock ARCADIS, US Inc.

Name Title

One Executive Drive,

Suite 303

Chelmsford, MA 01824

Street Address City/Township, State Zip Code

9783224520 lynn.gresock@ARCADISUS.COM

Phone Fax E-mail
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Oregon Clean Energy Center - 0448020102 Page 1 PTI/PTIO Application - A0045417

Section II - Specific Air Contaminant Source Information Facility ID: 0448020102

Emissions Unit ID: TMP173331

Company Equipment ID: CTG #1

One copy of this section should be filled out for each air contaminant source (emissions unit) covered by this

PTI/PTIO application identified in Section I, Question 5. See the application instructions for additional information.

Air Contaminant Source Installation or Modification Schedule Check all that apply (must be completed regardless of

date of installation or modification):

New installation (for which construction has not yet begun, in accordance with OAC rule 3745-31-33). When will you begin

to install the air contaminant source?

after installation permit has been issued

SCC Codes - List all Source Classification Code(s) (SCC) that describe the process(es) performed by this air contaminant

source (e.g., 1-02-002-04).

See Facility Profile

Emissions Information - The following table requests information needed to determine the applicable requirements and the

compliance status of this air contaminant source with those requirements. Suggestions for how to estimate emissions may

be found in the instructions to the Emissions Activity Category (EAC) forms required with this application. If you need further

assistance, contact your District Office/Local Air Agency representative.

If total potential emissions of HAPs or any Toxic Air Contaminant (as identified in OAC rule 3745-114-01) are greater

than 1 ton/yr, fill in the table for that (those) pollutant(s). For all other pollutants, if Emissions before controls (max), lb/hr

multiplied by 24 hours/day is greater than 10 lbs/day, fill in the table for that pollutant.

Actual emissions are calculated including add-on control equipment. If you have no add-on control equipment,

Emissions before controls will be the same as Actual emissions.

Actual emissions and Requested Allowable should be based on operating 8760 hr/yr unless you are requesting federally

enforceable operating restrictions to limit emissions. If so, calculate emissions based on requested operating restrictions

and describe in your calculations.

If you use units other than lbs/hr or ton/yr, specify the units used (e.g., gr/dscf, lb/ton charged, lb/MMBtu, tons/12-

months).

Requested Allowable (ton/yr) is often equivalent to Potential to Emit (PTE) as defined in OAC rule 3745-31-01 and OAC

rule 3745-77-01.

Pollutant Emissions

before controls

(max)* (lb/hr)

Actual

emissions

(lb/hr)

Actual

emissions

(ton/year)

Requested

Allowable

(lb/hr)

Requested

Allowable

(ton/year)

Particulate emissions

(PE/PM) (formerly

particulate matter, PM)

19 19 83.2 19 83.2

PM # 10 microns in

diameter (PE/PM10)

19 19 83.2 19 83.2

PM # 2.5 microns in

diameter (PE/PM2.5)

19 19 83.2 19 83.2

Sulfur dioxide (SO2) 4.6 4.6 20.1 4.6 20.1

Nitrogen oxides (NOx) 460 23 100.7 23 100.7

Carbon monoxide (CO) 140 14 80.2 14 80.2

Organic compounds (OC) 130 13 59.3 13 59.3

Volatile organic

compounds (VOC)

130 13 59.3 13 59.3

Lead (Pb) 0 0 0 0 0

Total Hazardous Air

Pollutants (HAPs)

10.3 1.03 4.50 1.03 4.50
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Oregon Clean Energy Center - 0448020102 Page 2 PTI/PTIO Application - A0045417

Highest single HAP 3 0.3 1.34 0.3 1.34

Hazardous Air Pollutants (HAPs):

Pollutant Emissions

before controls

(max)* (lb/hr)

Actual

emissions

(lb/hr)

Actual

emissions

(ton/year)

Requested

Allowable

(lb/hr)

Requested

Allowable

(ton/year)

Toluene 3 0.3 1.3 0.3 1.3

Formaldehyde 3 0.3 1.34 0.3 1.34

Sulfuric Acid 2.47 2.47 10.8 2.47 10.8

Ammonia 21 21 92 21 92

Best Available Technology (BAT) - For each pollutant for which the Requested Allowable in the above table exceeds 10

tons per year, BAT, as defined in OAC 3745-31-01, is required. Describe what has been selected as BAT and the basis for

the selection: 

See Section 4 - BACT/BAT analysis of the permit application document

Control Equipment - Does this air contaminant source employ emissions control equipment?

See Facility Profile

Process Flow Diagram - Attach a Process Flow Diagram to this application for this air contaminant source. See the

application instructions for additional information.

Process Flow Diagrams:

Description Type EAC Form Type Public Document

Id

Process Flow Diagram_Rev Process flow

diagram

628569

Modeling information: (Note: items in bold in Tables 7-A and/or 7-B, as applicable, are required even if the tables do

not otherwise need to be completed. If applicable, all information is required An air quality modeling analysis is

required for PTIs and PTIOs for new installations or modifications, as defined in OAC rule 3745-31-01, where either the

increase of toxic air contaminants from any air contaminant source or the increase of any other pollutant for all air

contaminant sources combined exceed a threshold listed below. This analysis is to assure that the impact from the

requested project will not exceed Ohios Acceptable Incremental Impacts for criteria pollutants and/or Maximum Allowable

Ground Level Concentrations (MAGLC) for toxic air contaminants. (See Ohio EPA, DAPCs Engineering Guide #69 for more

information.) Permit requests that would have unacceptable impacts cannot be approved as proposed. See the line-by-line

PTI/PTIO instructions for additional information.

See Facility Profile

Request for Federally Enforceable Limits - As part of this permit application, do you wish to propose voluntary restrictions

to limit emissions in order to avoid specific requirements listed below, (i.e., are you requesting federally enforceable limits to

obtain synthetic minor status)?

No

Continuous Emissions Monitoring Does this air contaminant source utilize any continuous emissions monitoring (CEM)

equipment for indicating or demonstrating compliance? This does not include continuous parametric monitoring systems.

See Facility Profile

EAC Forms The appropriate Emissions Activity Category (EAC) form(s) must be completed and attached for each air

contaminant source. At least one complete EAC form must be submitted for each air contaminant source for the application

to be considered complete. Refer to the list attached to the application instructions. Please indicate which EAC form

corresponds to this air contaminant source.

Process Flow Diagrams:

Description Type EAC Form Type Public Document
Oregon Clean Energy Center - 0448020102 Page 3 PTI/PTIO Application - A0045417

Id

CTG #1 EAC 3862 Stationary Internal

Combustion Engine (2003)

628322
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Oregon Clean Energy Center - 0448020102 Page 1 PTI/PTIO Application - A0045417

Section II - Specific Air Contaminant Source Information Facility ID: 0448020102

Emissions Unit ID: TMP173332

Company Equipment ID: CTG #2

One copy of this section should be filled out for each air contaminant source (emissions unit) covered by this

PTI/PTIO application identified in Section I, Question 5. See the application instructions for additional information.

Air Contaminant Source Installation or Modification Schedule Check all that apply (must be completed regardless of

date of installation or modification):

New installation (for which construction has not yet begun, in accordance with OAC rule 3745-31-33). When will you begin

to install the air contaminant source?

after installation permit has been issued

SCC Codes - List all Source Classification Code(s) (SCC) that describe the process(es) performed by this air contaminant

source (e.g., 1-02-002-04).

See Facility Profile

Emissions Information - The following table requests information needed to determine the applicable requirements and the

compliance status of this air contaminant source with those requirements. Suggestions for how to estimate emissions may

be found in the instructions to the Emissions Activity Category (EAC) forms required with this application. If you need further

assistance, contact your District Office/Local Air Agency representative.

If total potential emissions of HAPs or any Toxic Air Contaminant (as identified in OAC rule 3745-114-01) are greater

than 1 ton/yr, fill in the table for that (those) pollutant(s). For all other pollutants, if Emissions before controls (max), lb/hr

multiplied by 24 hours/day is greater than 10 lbs/day, fill in the table for that pollutant.

Actual emissions are calculated including add-on control equipment. If you have no add-on control equipment,

Emissions before controls will be the same as Actual emissions.

Actual emissions and Requested Allowable should be based on operating 8760 hr/yr unless you are requesting federally

enforceable operating restrictions to limit emissions. If so, calculate emissions based on requested operating restrictions

and describe in your calculations.

If you use units other than lbs/hr or ton/yr, specify the units used (e.g., gr/dscf, lb/ton charged, lb/MMBtu, tons/12-

months).

Requested Allowable (ton/yr) is often equivalent to Potential to Emit (PTE) as defined in OAC rule 3745-31-01 and OAC

rule 3745-77-01.

Pollutant Emissions

before controls

(max)* (lb/hr)

Actual

emissions

(lb/hr)

Actual

emissions

(ton/year)

Requested

Allowable

(lb/hr)

Requested

Allowable

(ton/year)

Particulate emissions

(PE/PM) (formerly

particulate matter, PM)

19 19 83.2 19 83.2

PM # 10 microns in

diameter (PE/PM10)

19 19 83.2 19 83.2

PM # 2.5 microns in

diameter (PE/PM2.5)

19 19 83.2 19 83.2

Sulfur dioxide (SO2) 4.6 4.6 20.1 4.6 20.1

Nitrogen oxides (NOx) 460 23 100.7 23 100.7

Carbon monoxide (CO) 140 14 80.2 14 80.2

Organic compounds (OC) 130 13 59.3 13 59.3

Volatile organic

compounds (VOC)

130 13 59.3 13 59.3

Lead (Pb) 0 0 0 0 0

Total Hazardous Air

Pollutants (HAPs)

10.3 1.03 4.5 1.03 4.5
4.

5.

6.

7.

8.

9.

10.

Oregon Clean Energy Center - 0448020102 Page 2 PTI/PTIO Application - A0045417

Highest single HAP 3 0.3 1.34 0.3 1.34

Hazardous Air Pollutants (HAPs):

Pollutant Emissions

before controls

(max)* (lb/hr)

Actual

emissions

(lb/hr)

Actual

emissions

(ton/year)

Requested

Allowable

(lb/hr)

Requested

Allowable

(ton/year)

Toluene 3 0.3 1.3 0.3 1.3

Formaldehyde 3 0.3 1.34 0.3 1.34

Sulfuric Acid 2.47 2.47 10.8 2.47 10.8

Ammonia 21 21 92 21 92

Best Available Technology (BAT) - For each pollutant for which the Requested Allowable in the above table exceeds 10

tons per year, BAT, as defined in OAC 3745-31-01, is required. Describe what has been selected as BAT and the basis for

the selection: 

See Section 4 - BACT/BAT analysis of the permit application document

Control Equipment - Does this air contaminant source employ emissions control equipment?

See Facility Profile

Process Flow Diagram - Attach a Process Flow Diagram to this application for this air contaminant source. See the

application instructions for additional information.

Process Flow Diagrams:

Description Type EAC Form Type Public Document

Id

Process Flow Diagram_Rev Process flow

diagram

628569

Modeling information: (Note: items in bold in Tables 7-A and/or 7-B, as applicable, are required even if the tables do

not otherwise need to be completed. If applicable, all information is required An air quality modeling analysis is

required for PTIs and PTIOs for new installations or modifications, as defined in OAC rule 3745-31-01, where either the

increase of toxic air contaminants from any air contaminant source or the increase of any other pollutant for all air

contaminant sources combined exceed a threshold listed below. This analysis is to assure that the impact from the

requested project will not exceed Ohios Acceptable Incremental Impacts for criteria pollutants and/or Maximum Allowable

Ground Level Concentrations (MAGLC) for toxic air contaminants. (See Ohio EPA, DAPCs Engineering Guide #69 for more

information.) Permit requests that would have unacceptable impacts cannot be approved as proposed. See the line-by-line

PTI/PTIO instructions for additional information.

See Facility Profile

Request for Federally Enforceable Limits - As part of this permit application, do you wish to propose voluntary restrictions

to limit emissions in order to avoid specific requirements listed below, (i.e., are you requesting federally enforceable limits to

obtain synthetic minor status)?

No

Continuous Emissions Monitoring Does this air contaminant source utilize any continuous emissions monitoring (CEM)

equipment for indicating or demonstrating compliance? This does not include continuous parametric monitoring systems.

See Facility Profile

EAC Forms The appropriate Emissions Activity Category (EAC) form(s) must be completed and attached for each air

contaminant source. At least one complete EAC form must be submitted for each air contaminant source for the application

to be considered complete. Refer to the list attached to the application instructions. Please indicate which EAC form

corresponds to this air contaminant source.

Process Flow Diagrams:

Description Type EAC Form Type Public Document
Oregon Clean Energy Center - 0448020102 Page 3 PTI/PTIO Application - A0045417

Id

CTG #2 EAC 3862 Stationary Internal

Combustion Engine (2003)

628323
1.

2.

3.

-

-

-

-

-

Oregon Clean Energy Center - 0448020102 Page 1 PTI/PTIO Application - A0045417

Section II - Specific Air Contaminant Source Information Facility ID: 0448020102

Emissions Unit ID: TMP173333

Company Equipment ID: Auxiliary Boiler

One copy of this section should be filled out for each air contaminant source (emissions unit) covered by this

PTI/PTIO application identified in Section I, Question 5. See the application instructions for additional information.

Air Contaminant Source Installation or Modification Schedule Check all that apply (must be completed regardless of

date of installation or modification):

New installation (for which construction has not yet begun, in accordance with OAC rule 3745-31-33). When will you begin

to install the air contaminant source?

after installation permit has been issued

SCC Codes - List all Source Classification Code(s) (SCC) that describe the process(es) performed by this air contaminant

source (e.g., 1-02-002-04).

See Facility Profile

Emissions Information - The following table requests information needed to determine the applicable requirements and the

compliance status of this air contaminant source with those requirements. Suggestions for how to estimate emissions may

be found in the instructions to the Emissions Activity Category (EAC) forms required with this application. If you need further

assistance, contact your District Office/Local Air Agency representative.

If total potential emissions of HAPs or any Toxic Air Contaminant (as identified in OAC rule 3745-114-01) are greater

than 1 ton/yr, fill in the table for that (those) pollutant(s). For all other pollutants, if Emissions before controls (max), lb/hr

multiplied by 24 hours/day is greater than 10 lbs/day, fill in the table for that pollutant.

Actual emissions are calculated including add-on control equipment. If you have no add-on control equipment,

Emissions before controls will be the same as Actual emissions.

Actual emissions and Requested Allowable should be based on operating 8760 hr/yr unless you are requesting federally

enforceable operating restrictions to limit emissions. If so, calculate emissions based on requested operating restrictions

and describe in your calculations.

If you use units other than lbs/hr or ton/yr, specify the units used (e.g., gr/dscf, lb/ton charged, lb/MMBtu, tons/12-

months).

Requested Allowable (ton/yr) is often equivalent to Potential to Emit (PTE) as defined in OAC rule 3745-31-01 and OAC

rule 3745-77-01.

Pollutant Emissions

before controls

(max)* (lb/hr)

Actual

emissions

(lb/hr)

Actual

emissions

(ton/year)

Requested

Allowable

(lb/hr)

Requested

Allowable

(ton/year)

Particulate emissions

(PE/PM) (formerly

particulate matter, PM)

0.45 0.45 1.97 0.45 1.97

PM # 10 microns in

diameter (PE/PM10)

0.45 0.45 1.97 0.45 1.97

PM # 2.5 microns in

diameter (PE/PM2.5)

0.45 0.45 1.97 0.45 1.97

Sulfur dioxide (SO2) 0.06 0.06 0.28 0.06 0.28

Nitrogen oxides (NOx) 0.9 0.9 3.94 0.9 3.94

Carbon monoxide (CO) 3.33 3.33 14.59 3.33 14.59

Organic compounds (OC) 0.36 0.36 1.58 0.36 1.58

Volatile organic

compounds (VOC)

0.36 0.36 1.58 0.36 1.58

Lead (Pb) 0 0 0 0 0

Total Hazardous Air

Pollutants (HAPs)

0.008 0.008 0.04 0.008 0.04
4.

5.

6.

7.

8.

9.

10.

Oregon Clean Energy Center - 0448020102 Page 2 PTI/PTIO Application - A0045417

Highest single HAP 0.007 0.007 0.029 0.007 0.029

Best Available Technology (BAT) - For each pollutant for which the Requested Allowable in the above table exceeds 10

tons per year, BAT, as defined in OAC 3745-31-01, is required. Describe what has been selected as BAT and the basis for

the selection: 

See Section 4 - BACT/BAT analysis of the permit application document

Control Equipment - Does this air contaminant source employ emissions control equipment?

See Facility Profile

Process Flow Diagram - Attach a Process Flow Diagram to this application for this air contaminant source. See the

application instructions for additional information.

Process Flow Diagrams:

Description Type EAC Form Type Public Document

Id

Process Flow Diagram_Rev Process flow

diagram

628569

Modeling information: (Note: items in bold in Tables 7-A and/or 7-B, as applicable, are required even if the tables do

not otherwise need to be completed. If applicable, all information is required An air quality modeling analysis is

required for PTIs and PTIOs for new installations or modifications, as defined in OAC rule 3745-31-01, where either the

increase of toxic air contaminants from any air contaminant source or the increase of any other pollutant for all air

contaminant sources combined exceed a threshold listed below. This analysis is to assure that the impact from the

requested project will not exceed Ohios Acceptable Incremental Impacts for criteria pollutants and/or Maximum Allowable

Ground Level Concentrations (MAGLC) for toxic air contaminants. (See Ohio EPA, DAPCs Engineering Guide #69 for more

information.) Permit requests that would have unacceptable impacts cannot be approved as proposed. See the line-by-line

PTI/PTIO instructions for additional information.

See Facility Profile

Request for Federally Enforceable Limits - As part of this permit application, do you wish to propose voluntary restrictions

to limit emissions in order to avoid specific requirements listed below, (i.e., are you requesting federally enforceable limits to

obtain synthetic minor status)?

No

Continuous Emissions Monitoring Does this air contaminant source utilize any continuous emissions monitoring (CEM)

equipment for indicating or demonstrating compliance? This does not include continuous parametric monitoring systems.

See Facility Profile

EAC Forms The appropriate Emissions Activity Category (EAC) form(s) must be completed and attached for each air

contaminant source. At least one complete EAC form must be submitted for each air contaminant source for the application

to be considered complete. Refer to the list attached to the application instructions. Please indicate which EAC form

corresponds to this air contaminant source.

Process Flow Diagrams:

Description Type EAC Form Type Public Document

Id

Aux. Boiler EAC EAC 3101 Fuel burning operation

(2003)

627123
1.

2.

3.

-

-

-

-

-

Oregon Clean Energy Center - 0448020102 Page 1 PTI/PTIO Application - A0045417

Section II - Specific Air Contaminant Source Information Facility ID: 0448020102

Emissions Unit ID: TMP173334

Company Equipment ID: Emergency

Generator

One copy of this section should be filled out for each air contaminant source (emissions unit) covered by this

PTI/PTIO application identified in Section I, Question 5. See the application instructions for additional information.

Air Contaminant Source Installation or Modification Schedule Check all that apply (must be completed regardless of

date of installation or modification):

New installation (for which construction has not yet begun, in accordance with OAC rule 3745-31-33). When will you begin

to install the air contaminant source?

after installation permit has been issued

SCC Codes - List all Source Classification Code(s) (SCC) that describe the process(es) performed by this air contaminant

source (e.g., 1-02-002-04).

See Facility Profile

Emissions Information - The following table requests information needed to determine the applicable requirements and the

compliance status of this air contaminant source with those requirements. Suggestions for how to estimate emissions may

be found in the instructions to the Emissions Activity Category (EAC) forms required with this application. If you need further

assistance, contact your District Office/Local Air Agency representative.

If total potential emissions of HAPs or any Toxic Air Contaminant (as identified in OAC rule 3745-114-01) are greater

than 1 ton/yr, fill in the table for that (those) pollutant(s). For all other pollutants, if Emissions before controls (max), lb/hr

multiplied by 24 hours/day is greater than 10 lbs/day, fill in the table for that pollutant.

Actual emissions are calculated including add-on control equipment. If you have no add-on control equipment,

Emissions before controls will be the same as Actual emissions.

Actual emissions and Requested Allowable should be based on operating 8760 hr/yr unless you are requesting federally

enforceable operating restrictions to limit emissions. If so, calculate emissions based on requested operating restrictions

and describe in your calculations.

If you use units other than lbs/hr or ton/yr, specify the units used (e.g., gr/dscf, lb/ton charged, lb/MMBtu, tons/12-

months).

Requested Allowable (ton/yr) is often equivalent to Potential to Emit (PTE) as defined in OAC rule 3745-31-01 and OAC

rule 3745-77-01.

Pollutant Emissions

before controls

(max)* (lb/hr)

Actual

emissions

(lb/hr)

Actual

emissions

(ton/year)

Requested

Allowable

(lb/hr)

Requested

Allowable

(ton/year)

Particulate emissions

(PE/PM) (formerly

particulate matter, PM)

0.66 0.66 0.17 0.66 0.17

PM # 10 microns in

diameter (PE/PM10)

0.66 0.66 0.17 0.66 0.17

PM # 2.5 microns in

diameter (PE/PM2.5)

0.66 0.66 0.17 0.66 0.17

Sulfur dioxide (SO2) 0.02 0.02 0.01 0.02 0.01

Nitrogen oxides (NOx) 18.53 18.53 4.63 18.53 4.63

Carbon monoxide (CO) 11.56 11.56 2.89 11.56 2.89

Organic compounds (OC) 2.62 2.62 0.65 2.62 0.65

Volatile organic

compounds (VOC)

2.62 2.62 0.65 2.62 0.65

Lead (Pb) 1.97E-04 1.97E-04 4.93E-05 1.97E-04 4.93E-05

Total Hazardous Air

Pollutants (HAPs)

0.008 0.008 0.002 0.008 0.002
4.

5.

6.

7.

8.

-

9.

10.

Oregon Clean Energy Center - 0448020102 Page 2 PTI/PTIO Application - A0045417

Highest single HAP 0.002 0.002 0.0006 0.002 0.0006

Best Available Technology (BAT) - For each pollutant for which the Requested Allowable in the above table exceeds 10

tons per year, BAT, as defined in OAC 3745-31-01, is required. Describe what has been selected as BAT and the basis for

the selection: 

N/A

Control Equipment - Does this air contaminant source employ emissions control equipment?

See Facility Profile

Process Flow Diagram - Attach a Process Flow Diagram to this application for this air contaminant source. See the

application instructions for additional information.

Process Flow Diagrams:

Description Type EAC Form Type Public Document

Id

Process Flow Diagram_Rev Process flow

diagram

628569

Modeling information: (Note: items in bold in Tables 7-A and/or 7-B, as applicable, are required even if the tables do

not otherwise need to be completed. If applicable, all information is required An air quality modeling analysis is

required for PTIs and PTIOs for new installations or modifications, as defined in OAC rule 3745-31-01, where either the

increase of toxic air contaminants from any air contaminant source or the increase of any other pollutant for all air

contaminant sources combined exceed a threshold listed below. This analysis is to assure that the impact from the

requested project will not exceed Ohios Acceptable Incremental Impacts for criteria pollutants and/or Maximum Allowable

Ground Level Concentrations (MAGLC) for toxic air contaminants. (See Ohio EPA, DAPCs Engineering Guide #69 for more

information.) Permit requests that would have unacceptable impacts cannot be approved as proposed. See the line-by-line

PTI/PTIO instructions for additional information.

See Facility Profile

Request for Federally Enforceable Limits - As part of this permit application, do you wish to propose voluntary restrictions

to limit emissions in order to avoid specific requirements listed below, (i.e., are you requesting federally enforceable limits to

obtain synthetic minor status)?

Yes

If yes, why are you requesting federally enforceable limits? 

Avoid another requirement

Describe:

Restricted to 500 hrs/year of operation to comply with Ohio EPA requirements for

emergency operation

Continuous Emissions Monitoring Does this air contaminant source utilize any continuous emissions monitoring (CEM)

equipment for indicating or demonstrating compliance? This does not include continuous parametric monitoring systems.

See Facility Profile

EAC Forms The appropriate Emissions Activity Category (EAC) form(s) must be completed and attached for each air

contaminant source. At least one complete EAC form must be submitted for each air contaminant source for the application

to be considered complete. Refer to the list attached to the application instructions. Please indicate which EAC form

corresponds to this air contaminant source.

Process Flow Diagrams:

Description Type EAC Form Type Public Document

Id

Emergency Generator EAC EAC 3862 Stationary Internal

Combustion Engine (2003)

628324
1.

2.

3.

-

-

-

-

-

Oregon Clean Energy Center - 0448020102 Page 3 PTI/PTIO Application - A0045417

Section II - Specific Air Contaminant Source Information Facility ID: 0448020102

Emissions Unit ID: TMP173335

Company Equipment ID: Emergency Fire

Pump

One copy of this section should be filled out for each air contaminant source (emissions unit) covered by this

PTI/PTIO application identified in Section I, Question 5. See the application instructions for additional information.

Air Contaminant Source Installation or Modification Schedule Check all that apply (must be completed regardless of

date of installation or modification):

New installation (for which construction has not yet begun, in accordance with OAC rule 3745-31-33). When will you begin

to install the air contaminant source?

after installation permit has been issued

SCC Codes - List all Source Classification Code(s) (SCC) that describe the process(es) performed by this air contaminant

source (e.g., 1-02-002-04).

See Facility Profile

Emissions Information - The following table requests information needed to determine the applicable requirements and the

compliance status of this air contaminant source with those requirements. Suggestions for how to estimate emissions may

be found in the instructions to the Emissions Activity Category (EAC) forms required with this application. If you need further

assistance, contact your District Office/Local Air Agency representative.

If total potential emissions of HAPs or any Toxic Air Contaminant (as identified in OAC rule 3745-114-01) are greater

than 1 ton/yr, fill in the table for that (those) pollutant(s). For all other pollutants, if Emissions before controls (max), lb/hr

multiplied by 24 hours/day is greater than 10 lbs/day, fill in the table for that pollutant.

Actual emissions are calculated including add-on control equipment. If you have no add-on control equipment,

Emissions before controls will be the same as Actual emissions.

Actual emissions and Requested Allowable should be based on operating 8760 hr/yr unless you are requesting federally

enforceable operating restrictions to limit emissions. If so, calculate emissions based on requested operating restrictions

and describe in your calculations.

If you use units other than lbs/hr or ton/yr, specify the units used (e.g., gr/dscf, lb/ton charged, lb/MMBtu, tons/12-

months).

Requested Allowable (ton/yr) is often equivalent to Potential to Emit (PTE) as defined in OAC rule 3745-31-01 and OAC

rule 3745-77-01.

Pollutant Emissions

before controls

(max)* (lb/hr)

Actual

emissions

(lb/hr)

Actual

emissions

(ton/year)

Requested

Allowable

(lb/hr)

Requested

Allowable

(ton/year)

Particulate emissions

(PE/PM) (formerly

particulate matter, PM)

0.07 0.07 0.02 0.07 0.02

PM # 10 microns in

diameter (PE/PM10)

0.08 0.08 0.02 0.08 0.02

PM # 2.5 microns in

diameter (PE/PM2.5)

0.08 0.08 0.02 0.08 0.02

Sulfur dioxide (SO2) 0.00 0.00 0.00 0.00 0.00

Nitrogen oxides (NOx) 1.44 1.44 0.36 1.44 0.36

Carbon monoxide (CO) 1.44 1.44 0.36 1.44 0.36

Organic compounds (OC) 0.2 0.2 0.05 0.2 0.05

Volatile organic

compounds (VOC)

0.2 0.2 0.05 0.2 0.05

Lead (Pb) 2.45E-05 2.45E-05 6.13E-06 2.45E-05 6.13E-06

Total Hazardous Air

Pollutants (HAPs)

0.008 0.008 0.002 0.008 0.002
4.

5.

6.

7.

8.

-

9.

10.

Oregon Clean Energy Center - 0448020102 Page 1 PTI/PTIO Application - A0045417

Highest single HAP 0.002 0.002 0.0006 0.002 0.0006

Best Available Technology (BAT) - For each pollutant for which the Requested Allowable in the above table exceeds 10

tons per year, BAT, as defined in OAC 3745-31-01, is required. Describe what has been selected as BAT and the basis for

the selection: 

N/A

Control Equipment - Does this air contaminant source employ emissions control equipment?

See Facility Profile

Process Flow Diagram - Attach a Process Flow Diagram to this application for this air contaminant source. See the

application instructions for additional information.

Process Flow Diagrams:

Description Type EAC Form Type Public Document

Id

Process Flow Diagram_Rev Process flow

diagram

628569

Modeling information: (Note: items in bold in Tables 7-A and/or 7-B, as applicable, are required even if the tables do

not otherwise need to be completed. If applicable, all information is required An air quality modeling analysis is

required for PTIs and PTIOs for new installations or modifications, as defined in OAC rule 3745-31-01, where either the

increase of toxic air contaminants from any air contaminant source or the increase of any other pollutant for all air

contaminant sources combined exceed a threshold listed below. This analysis is to assure that the impact from the

requested project will not exceed Ohios Acceptable Incremental Impacts for criteria pollutants and/or Maximum Allowable

Ground Level Concentrations (MAGLC) for toxic air contaminants. (See Ohio EPA, DAPCs Engineering Guide #69 for more

information.) Permit requests that would have unacceptable impacts cannot be approved as proposed. See the line-by-line

PTI/PTIO instructions for additional information.

See Facility Profile

Request for Federally Enforceable Limits - As part of this permit application, do you wish to propose voluntary restrictions

to limit emissions in order to avoid specific requirements listed below, (i.e., are you requesting federally enforceable limits to

obtain synthetic minor status)?

Yes

If yes, why are you requesting federally enforceable limits? 

Avoid another requirement

Describe:

500 hour/year operational restriction to satisfy Ohio EPA requirement for emergency

operation

Continuous Emissions Monitoring Does this air contaminant source utilize any continuous emissions monitoring (CEM)

equipment for indicating or demonstrating compliance? This does not include continuous parametric monitoring systems.

See Facility Profile

EAC Forms The appropriate Emissions Activity Category (EAC) form(s) must be completed and attached for each air

contaminant source. At least one complete EAC form must be submitted for each air contaminant source for the application

to be considered complete. Refer to the list attached to the application instructions. Please indicate which EAC form

corresponds to this air contaminant source.

Process Flow Diagrams:

Description Type EAC Form Type Public Document

Id

Emergency Fire Pump EAC EAC 3862 Stationary Internal

Combustion Engine (2003)

628325
1.

2.

3.

-

-

-

-

-

Oregon Clean Energy Center - 0448020102 Page 2 PTI/PTIO Application - A0045417

Section II - Specific Air Contaminant Source Information Facility ID: 0448020102

Emissions Unit ID: TMP173336

Company Equipment ID: Wet Cooling Tower

One copy of this section should be filled out for each air contaminant source (emissions unit) covered by this

PTI/PTIO application identified in Section I, Question 5. See the application instructions for additional information.

Air Contaminant Source Installation or Modification Schedule Check all that apply (must be completed regardless of

date of installation or modification):

New installation (for which construction has not yet begun, in accordance with OAC rule 3745-31-33). When will you begin

to install the air contaminant source?

after installation permit has been issued

SCC Codes - List all Source Classification Code(s) (SCC) that describe the process(es) performed by this air contaminant

source (e.g., 1-02-002-04).

See Facility Profile

Emissions Information - The following table requests information needed to determine the applicable requirements and the

compliance status of this air contaminant source with those requirements. Suggestions for how to estimate emissions may

be found in the instructions to the Emissions Activity Category (EAC) forms required with this application. If you need further

assistance, contact your District Office/Local Air Agency representative.

If total potential emissions of HAPs or any Toxic Air Contaminant (as identified in OAC rule 3745-114-01) are greater

than 1 ton/yr, fill in the table for that (those) pollutant(s). For all other pollutants, if Emissions before controls (max), lb/hr

multiplied by 24 hours/day is greater than 10 lbs/day, fill in the table for that pollutant.

Actual emissions are calculated including add-on control equipment. If you have no add-on control equipment,

Emissions before controls will be the same as Actual emissions.

Actual emissions and Requested Allowable should be based on operating 8760 hr/yr unless you are requesting federally

enforceable operating restrictions to limit emissions. If so, calculate emissions based on requested operating restrictions

and describe in your calculations.

If you use units other than lbs/hr or ton/yr, specify the units used (e.g., gr/dscf, lb/ton charged, lb/MMBtu, tons/12-

months).

Requested Allowable (ton/yr) is often equivalent to Potential to Emit (PTE) as defined in OAC rule 3745-31-01 and OAC

rule 3745-77-01.

Pollutant Emissions

before controls

(max)* (lb/hr)

Actual

emissions

(lb/hr)

Actual

emissions

(ton/year)

Requested

Allowable

(lb/hr)

Requested

Allowable

(ton/year)

Particulate emissions

(PE/PM) (formerly

particulate matter, PM)

1.00 1.00 4.39 1.00 4.39

PM # 10 microns in

diameter (PE/PM10)

1.00 1.00 4.39 1.00 4.39

PM # 2.5 microns in

diameter (PE/PM2.5)

1.00 1.00 4.39 1.00 4.39

Sulfur dioxide (SO2) 0 0 0 0 0

Nitrogen oxides (NOx) 0 0 0 0 0

Carbon monoxide (CO) 0 0 0 0 0

Organic compounds (OC) 0 0 0 0 0

Volatile organic

compounds (VOC)

0 0 0 0 0

Lead (Pb) 0 0 0 0 0

Total Hazardous Air

Pollutants (HAPs)

0 0 0 0 0
4.

5.

6.

7.

8.

9.

10.

Oregon Clean Energy Center - 0448020102 Page 1 PTI/PTIO Application - A0045417

Highest single HAP 0 0 0 0 0

Best Available Technology (BAT) - For each pollutant for which the Requested Allowable in the above table exceeds 10

tons per year, BAT, as defined in OAC 3745-31-01, is required. Describe what has been selected as BAT and the basis for

the selection: 

Drift Eliminators

Control Equipment - Does this air contaminant source employ emissions control equipment?

See Facility Profile

Process Flow Diagram - Attach a Process Flow Diagram to this application for this air contaminant source. See the

application instructions for additional information.

Process Flow Diagrams:

Description Type EAC Form Type Public Document

Id

Process Flow Diagram_Rev Process flow

diagram

628569

Modeling information: (Note: items in bold in Tables 7-A and/or 7-B, as applicable, are required even if the tables do

not otherwise need to be completed. If applicable, all information is required An air quality modeling analysis is

required for PTIs and PTIOs for new installations or modifications, as defined in OAC rule 3745-31-01, where either the

increase of toxic air contaminants from any air contaminant source or the increase of any other pollutant for all air

contaminant sources combined exceed a threshold listed below. This analysis is to assure that the impact from the

requested project will not exceed Ohios Acceptable Incremental Impacts for criteria pollutants and/or Maximum Allowable

Ground Level Concentrations (MAGLC) for toxic air contaminants. (See Ohio EPA, DAPCs Engineering Guide #69 for more

information.) Permit requests that would have unacceptable impacts cannot be approved as proposed. See the line-by-line

PTI/PTIO instructions for additional information.

See Facility Profile

Request for Federally Enforceable Limits - As part of this permit application, do you wish to propose voluntary restrictions

to limit emissions in order to avoid specific requirements listed below, (i.e., are you requesting federally enforceable limits to

obtain synthetic minor status)?

No

Continuous Emissions Monitoring Does this air contaminant source utilize any continuous emissions monitoring (CEM)

equipment for indicating or demonstrating compliance? This does not include continuous parametric monitoring systems.

See Facility Profile

EAC Forms The appropriate Emissions Activity Category (EAC) form(s) must be completed and attached for each air

contaminant source. At least one complete EAC form must be submitted for each air contaminant source for the application

to be considered complete. Refer to the list attached to the application instructions. Please indicate which EAC form

corresponds to this air contaminant source.

Process Flow Diagrams:

Description Type EAC Form Type Public Document

Id

Cooling Tower Process

Operation

EAC 3100 Process operation (2003) 627128
Facility Profile Report

Facility Name: Oregon Clean Energy Center

ID: 0448020102
-

-

-

-

-

-

 Page 1 Facility Profile Report (0448020102): Oregon Clean Energy Center

Facility : 0448020102 Aug 23 2012, 15:04:46

Facility Information

Facility ID: 0448020102

FacilityName: Oregon Clean Energy Center

Facility Description: 800 MW combined cycle gas turbine (CCGT) facility

Address1: 816 Lallendorf Rd

Address2:

City: Oregon State: Ohio

Zip Code: 43616

Portable:

Operating Status: Not Installed

Permitting Classification: NONE PER Due Date: None

Transitional Status: None

Title V Permit Status: None Title V Certification Report Due Date:

Anticipated Emissions Reporting

Category for 2012:

NONE

Core Place ID: 313477

Latitude: 41.667587

Longtitude: -83.44293

Yearly Emissions Reporting Category

Year Category Enabled Status

SIC Codes

NAICS Codes

221112 Fossil Fuel Electric Power Generation

Contacts

Contact Type Contact Person Phone Number Email Start Date End Date

Federal Rules Applicability

Subject to MACT: Subject to PSD:

Subject to NESHAPS: Subject to non-attainment NSR:

Subject to NSPS: Subject to 112(r):

Subject to Title IV:
-

-

 Page 2 Facility Profile Report (0448020102): Oregon Clean Energy Center

Emission Unit : TMP173331 Aug 23 2012, 15:04:46

Emission Unit Information

DAPC Emissions Unit ID: TMP173331

DAPC Description:

Company Equipment ID: CTG #1

Company Description: One combustion turbine generator exhausting through a dedicated Heat Recovery Steam

Generator (HRSG). The HRSG will generate steam from the waste heat energy in the

exhaust gas. Each HRSG will be equipped with supplemental fuel firing via a duct

burner. The duct burner provides additional energy to the HRSG, which produces more

steam that can be fed to the steam turbine generator (STG). Steam generated in the

HRSG will be expanded through a STG multi-stage, reheat, condensing turbine and

associated electric generator to generate additional electricity

Operating Status: Not Installed

Completion of Initial Installation

Date:

04/30/2016 Begin Installation/Modification Date: 10/01/2013

Commence Operation After

Installation or Latest Modification

Date:

Title V EU Classification: Non-insignificant Exemption Status: NA

Boiler/Turbine/Generator Design

Capacity:

Turbine ORIS Boiler ID:

Processes
-

-

 Page 3 Facility Profile Report (0448020102): Oregon Clean Energy Center

Emission Unit : TMP173332 Aug 23 2012, 15:04:46

Emission Unit Information

DAPC Emissions Unit ID: TMP173332

DAPC Description:

Company Equipment ID: CTG #2

Company Description: One combustion turbine generator exhausting through a dedicated Heat Recovery Steam

Generator (HRSG). The HRSG will generate steam from the waste heat energy in the

exhaust gas. Each HRSG will be equipped with supplemental fuel firing via a duct

burner. The duct burner provides additional energy to the HRSG, which produces more

steam that can be fed to the steam turbine generator (STG). Steam generated in the

HRSG will be expanded through a STG multi-stage, reheat, condensing turbine and

associated electric generator to generate additional electricity

Operating Status: Not Installed

Completion of Initial Installation

Date:

04/30/2016 Begin Installation/Modification Date: 10/01/2013

Commence Operation After

Installation or Latest Modification

Date:

Title V EU Classification: Non-insignificant Exemption Status: NA

Boiler/Turbine/Generator Design

Capacity:

Turbine ORIS Boiler ID:

Processes
-

-

 Page 4 Facility Profile Report (0448020102): Oregon Clean Energy Center

Emission Unit : TMP173333 Aug 23 2012, 15:04:46

Emission Unit Information

DAPC Emissions Unit ID: TMP173333

DAPC Description:

Company Equipment ID: Auxiliary Boiler

Company Description: 90 MMBtu/hr auxiliary boiler operated as needed to keep the HRSG warm during periods

of turbine shutdown and provide sealing steam to the steam turbine during warm and

hot starts.

Operating Status: Not Installed

Completion of Initial Installation

Date:

04/30/2016 Begin Installation/Modification Date: 10/01/2013

Commence Operation After

Installation or Latest Modification

Date:

Title V EU Classification: Non-insignificant Exemption Status: NA

Boiler/Turbine/Generator Design

Capacity:

Boiler/Heater ORIS Boiler ID:

Processes
-

-

 Page 5 Facility Profile Report (0448020102): Oregon Clean Energy Center

Emission Unit : TMP173334 Aug 23 2012, 15:04:46

Emission Unit Information

DAPC Emissions Unit ID: TMP173334

DAPC Description:

Company Equipment ID: Emergency Generator

Company Description: 1,500 kW emergency diesel-fired generator to provide on-site emergency power

capabiities independent of the utility grid

Operating Status: Not Installed

Completion of Initial Installation

Date:

04/30/2016 Begin Installation/Modification Date: 10/01/2013

Commence Operation After

Installation or Latest Modification

Date:

Title V EU Classification: Insignificant Exemption Status: NA

Boiler/Turbine/Generator Design

Capacity:

Not Applicable Design Capacity Units:

ORIS Boiler ID:

Processes
-

-

 Page 6 Facility Profile Report (0448020102): Oregon Clean Energy Center

Emission Unit : TMP173335 Aug 23 2012, 15:04:46

Emission Unit Information

DAPC Emissions Unit ID: TMP173335

DAPC Description:

Company Equipment ID: Emergency Fire Pump

Company Description: 250 hp emergency diesel-fired firepump to provide on-site fire fighting capabilities

independent of the utility grid

Operating Status: Not Installed

Completion of Initial Installation

Date:

04/30/2016 Begin Installation/Modification Date: 10/01/2013

Commence Operation After

Installation or Latest Modification

Date:

Title V EU Classification: Insignificant Exemption Status: NA

Boiler/Turbine/Generator Design

Capacity:

Not Applicable Design Capacity Units:

ORIS Boiler ID:

Processes
-

-

 Page 7 Facility Profile Report (0448020102): Oregon Clean Energy Center

Emission Unit : TMP173336 Aug 23 2012, 15:04:46

Emission Unit Information

DAPC Emissions Unit ID: TMP173336

DAPC Description:

Company Equipment ID: Wet Cooling Tower

Company Description: 12- Cell Wet Cooling Tower equipped with a high efficiency drift eliminator

Operating Status: Not Installed

Completion of Initial Installation

Date:

04/30/2016 Begin Installation/Modification Date: 10/01/2013

Commence Operation After

Installation or Latest Modification

Date:

Title V EU Classification: Non-insignificant Exemption Status: NA

Boiler/Turbine/Generator Design

Capacity:

Not Applicable Design Capacity Units:

ORIS Boiler ID:

Processes
City: Chicago Author: MNesta Path: G:\Aproject\GIS\OCE\MXD\OCE_ProcessFlow.mxd

OREGONCLEAN

ENERGY,LLC

LucasCounty,Ohio

PROCESSFLOW

DIAGRAMDa

te:08/17/2012

CTG – Combustion Turbine Generator

HRSG – Heat Recovery Steam Generator

STG – Steam Turbine Generator

Air

Fuel

CTG

Exhaust

Stack

Exhaust

Air

Fuel

CTG

Exhaust

Stack

Exhaust

High Pressure Steam Condensate

Low Pressure Steam

Water 

Supply

Water 

Blowdown

Aux. 

Boiler

Fuel Stack

Exhaust

Emergency 

Generator Fuel

Stack

Exhaust

Fire 

Pump

Stack

Exhaust

Fuel
EPA FORM 3101 – REV2005 Page 1

FOR OHIO EPA USE

FACILITY ID: ___________________________

EU ID: _______________ PTI #:__________________

EMISSIONS ACTIVITY CATEGORY FORM

FUEL BURNING OPERATION

This form is to be completed for each fuel burning operation. State/Federal regulations which may apply to 

fuel burning operations are listed in the instructions. Note that there may be other regulations which apply 

to this emissions unit which are not included in this list

1. Reason this form is being submitted (check one) 

 New Permit Renewal or Modification of Air Permit Number(s) (e.g. B001)________

2. Maximum Operating Schedule: __24______hours per day; _365___days per year

If the schedule is less than 24 hours/day or 365 days/year, what limits the schedule to less than 

maximum? See instructions for examples. ______________________________ 

3. Input Capacity (million Btu/hr):

Rated

(Indicate units if other than mmBtu/hr)

Maximum

(Indicate units if other than mmBtu/hr)

Normal

(Indicate units if other than mmBtu/hr)

90 90 90

4. Output Capacity:

Rated

(lb steam/hr)

Maximum

(lb steam/hr)

Normal

(lb steam/hr)

 Not applicable - operation does not produce steam.

5. Percent of Operating Time Used for:

Process: ____100___%

Space Heat: _______%

6. Type of Draft (check one):

 Natural Induced Forced

7. Type of combustion monitoring (check one):

Fuel/Air Ratio Oxygen None

 Other (describe) ______________________________
EPA FORM 3101 – REV2005 Page 2

8. Type of Fuel Fired (complete all that apply):

Fuel* Fired as... Min. Heat 

Content

(Btu/unit)

Max. % 

Ash

Max. % 

Sulfur

Max. Annual 

Fuel Use

Average Hourly 

Fuel Use

Maximum Hourly 

Fuel Use

Coal Primary

 Backup tons lbs lbs

No. 2 Fuel Oil 

 

 Primary

 Backup gal gal gal

No. 6 Fuel Oil Primary

 Backup gal gal gal

Other** Oil Primary

 Backup gal gal gal

Natural Gas Primary

 Backup

1050 Btu/scf 751 MM

ft3

0.09 MM

ft3

0.09 MM

ft3

Wood Primary

 Backup tons lbs lbs

LPG Primary

 Backup gal gal gal

Other** Primary

 Backup

Other** Primary

 Backup

 * Please identify all combinations of fuels that are co-fired: _______________________________

 ** Identify other fuel(s): _______________________________

Coal-Fired Units

9. Type of Coal Firing (check one):

Pulverized-Wet Bottom Hand-Fired Chain Grate Traveling Grate

Pulverized-Dry Bottom Cyclones Spreader Stoker Fluidized Bed

Underfeed Stoker Other (describe) _________________________________

10. Flyash Reinjection:

 Yes No

11. Overfire Air:

 Yes No

Oil-Fired Units

12. Oil Preheater:

 Yes - Indicate Temperature_______deg. F

 No
EPA FORM 3100 – REV2005 1 of 2

FOR OHIO EPA USE

FACILITY ID:_____________________________________

 

EU ID: PTI 

#: 

EMISSIONS ACTIVITY CATEGORY FORM

GENERAL PROCESS OPERATION

This form is to be completed for each process operation when there is no specific emissions activity 

category (EAC) form applicable. If there is more than one end product for this process, copy and complete 

this form for each additional product (see instructions). Several State/Federal regulations which may apply 

to process operations are listed in the instructions. Note that there may be other regulations which apply to 

this emissions unit which are not included in this list.

1. Reason this form is being submitted (Check one) 

 New Permit Renewal or Modification of Air Permit Number(s) (e.g.P001)_______________

2. Maximum Operating Schedule: 24 hours per day ; 365 days per year

If the schedule is less than 24 hours/day or 365 days/year, what limits the schedule to less than 

maximum? See instructions for examples. _______________________________

3. End product of this process: Cooling water 

4. Hourly production rates (indicate appropriate units). Please see the instructions for clarification of 

“Maximum” and “Average” for new versus existing operations:

Minute Rate Units (e.g., widgets)

Average production 133,700 Gallon

Maximum production

5. Annual production rates (indicate appropriate units) Please see the instructions for clarification of 

“Maximum” and “Actual” for new versus existing operations:

Annual Rate Units (e.g., widgets)

Actual production

Maximum production
EPA FORM 3100 – REV2005 2 of 2

6. Type of operation (please check one):

 Continuous

Batch (please complete items below)

Minimum cycle* time (minutes): _________

Minimum time between cycles (minutes): _________

Maximum number of cycles per daily 24 hour period: _________

(Note: include cycle time and set up/clean up time.)

*”Cycle” refers to the time the equipment is in operation.

7. Materials used in process at maximum production rate (add rows/pages as needed):

Material Physical State at Standard 

Conditions

Principle Use Amount** 

Water Liquid Cooling 133,700 gpm

** Please indicate the amount and rate (e.g., lbs/hr, gallons/hr, lbs/cycle, etc.).

8. Please provide a narrative description of the process below (e.g., coating of metal parts using high 

VOC content coatings for the manufacture of widgets; emissions controlled by thermal oxidizer...):

___________________________________________________________________________

___See Section 2.3.4 of PTI Application Package_________________________

________________________________________________________________________________

________________________________________________________________________________

________________________________________________________________________________

________________________________________________________________________________

________________________________________________________________________________

________________________________________________________________________________

________________________________________________________________________________

________________________________________________________________________________

________________________________________________________________________________
EPA FORM 3862 - REV2005 Page 1

EMISSIONS ACTIVITY CATEGORY FORM

STATIONARY INTERNAL COMBUSTION ENGINE

This form is to be completed for each stationary reciprocating or gas turbine engine. State/Federal 

regulations which may apply to stationary internal combustion engines are listed in the instructions. Note 

that there may be other regulations which apply to this emissions unit which are not included in this list.

1. Reason this form is being submitted (Check one) 

 New Permit Renewal or Modification of Air Permit Number (e.g. P001)__________

2. Maximum Operating Schedule: __8,760_____ hours per day; _365____ days per year

If the schedule is less than 24 hours/day or 365 days/year, what limits the schedule to less than 

maximum? See instructions for examples. _____________________________________________

 

3. Engine type: Gas turbine Reciprocating

4. Purpose of engine: Driving pump or compressor Driving electrical generator

5. Normal use of engine: Emergency only Non-emergency

6. Engine Manufacturer: ___TBD_________________ Model No: ___TBD_________________

7. Engine exhaust 

configuration: simple cycle (no heat recovery)

(for turbines only) regenerative cycle (heat recovery to preheat combustion air)

cogeneration cycle (heat recovered to produce steam)

combined cycle (heat recovered to produce steam which drives generator)

8. Input capacities (million BTU/hr): Rated ________ Maximum __2,277______ Normal _______

Supplemental burner (duct burner) input capacity, if equipped (million BTU/hr):

 Rated:_________ Maximum ___841__ Normal ___________

9. Output capacities (Horsepower): Rated: _________ Maximum ___________ Normal ___________

 (Kilowatts): Rated: _800,000_ Maximum _846,300_ Normal ___________

 (lbs steam/hr)*: Rated: __75,000____ Maximum __75,000__ Normal ___________

FOR OHIO EPA USE

FACILITY ID: _________________

EU ID: _______ PTI#:__________
EPA FORM 3862 - REV2005 Page 2

*required for cogeneration or combined cycle units only

10. Type of ignition: non-spark (diesel) spark

11. Type of fuel fired (check all that apply):

single fuel No. 2 oil, low-sulfur natural gas landfill gas

dual fuel No. 2 oil, high-sulfur diesel digester gas

gasoline propane

other, explain ______________________________________________

12. Complete the following table for all fuels identified in question 11 that are used for the engine and any 

supplemental (duct) burners, if equipped:

wt.% wt.% Fuel Usage

Fuel Heat Content 

(BTU/unit)

Ash Sulfur Estimated Maximum 

Per Year

Normal Per Hour Max. Per Hour

Nat. gas 1,050 BTU/cu ft 0.005 gr/scf 25,283 MMcu ft cu ft 2.9 MMcu ft

No. 2 oil BTU/gal gal gal gal

Gasoline BTU/gal gal gal gal

Diesel BTU/gal gal gal gal

Landfill/digester gas BTU/cu ft ppm cu ft cu ft cu ft

Other (show units)

List supplemental (duct) burner fuel and information below (show units):

13. Type of combustion cycle (check all that apply):

2-stroke 4-stroke

rich-burn lean-burn

carbureted fuel injected

other, explain ________________________________________________

14. Emissions control techniques (check all that apply):

prestratified charge nonselective catalytic reduction (NSCR)

catalytic oxidation (CO) selective catalytic reduction (SCR)

air/fuel ratio injection timing retard (ITR)

2-stage rich/lean combustion 2-stage lean/lean combustion

water/steam injection preignition chamber combustion (PCC)

other, explain________________________________________________

For each emissions control technique checked above, explain what pollutants are controlled by each 

technique: 
EPA FORM 3862 - REV2005 Page 3

Catalytic oxidation will control VOCs and CO. Selective Catalytic Reduction (SCR) will control NOx
EPA FORM 3862 - REV2005 Page 1

EMISSIONS ACTIVITY CATEGORY FORM

STATIONARY INTERNAL COMBUSTION ENGINE

This form is to be completed for each stationary reciprocating or gas turbine engine. State/Federal 

regulations which may apply to stationary internal combustion engines are listed in the instructions. Note 

that there may be other regulations which apply to this emissions unit which are not included in this list.

1. Reason this form is being submitted (Check one) 

 New Permit Renewal or Modification of Air Permit Number (e.g. P001)__________

2. Maximum Operating Schedule: __8,760_____ hours per day; _365____ days per year

If the schedule is less than 24 hours/day or 365 days/year, what limits the schedule to less than 

maximum? See instructions for examples. _____________________________________________

 

3. Engine type: Gas turbine Reciprocating

4. Purpose of engine: Driving pump or compressor Driving electrical generator

5. Normal use of engine: Emergency only Non-emergency

6. Engine Manufacturer: ___TBD_________________ Model No: ___TBD_________________

7. Engine exhaust 

configuration: simple cycle (no heat recovery)

(for turbines only) regenerative cycle (heat recovery to preheat combustion air)

cogeneration cycle (heat recovered to produce steam)

combined cycle (heat recovered to produce steam which drives generator)

8. Input capacities (million BTU/hr): Rated ________ Maximum __2,277______ Normal _______

Supplemental burner (duct burner) input capacity, if equipped (million BTU/hr):

 Rated:_________ Maximum ___841__ Normal ___________

9. Output capacities (Horsepower): Rated: _________ Maximum ___________ Normal ___________

 (Kilowatts): Rated: _800,000_ Maximum _846,300_ Normal ___________

 (lbs steam/hr)*: Rated: __75,000__ Maximum __75,000____ Normal ___________

FOR OHIO EPA USE

FACILITY ID: _________________

EU ID: _______ PTI#:__________
EPA FORM 3862 - REV2005 Page 2

*required for cogeneration or combined cycle units only

10. Type of ignition: non-spark (diesel) spark

11. Type of fuel fired (check all that apply):

single fuel No. 2 oil, low-sulfur natural gas landfill gas

dual fuel No. 2 oil, high-sulfur diesel digester gas

gasoline propane

other, explain ______________________________________________

12. Complete the following table for all fuels identified in question 11 that are used for the engine and any 

supplemental (duct) burners, if equipped:

wt.% wt.% Fuel Usage

Fuel Heat Content 

(BTU/unit)

Ash Sulfur Estimated Maximum 

Per Year

Normal Per Hour Max. Per Hour

Nat. gas 1,050 BTU/cu ft 0.005 gr/scf 25,283 MMcu ft cu ft 2.9 MMcu ft

No. 2 oil BTU/gal gal gal gal

Gasoline BTU/gal gal gal gal

Diesel BTU/gal gal gal gal

Landfill/digester gas BTU/cu ft ppm cu ft cu ft cu ft

Other (show units)

List supplemental (duct) burner fuel and information below (show units):

13. Type of combustion cycle (check all that apply):

2-stroke 4-stroke

rich-burn lean-burn

carbureted fuel injected

other, explain ________________________________________________

14. Emissions control techniques (check all that apply):

prestratified charge nonselective catalytic reduction (NSCR)

catalytic oxidation (CO) selective catalytic reduction (SCR)

air/fuel ratio injection timing retard (ITR)

2-stage rich/lean combustion 2-stage lean/lean combustion

water/steam injection preignition chamber combustion (PCC)

other, explain________________________________________________

For each emissions control technique checked above, explain what pollutants are controlled by each 

technique: 
EPA FORM 3862 - REV2005 Page 3

Catalytic oxidation will control VOCs and CO. Selective Catalytic Reduction (SCR) will control NOx
EPA FORM 3862 - REV2005 Page 1

EMISSIONS ACTIVITY CATEGORY FORM

STATIONARY INTERNAL COMBUSTION ENGINE

This form is to be completed for each stationary reciprocating or gas turbine engine. State/Federal 

regulations which may apply to stationary internal combustion engines are listed in the instructions. Note 

that there may be other regulations which apply to this emissions unit which are not included in this list.

1. Reason this form is being submitted (Check one) 

 New Permit Renewal or Modification of Air Permit Number (e.g. P001)__________

2. Maximum Operating Schedule: __24____ hours per day; _varies____ days per year

If the schedule is less than 24 hours/day or 365 days/year, what limits the schedule to less than 

maximum? See instructions for examples. 

_Limited to 500 hours/year for emergency operations _______________________ 

 

3. Engine type: Gas turbine Reciprocating

4. Purpose of engine: Driving pump or compressor Driving electrical generator

5. Normal use of engine: Emergency only Non-emergency 

6. Engine Manufacturer: ___TBD_________________ Model No: ___TBD_________________

7. Engine exhaust 

configuration: simple cycle (no heat recovery)

(for turbines only) regenerative cycle (heat recovery to preheat combustion air)

cogeneration cycle (heat recovered to produce steam)

combined cycle (heat recovered to produce steam which drives generator)

8. Input capacities (million BTU/hr): Rated ___14.1_____ Maximum __14.1______ Normal 

_14.1______

Supplemental burner (duct burner) input capacity, if equipped (million BTU/hr):

 Rated:_________ Maximum _____ Normal ___________

9. Output capacities (Horsepower): Rated: _________ Maximum ___________ Normal ___________

 (Kilowatts): Rated: 1,500_ Maximum _1,500_ Normal __1,500_________

FOR OHIO EPA USE

FACILITY ID: _________________

EU ID: _______ PTI#:__________
EPA FORM 3862 - REV2005 Page 2

 (lbs steam/hr)*: Rated: ______ Maximum _______ Normal ___________

*required for cogeneration or combined cycle units only

10. Type of ignition: non-spark (diesel) spark

11. Type of fuel fired (check all that apply):

single fuel No. 2 oil, low-sulfur natural gas landfill gas

dual fuel No. 2 oil, high-sulfur diesel digester gas

gasoline propane

other, explain ______________________________________________

12. Complete the following table for all fuels identified in question 11 that are used for the engine and any 

supplemental (duct) burners, if equipped:

wt.% wt.% Fuel Usage

Fuel Heat Content 

(BTU/unit)

Ash Sulfur Estimated Maximum 

Per Year

Normal Per Hour Max. Per Hour

Nat. gas BTU/cu ft gr/scf MMcu ft cu ft MMcu ft

No. 2 oil BTU/gal gal gal gal

Gasoline BTU/gal gal gal gal

Diesel 137,000 BTU/gal 0.0015 50,500gal 101gal 101gal

Landfill/digester gas BTU/cu ft ppm cu ft cu ft cu ft

Other (show units)

List supplemental (duct) burner fuel and information below (show units):

13. Type of combustion cycle (check all that apply):

2-stroke 4-stroke

rich-burn lean-burn

carbureted fuel injected

other, explain ________________________________________________

14. Emissions control techniques (check all that apply):

prestratified charge nonselective catalytic reduction (NSCR)

catalytic oxidation (CO) selective catalytic reduction (SCR)

air/fuel ratio injection timing retard (ITR)

2-stage rich/lean combustion 2-stage lean/lean combustion

water/steam injection preignition chamber combustion (PCC)

other, explain__Use of low sulfur fuel_______________________________________
EPA FORM 3862 - REV2005 Page 3

For each emissions control technique checked above, explain what pollutants are controlled by each 

technique: 

The use of ultra low sulfur fuel will minimize SO2 emissions
EPA FORM 3862 - REV2005 Page 1

EMISSIONS ACTIVITY CATEGORY FORM

STATIONARY INTERNAL COMBUSTION ENGINE

This form is to be completed for each stationary reciprocating or gas turbine engine. State/Federal 

regulations which may apply to stationary internal combustion engines are listed in the instructions. Note 

that there may be other regulations which apply to this emissions unit which are not included in this list.

1. Reason this form is being submitted (Check one) 

 New Permit Renewal or Modification of Air Permit Number (e.g. P001)__________

2. Maximum Operating Schedule: __24____ hours per day; _varies____ days per year

If the schedule is less than 24 hours/day or 365 days/year, what limits the schedule to less than 

maximum? See instructions for examples. 

_Limited to 500 hours/year for emergency operations _______________________ 

 

3. Engine type: Gas turbine Reciprocating

4. Purpose of engine: Driving pump or compressor Driving electrical generator

5. Normal use of engine: Emergency only Non-emergency 

6. Engine Manufacturer: ___TBD_________________ Model No: ___TBD_________________

7. Engine exhaust 

configuration: simple cycle (no heat recovery)

(for turbines only) regenerative cycle (heat recovery to preheat combustion air)

cogeneration cycle (heat recovered to produce steam)

combined cycle (heat recovered to produce steam which drives generator)

8. Input capacities (million BTU/hr): Rated ___1.3_____ Maximum __1.3______ Normal _1.3______

Supplemental burner (duct burner) input capacity, if equipped (million BTU/hr):

 Rated:_________ Maximum _____ Normal ___________

9. Output capacities (Horsepower): Rated: _250___ Maximum __250____ Normal _250_______

 (Kilowatts): Rated: _ Maximum __ Normal ___________

FOR OHIO EPA USE

FACILITY ID: _________________

EU ID: _______ PTI#:__________
EPA FORM 3862 - REV2005 Page 2

 (lbs steam/hr)*: Rated: ______ Maximum _______ Normal ___________

*required for cogeneration or combined cycle units only

10. Type of ignition: non-spark (diesel) spark

11. Type of fuel fired (check all that apply):

single fuel No. 2 oil, low-sulfur natural gas landfill gas

dual fuel No. 2 oil, high-sulfur diesel digester gas

gasoline propane

other, explain ______________________________________________

12. Complete the following table for all fuels identified in question 11 that are used for the engine and any 

supplemental (duct) burners, if equipped:

wt.% wt.% Fuel Usage

Fuel Heat Content 

(BTU/unit)

Ash Sulfur Estimated Maximum 

Per Year

Normal Per Hour Max. Per Hour

Nat. gas BTU/cu ft gr/scf MMcu ft cu ft MMcu ft

No. 2 oil BTU/gal gal gal gal

Gasoline BTU/gal gal gal gal

Diesel 137,000 BTU/gal 0.0015 4,650gal 9.3gal 9.3gal

Landfill/digester gas BTU/cu ft ppm cu ft cu ft cu ft

Other (show units)

List supplemental (duct) burner fuel and information below (show units):

13. Type of combustion cycle (check all that apply):

2-stroke 4-stroke

rich-burn lean-burn

carbureted fuel injected

other, explain ________________________________________________

14. Emissions control techniques (check all that apply):

prestratified charge nonselective catalytic reduction (NSCR)

catalytic oxidation (CO) selective catalytic reduction (SCR)

air/fuel ratio injection timing retard (ITR)

2-stage rich/lean combustion 2-stage lean/lean combustion

water/steam injection preignition chamber combustion (PCC)

other, explain__Use of low sulfur fuel_______________________________________

For each emissions control technique checked above, explain what pollutants are controlled by each 
EPA FORM 3862 - REV2005 Page 3

technique: 

The use of ultra low sulfur fuel will minimize SO2 emissions
Appendix B: Supporting Calculations
Summary of Annual Emissions 

Oregon Clean Energy

Max Annual Emissions - facility wide (including startup and shutdown)

number of CTs 2 NOx CO VOC SO2 PM10/PM2.5 NH3 H2SO4 Pb 

combustion turbines tpy 201.5 160.3 118.5 40.3 166.4 184.0 21.6 0 ancillary equipment tpy 8.9 17.8 2.3 0.282 2.2 0.0000 2.13E-02 5.54E-05 cooling tower tpy 0.0 0.0 0.0 0.0 4.4 0 0 0 TOTAL TPY 210.4 178.2 120.7 40.6 172.99 184.0 21.6 0.0 

Max Annual Emissions - per unit (including startup and shutdown)

lb/hr 17 23 10 14 3 13 3.4 4.6 

Potential 

Annual Hours

tons hours tpy hours tpy hours tpy hours 

0.0 steady state - no DB 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 

8760.0 steady state - with DB 100.7 8760.0 51.9 7416.7 48.2 7416.7 20.1 8760.0 3348.3 cold start 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 

833.3 hot start 0.0 0.0 16.3 833.3 6.4 833.3 0.0 0.0 

0.0 warm start 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 

510.0 shutdown 0.0 0.0 12.0 510.0 4.7 510.0 0.0 0.0 

TOTAL TPY 100.7 8760.0 80.2 8760.0 59.2 8760.0 20.1 8760.0 steady state emissions are assumed for events that are self correcting

SUMMARY OF SU/SD INFORMATION

Self Correcting?

NOx CO VOC SO2 PM10/PM2.5

cold start emissions yes yes yes yes yeshot start emissions yes no no yes yeswarm start emissions yes yes yes yes yesshutdown emissions yes no no yes yesred value indicates not self-correcting

steady state emissions[ [no DB] / [DB] ]

NOx CO VOC SO2

Summary of Annual Emissions OCE_summary of 
Summary of Annual Emissions 

Oregon Clean Energy

Overall Assumptions

number of CTs 2duct burning hours 8760 hrs/yrsteady state hours per unit 8760

Steady State Emissions Data

Emissions data from Siemens Dated 8-10-12Emissions at ISO conditions (100% load 59 F) with and without DBEmissions Case 7 (no DB) and Case 5 (w/DB)NOx emissions assume SCRCO and VOC assume oxidation catalystSO2 emissions assume no conversion to SO3 and 0.5 grains/100 SCFH2SO4 emissions assume 35% conversion to SO3 and no conversion to ammonium sulfate

Each Turbine

NOx CO VOC SO2 PM10/PM2.5 NH3 

Emissions - (Case 7) - No DB lb/hr 17 10 3 3.40 11.0 16 

Emissions - (Case 5) - w/DB lb/hr 23 14 13 4.60 19.0 21 Emissions from DB lb/hr 6 4 10 1.2 8 5 

Facility operating hours hr/yr 8760 8760 8760 8760 8760 8760 operating hours no DB hrs/yr 0 0 0 0 0 0 operating hours with DB hrs/yr 8760 8760 8760 8760 8760 8760 steady state emissions per turbine tpy 100.74 61.32 56.94 20.148 83.22 91.98 

Both Turbinesnumber of turbines 2 2 2 2 2 2 total plant emissions emissions - steady state tpy 201.48 122.64 113.88 40.30 166.44 183.96 Plant gross output (case 7) MW 688.137 688.137 688.137 688.137 688.137 688.137 Plant net output (case 7) MW 677.3 677.3 677.3 677.3 677.3 677.3 lbs CO2 per MW-hr gross (case 7) lb/MW hr lbs CO2 per MW-hr gross (case 7) + 12.8% marginlb/MW hr 

ISO Conditions OCE_summary of poten
Summary of Annual Emissions 

Oregon Clean Energy

Overall Assumptions

SU/SD information from Siemens Technical Package Dated 8-10-12cold starts/unit 50 number/yr 2.97 hours/event 64 minimum hours downtime with event 178 minutes per event

hot starts/unit 250 number/yr 1.33 hours/event 2 minimum hours downtime with event 80 minutes per event

warm starts/unit 0 number/yr 1.47 hours/event 16 minimum hours downtime with event 88 minutes per eventshutdowns/unit 300 number/yr 0.70 hours/event 1 minimum hours downtime with event 42 minutes per event

Emissions

NOx CO VOC SO2 PM10/PM2.5

Emissions per cold start lbs 76 253 63 7.75 24Emissions per hot start lbs 64 130 51 3.75 12Emissions per warm start lbs 67 130 52 4.25 14Emissions per shutdown lbs 32 80 31 1.75 6.2cold start - duration of event (include downtime) hrs 66.97 66.97 66.97 66.97 66.97hot start - duration of event (include downtime) hrs 3.33 3.33 3.33 3.33 3.33warm start - duration of event (include downtime) hrs 17.47 17.47 17.47 17.47 17.47shutdown - duration of event (include downtime) hrs 1.70 1.70 1.70 1.70 1.70cold start - avg hourly emissions (including downtime) lb/hr 1.13 3.78 0.94 0.12 0.358hot start - avg hourly emissions (including downtime) lb/hr 19.20 39.00 15.30 1.1 3.600warm start - avg hourly emissions (including downtime) lb/hr 3.84 7.44 2.98 0.24 0.80shutdown - avg hourly emissions (including downtime) lb/hr 18.82 47.06 18.24 1.03 3.65steady state average hourly 23.00 14.00 13.00 4.60 19.00cold start - self correcting? - yes yes yes yes yeshot start - self correcting? - yes no no yes yeswarm start - self correcting? - yes yes yes yes yesshutdown - self correcting? - yes no no yes yes

Dispersion Modeling Parameters (per turbine)

Exhaust 

Flow Temp Temp

Stack 

Diameter Exit Velocity Exit Velocity

acfm F K ft ft/min m/s

Cold Start 830000 180 355.2 22 2183 11.09

Hot Start 915000 180 355.2 22 2407 12.23

Warm Start 904000 180 355.2 22 2378 12.08

Shutdown 846000 180 355.2 22 2226 11.31

Dispersion Modeling Emissions (per turbine)

NOx CO VOC SO2 PM10/PM2.5

Cold Start g/s 3.23 10.75 2.68 0.33 1.02

Hot Start g/s 6.05 12.30 4.82 0.35 1.14

Warm Start g/s 5.76 11.18 4.47 0.37 1.20

Shutdown g/s 5.77 14.41 5.58 0.32 1.12

SU-SD OCE_
Emissions From Ancillary Equipment

Oregon Clean Energy

Total Emissions form Ancillary Equipment (tpy)

NOx CO VOC TSP SO2

PM10/ PM2.5 lead (Pb) H2SO4 CO2

Auxilliary Boiler tpy 3.94 14.59 1.58 1.30 0.28 1.97 0.00 2.11E-02 46,376.47

Emergency Generator tpy 4.63 2.89 0.65 0.15 0.005 0.17 0.00004927 1.09E-04 580.69Emergency Fire Pump tpy 0.36 0.36 0.05 0.018 0.0007 0.021 0.000006125 1.36E-05 72.19TOTAL tpy 8.93 17.84 2.28 1.47 0.28 2.16 0.0000554 2.13E-02 47,029.35

Emissions (lb/hr)

NOx CO VOC TSP SO2

PM10/ PM2.5 lead (Pb)

Auxilliary Boiler 0.900 3.330 0.360 0.297 0.063 0.45 0.00E+00Emergency Generator 18.527 11.564 2.618 0.588 0.021 0.66 1.97E-04Emergency Fire Pump 1.439 1.438 0.203 0.073 0.003 0.08 2.45E-05Emissions for Modeling (g/s) - annual average

NOx CO VOC SO2

PM10/ PM2.5 lead (Pb)

Auxilliary Boiler 0.114 0.420 0.0454 0.007948 0.056750 0.00E+00Emergency Generator 0.133 0.083 0.0188 0.000152 0.004756 1.42E-06Emergency Fire Pump 0.010 0.010 0.0015 0.000019 0.000591 1.76E-07Emissions for Modeling (g/s) - hourly average

NOx CO VOC SO2

PM10/ PM2.5 lead (Pb)

Auxilliary Boiler 0.11 0.42 0.05 0.00795 0.06 0.00E+00

Emergency Generator Emergency Generator 2 34 . 1 46 . 0 33 . 0 00266 0.00266 0 08 . 2 49E 05 2.49E-05Emergency Fire Pump 0.18 0.18 0.03 0.00033 0.01 3.09E-06

Auxilliary Boiler

NOx CO VOC TSP SO2

PM10/ PM2.5 H2SO4 CO2

Maximum Input Capacity MMBtu/hr 90 90 90 90 90 90 90 90Emission Factor lb/MMscf 0.714 120000Emission Factor lb/MMBtu 0.010 0.037 0.004 0.0033 0.0007 0.005 0.00005 117.65Operating Hours per Years hrs/yr 8760 8760 8760 8760 8760 8760 8760 8760Potential Emissions lb/hr 0.90 3.33 0.36 0.30 0.06 0.45 0.034 10588.235Potential Emissions tpy 3.94 14.59 1.58 1.30 0.28 1.97 0.021 46376.5

emission factors for NOx, CO, VOC, PM10/PM2.5 based on emission factors from recent permit (NEC)emissions of SO2 assume a sulfur content in NG of 0.5 gr/100 dscfemissions of H2SO4 assumes a 5% conversion of SO2 --> SO3 (on a molar basis)CO2 Emission Factor from AP-42 Table 1.4-2 (provided in lb/MMscf and converted to lb/MMBtu)

ancillary equipment 
Emissions From Ancillary Equipment

Oregon Clean Energy

Emergency Generator

NOx CO VOC TSP SO2

PM10/ PM2.5 lead (Pb) H2SO4 CO2

Power rating kW 1500 1500 1500 1500 1500 1500 1500 1500 1500Power rating hp 2011.1 2011.1 2011.1 2011.1 2011.1 2011.1 2011.1 2011.1 2011.1emission factor g/kW hr 5.61 3.5 0.79 0.18 0.2emission factor lb/MMBtu 1.40E-05 3.10E-05 165.00emission factor g/bhp hr 0.0048 4.45E-05 9.85E-05 5.24E+02emissions lb/hr 18.527 11.564 2.618 0.588 0.021 0.661 0.0002 4.36E-04 2322.763operating hours per year hrs/yr 500 500 500 500 500 500 500 500.00 500.00hourly emissions (30 min/hr) lb/hr 9.264 5.782 1.309 0.294 0.011 0.330 0.0001 0.000 1161.381Potential Emissions tpy 4.63 2.89 0.65 0.15 0.0053 0.17 4.93E-05 0.0001091 580.7

emission factors for NOx, CO, VOC and PM10/PM2.5 based on Tier 2 emission standards provided in 40 CFR 89 Subpart B - Table 1. TSP emission factor = 89% of PM-10 emission factor, based on AP-42, Table 3.4-2 distribution of particulate emissions for stationary diesel engines.emission factor for SO2 based on ULSD fuel oil (sulfur content of 15 ppmw or 0.0015 lb/MMBtu) and fuel input ratio of 7000 Btu/hp hr (AP-42 Section 3.3)emission factor for Pb based on AP-42 Section 3.1 (1.4e-5 lb/MMBtu) and fuel input of 7000 Btu/hp hr (AP-42 Section 3.3)emission factor for H2SO4 ( 0.000031 lb/MMBTu) from Page 276 of Toxic air pollutant emission factors - a compilation for selected compounds and sources (EPA, 1990) and fuel input ratio of 7000 Btu/hpemission factor for CO2 (165 lb/MMBtu) from AP-42 Table 3.4-1emission factor for CH4 (0.0081 lb/MMBtu) from AP-42 Table 3.4-1emission factor for N2O (0.6 g/MMBtu) from Climate Registry General Reporting Protocol (GRP) (Emission Factors by Fuel Type and Sector)

Emergency Fire Pump

NOx CO VOC TSP SO2

PM10/ PM2.5 lead (Pb) H2SO4 CO2

Power rating hp 250.0 250.0 250.0 250.0 250.0 250.0 250.0 250.0 250.0Power rating kW 186.5 186.5 186.5 186.5 186.5 186.5 186.5 186.5 186.5emission factor g/kW hr 3.50 3.5 0.50 0.18 0.2

lb/MMBtu 1 40E-05 3 10E-05 165 00

The Tier 2 emission factor for NOx and VOC (non methane hydrocarbons (NMHC)) provided in Subpart B - Table 1 is provided as a combined factor (NOx+NMHC). The breakdown of NOx and NMHC in this total factor was estimated using the Tier 1 factors provided in 40 CFR 89 Subpart B Table 1. For example, the NOx emission factor was determined via the following equation: 6.4 * (9.2/(9.2+1.3))

lb/MMBtu 1.40E 05 3.10E 05 165.00

emission factor g/bhp hr 0.0048 4.45E-05 9.85E-05 5.24E+02emissions lb/hr 1.439 1.438 0.203 0.073 0.003 0.082 2.45E-05 5.43E-05 2.89E+02operating hours per year hrs/yr 500 500 500 500 500 500 500 500 500hourly emissions (30 min/hr) lb/hr 0.720 0.719 0.102 0.037 0.001 0.041 0.00001 0.000 144.375Potential Emissions tpy 0.36 0.36 0.05 0.018 0.0007 0.021 6.13E-06 1.36E-05 72.1875

emission factors for NOx, CO, VOC and PM10/PM2.5 based on post -2009 emission standards provided in 40 CFR 60 Subpart IIII - Table 4 TSP emission factor = 89% of PM-10 emission factor, based on AP-42, Table 3.4-2 distribution of particulate emissions for stationary diesel engines.emission factor for SO2 based on ULSD fuel oil (sulfur content of 15 ppmw or 0.0015 lb/MMBtu) and fuel input ratio of 7000 Btu/hp hr (AP-42 Section 3.3)emission factor for Pb based on AP-42 Section 3.1 (1.4e-5 lb/MMBtu) and fuel input of 7000 Btu/hp hr (AP-42 Section 3.3)emission factor for H2SO4 ( 0.000031 lb/MMBTu) from Toxic air pollutant emission factors - a compilation for selected compounds and sources (EPA, 1990) and fuel input ratio of 7000 Btu/hpemission factor for CO2 (165 lb/MMBtu) from AP-42 Table 3.4-1emission factor for CH4 (0.0081 lb/MMBtu) from AP-42 Table 3.4-1emission factor for N2O (0.6 g/MMBtu) from Climate Registry General Reporting Protocol (GRP) (Emission Factors by Fuel Type and Sector)The post-2009 emission factor for NOx and VOC (non methane hydrocarbons (NMHC)) provided in Subpart IIII - Table 4 is provided as a combine factor (NOx+NMHC). The breakdown of NOx and NMHC in this total factor was estimated using the Tier 1 factors provided in 40 CFR 89 Subpart B Table 1. For example, the NOx emission factor was determined via the following equation: 0.4 * (9.2/(9.2+1.3))

ancillary equipment 
Estimated Emissions from Cooling Tower

Oregon Clean Energy

Emissions

PM10 PM2.5

recirculating water flow gpm 133700 133700

drift eliminator efficiency % 0.0005% 0.0005%

TDS in recirculating water mg/l 3000 3000

particle size distribution % 100% 100%

estimated emissions lb/hr 1.003 1.003

estimated emissions tpy 4.394 4.394

number of cells - 12 12

estimated emissions per cell lb/hr 0.08 0.084

estimated emissions per cell g/s 0.0105 0.0105

Dispersion Modeling Parameters (per cell)

diameter m 10

diameter ft 32.8

exhaust temperature K ambient + 10 K

exit velocity m/s 8.5

cooling tower
NAPD ‐ Oregon italics indicate calculations added by ARCADIS Estimated Emissions Data Sheet

Estimated SGT6‐5000F(5)ee Exhaust Stack Emissions 1.108632918 10‐Aug‐12

Combined Cycle / Ultra‐Low NOX Combustor

SITE CONDITIONS: CASE 1 CASE 2 CASE 3 CASE 4 CASE 5 ‐ ISO

with DB

CASE 6 CASE 7 ‐ ISO

no DB

CASE 8 CASE 9 CASE 10 

FUEL TYPE Natural Gas Natural Gas Natural Gas Natural Gas Natural Gas Natural Gas Natural Gas Natural Gas Natural Gas Natural Gas 

LOAD LEVEL 100% 100% 100% 100% 100% 100% 100% 100% 100% 100% 

NET FUEL HEATING VALUE, Btu/lbm (LHV) 20,445 20,445 20,445 20,445 20,445 20,445 20,445 20,445 20,445 20,445

GROSS FUEL HEATING VALUE, Btu/lbm (HHV) 22,666 22,666 22,666 22,666 22,666 22,666 22,666 22,666 22,666 22,666

EVAPORATIVE COOLER STATUS ON OFF ON OFF ON OFF ON OFF OFF OFF

DUCT BURNER STATUS ON ON OFF OFF ON ON OFF OFF ON OFF AMBIENT DRY BULB TEMPERATURE, °F 90 90 90 90 59 59 59 59 0 0

AMBIENT RELATIVE HUMIDITY, % 45 45 45 45 71 71 71 71 100 100

BAROMETRIC PRESSURE, psia 14.387 14.387 14.387 14.387 14.387 14.387 14.387 14.387 14.387 14.387

GT FUEL FLOW, lb m/hr 98,076 93,157 98,179 93,191 99,882 100,296 99,963 100,445 98,347 98,385

GT FUEL FLOW, MMBtu/hr HHV 2,223 2,111 2,225 2,112 2,264 2,273 2,266 2,277 2,229 2,230DUCT BURNER FUEL FLOW, lb m/hr 34,307 35,807 0 0 33,821 33,303 0 0 37,115 0DUCT BURNER FUEL FLOW, MMBtu/hr HHV 778 812 0 0 767 755 0 0 841 0TOTAL FUEL FLOW, MMBtu/hr HHV 3,001 2,923 2,225 2,112 3,031 3,028 2,266 2,277 3,070 2,230HRSG STACK EXHAUST GAS

EXHAUST FLOW, lb m/hr 4,477,436 4,304,309 4,443,128 4,268,502 4,506,761 4,559,203 4,472,940 4,525,900 4,317,666 4,280,552

OXYGEN, Vol. % 9.47 9.42 12.19 12.38 9.66 9.83 12.33 12.42 9.25 12.31

CARBON DIOXIDE, Vol. % 5.07 5.14 3.81 3.77 5.11 5.04 3.87 3.84 5.4 3.99

WATER, Vol. % 12.42 12.07 10 9.43 11.24 10.96 8.85 8.64 10.63 7.88

NITROGEN, Vol. % 72.18 72.5 73.13 73.55 73.12 73.29 74.06 74.21 73.83 74.92

ARGON, Vol. % 0.86 0.87 0.87 0.87 0.88 0.88 0.89 0.89 0.89 0.9

MOLECULAR WEIGHT 28.06 28.11 28.44 28.45 28.19 28.22 28.71 28.4 28.29 28.52HRSG EXHAUST STACK EMISSIONS (Based on USEPA Test Methods):

NOX, ppmvd @ 15% O2 2 2 2 2 2 2 2 2 2 2 NOX, ppmvd 

NOX, lbm/hr as NO2 23 22 17 16 23 23 17 17 23 17 NOX, lbm/hr 

NH3, ppmvd @ 15% O2 5 5 5 5 5 5 5 5 5 5 NH3, ppmvd 

NH3, lbm/hr 21 20 15 15 21 21 16 16 21 16 NH3, lbm/hr 

CO, ppmvd @ 15% O2 2 2 2 2 2 2 2 2 2 2 CO, ppmvd @ 

CO, lbm/hr 14 14 10 10 14 14 10 11 14 10 CO, lbm/hr 

CO2, lbm/hr 366791 356,748 269,782 256,399 369,960 369,020 273,289 277,434 373,772 271,440 CO2, lbm/hr 

VOC, ppmvd @ 15% O2 as CH4 3.4 3.5 1 1 3.3 3.3 1 1 3.5 1 VOC, ppmvd 

VOC, lbm/hr as CH4 13 14 2.9 2.8 13 13 3 3 14 3 VOC, lbm/hr 

SO2, lbm/hr 4.5 4.4 3.4 3.2 4.6 4.6 3.4 3.4 4.6 3.4 SO2, lbm/hr 

PARTICULATES, lbm/hr 19 19 11 10 19 19 11 11 20 11 PARTICULATE

H2SO4, lbm/hr 2.41 2.36 1.82 1.72 2.47 2.47 1.82 1.82 2.47 1.82 H2SO4, lbm/NOx (lbm/MMBtu HHV) 0.00767 0.00753 0.00764 0.00757 0.00759 0.00760 0.00750 0.00747 0.00749 0.00762 NOx (lbm/MM

NH3 (lbm/MMBtu HHV) 0.00700 0.00684 0.00674 0.00710 0.00693 0.00693 0.00706 0.00703 0.00684 0.00717 NH3 (lbm/MM

CO (lbm/MMBtu HHV) 0.00467 0.00479 0.00449 0.00473 0.00462 0.00462 0.00441 0.00483 0.00456 0.00448 CO (lbm/MM

VOC (lbm/MMBtu HHV) 0.00433 0.00479 0.00130 0.00133 0.00429 0.00429 0.00132 0.00132 0.00456 0.00135 VOC (lbm/MM

SO2 (lbm/MMBtu HHV) 0.00150 0.00151 0.00153 0.00151 0.00152 0.00152 0.00150 0.00149 0.00150 0.00152 SO2 (lbm/MM

PM10/PM2.5 (lbm/MMBtu HHV) 0.00633 0.00650 0.00494 0.00473 0.00627 0.00627 0.00485 0.00483 0.00651 0.00493 PM10/PM2.5 

H2SO4 (lbm/MMBtu HHV) 0.00080 0.00081 0.00082 0.00081 0.00081 0.00081 0.00080 0.00080 0.00080 0.00082 H2SO4 (lbm/

NOTES:‐  All data is estimated and not guaranteed. Performance is based on new and clean condition.

‐  Gas fuel composition is 96.771% CH 4, 1.129% C2H6, 0.093% C3H8, 0.014% iC4H10, 0.014% nC4H10, 0.004% iC5H12, 0.004% nC5H12, 0.009% C6H14, 0.242% N2, 1.68% CO2 , 0.005 H2, and 0.5 grains S/100 SCF.

‐  Gas fuel must be in compliance with the Siemens Gas Fuel Specification.

‐  NOX emissions assume the use of an SCR system with ammonia injection.

‐  CO and VOC emissions assume the use of an oxidation catalyst.

‐  VOC consist of total hydrocarbons excluding methane and ethane and are expressed in terms of methane (CH 4).

‐  Particulates are per US EPA Method 5 and 202 (front and back half).

‐  Emissions exclude ambient air contributions and assume steady‐state conditions.

permit application data upon request.

Siemens Energy, Inc. Proprietary Information

‐  Please be advised that the information contained in this transmittal has been prepared and is being transmitted per customer request specifically for information purposes only. Such information is not intended to be

used for evaluation of plant design. Data included in any permit application or Environmental Impact Statement are strictly the customer's responsibility. Siemens is available to review

Siemens Turbine Data OCE_summ
Oregon Clean Energy

Dispersion Modeling Parameters (per turbine) developed by ARCADIS based on Siemens Data (as provided below)

SITE CONDITIONS: CASE 1 CASE 2 CASE 3 CASE 4 CASE 5 CASE 6 CASE 7 CASE 8 CA

LOAD LEVEL 100% 100% 100% 100% 100% 100% 100% 100% 10

AMBIENT DRY BULB TEMPERATURE, °F 90 90 90 90 59 59 59 59 0 

AMBIENT RELATIVE HUMIDITY, % 45 45 45 45 71 71 71 71 10

exhaust flow rate (scfm) 1,043,033 1,000,919 1,021,211 980,730 1,045,023 1,056,059 1,018,395 1,041,701 

stack gas temperature (K) 350 350 350 350 350 350 350 350 35

stack gas temperature (F) 170.6 170.6 170.6 170.6 170.6 170.6 170.6 170.6 17

exhaust flow rate (acfm) 1,224,835 1,175,381 1,199,210 1,151,673 1,227,172 1,240,132 1,195,903 1,223,271 

stack diameter (ft) 22 22 22 22 22 22 22 22 22 stack exit velocity (ft/min) 3222 3092 3155 3030 3228 3262 3146 3218 30stack exit velocity (m/s) 16.37 15.71 16.03 15.39 16.40 16.57 15.98 16.35 15NOx emissions (g/s) 2.90 2.77 2.14 2.02 2.90 2.90 2.14 2.14 2.9CO emissions (g/s) 1.77 1.77 1.26 1.26 1.77 1.77 1.26 1.39 1.7

SO2 emissions (g/s) 0.57 0.55 0.43 0.40 0.58 0.58 0.43 0.43 0.5PM10/PM2.5 emissions (g/s) 2.40 2.40 1.39 1.26 2.40 2.40 1.39 1.39 2.5

NAPD ‐ Oregon Estim

Estimated SGT6‐5000F(5)ee Exhaust Stack Emissions 

Combined Cycle / Ultra‐Low NOX Combustor

SITE CONDITIONS: CASE 1 CASE 2 CASE 3 CASE 4 CASE 5 CASE 6 CASE 7 CASE 8 CA

FUEL TYPE Natural Gas Natural Gas Natural Gas Natural Gas Natural Gas Natural Gas Natural Gas Natural Gas Na

LOAD LEVEL 100% 100% 100% 100% 100% 100% 100% 100% 10

NET FUEL HEATING VALUE, Btu/lbm (LHV) 20,445 20,445 20,445 20,445 20,445 20,445 20,445 20,445 20

GROSS FUEL HEATING VALUE, Btu/lbm (HHV) 22,666 22,666 22,666 22,666 22,666 22,666 22,666 22,666 2 22

EVAPORATIVE COOLER STATUS ON OFF ON OFF ON OFF ON OFF OF

DUCT BURNER STATUS ON ON OFF OFF ON ON OFF OFF ON 

AMBIENT DRY BULB TEMPERATURE, °F 90 90 90 90 59 59 59 59 0 

AMBIENT RELATIVE HUMIDITY, % 45 45 45 45 71 71 71 71 10

BAROMETRIC PRESSURE, psia 14.387 14.387 14.387 14.387 14.387 14.387 14.387 14.387 14

GT FUEL FLOW, lb m/hr 98,076 93,157 98,179 93,191 99,882 100,296 99,963 100,445 98

DUCT BURNER FUEL FLOW, lb m/hr 34,307 35,807 ‐‐‐ ‐‐‐ 33,821 33,303 ‐‐‐ ‐‐‐ 37

HRSG STACK EXHAUST GAS

EXHAUST FLOW, lb m/hr 4,477,436 4,304,309 4,443,128 4,268,502 4,506,761 4,559,203 4,472,940 4,525,900 4,3

OXYGEN, Vol. % 9.47 9.42 12.19 12.38 9.66 9.83 12.33 12.42 9.2

CARBON DIOXIDE, Vol. % 5.07 5.14 3.81 3.77 5.11 5.04 3.87 3.84 5.4 

WATER, Vol. % 12.42 12.07 10 9.43 11.24 10.96 8.85 8.64 10

NITROGEN, Vol. % 72.18 72.5 73.13 73.55 73.12 73.29 74.06 74.21 73

ARGON, Vol. % 0.86 0.87 0.87 0.87 0.88 0.88 0.89 0.89 0.8

MOLECULAR WEIGHT 28.06 28.11 28.44 28.45 28.19 28.22 28.71 28.4 28HRSG EXHAUST STACK EMISSIONS (Based on USEPA Test Methods):

NOX, ppmvd @ 15% O2 2 2 2 2 2 2 2 2 2 

NOX, lbm/hr as NO2 23 22 17 16 23 23 17 17 23 

NH3, ppmvd @ 15% O2 5 5 5 5 5 5 5 5 5 

NH3, lbm/hr 21 20 15 15 21 21 16 16 21 

CO, ppmvd @ 15% O2 2 2 2 2 2 2 2 2 2 

CO, lbm/hr 14 14 10 10 14 14 10 11 14 

CO2, lbm/hr 366791 356,748 269,782 256,399 369,960 369,020 273,289 277,434 37

Turbine Data for Modeling OCE_summary of 
VOC, ppmvd @ 15% O2 as CH4 3.4 3.5 1 1 3.3 3.3 1 1 3.5 

VOC, lbm/hr as CH4 13 14 2.9 2.8 13 13 3 3 14 

SO2, lbm/hr 4.5 4.4 3.4 3.2 4.6 4.6 3.4 3.4 4.6 

PARTICULATES, lbm/hr 19 19 11 10 19 19 11 11 20 

NOTES:‐  All data is estimated and not guaranteed. Performance is based on new and clean condition.

‐  Gas fuel composition is 96.771% CH 4, 1.129% C2H6, 0.093% C3H8, 0.014% iC4H10, 0.014% nC4H10, 0.004% iC5H12, 0.004% nC5H12, 0.009% C6H14, 0.242% N2, 1.68% CO2 , 0.005 H2, and 0

‐  Gas fuel must be in compliance with the Siemens Gas Fuel Specification.

‐  NOX emissions assume the use of an SCR system with ammonia injection.

‐  CO and VOC emissions assume the use of an oxidation catalyst.

‐  VOC consist of total hydrocarbons excluding methane and ethane and are expressed in terms of methane (CH 4).

‐  Particulates are per US EPA Method 5 and 202 (front and back half).

‐  Emissions exclude ambient air contributions and assume steady‐state conditions.

permit application data upon request.

Siemens Energy, Inc. 

‐  Please be advised that the information contained in this transmittal has been prepared and is being transmitted per customer request specifically for information purposes only. Such inform

Turbine Data for Modeling OCE_summary of 
Appendix C: RBLC Tables
RBLC Review for Auxiliary Boiler - CO 

RBLC ID Facility County State Permit Date Status pacity (MMBTU Basis Notes 

* NV-0049HARRAH'S OPERATING COMPANY, IN

C Clark NV 8/20/2009 Draft 35.4 Other COMMERCIAL BOILER 

* NV-0049HARRAH'S OPERATING COMPANY, IN

C Clark NV 8/20/2009 Draft 33.48 Other COMMERCIAL BOILER 

IA-0062 EMERY GENERATING STATION Cerro Gordo IA 12/20/2002 Operational 68 Other AUX BOILER * NV-0049HARRAH'S OPERATING COMPANY, IN

C Clark NV 8/20/2009 Draft 31.38 Other COMMERCIAL BOILER 

* NV-0049HARRAH'S OPERATING COMPANY, IN

C Clark NV 8/20/2009 Draft 16.8 Other COMMERCIAL BOILER 

NV-0050 MGM MIRAGE Clark NV 11/30/2009 41.64 LAER BOILER MD-0040 CPV ST CHARLES Charles MD 11/12/2008 Not constructed 93 BACT AUX BOILER NM-0042 DEMING ENERGY FACILITY Luna NM 12/29/2000 44.1 BACT AUX BOILER * VA-0308WARREN COUNTY FACILITY Warren VA 1/14/2008 Draft 97 N/A AUX BOILER 

NV-0044 HARRAH'S OPERATING COMPANY, IN

C Clark NV 1/4/2007 35.4 BACT INDUSTRIAL BOILERS 

WI-0226 WPS - WESTON PLANT Marathon WI 8/27/2004 Operational 46.2 N/A BOILER * NV-0049HARRAH'S OPERATING COMPANY, IN

C Clark NV 8/20/2009 Draft 24 Other COMMERCIAL BOILER 

* NV-0049HARRAH'S OPERATING COMPANY, IN

C Clark NV 8/20/2009 Draft 8.37 Other COMMERCIAL BOILER 

OH-0252 DUKE ENERGY HANGING ROCK ENER Lawrence OH 12/28/2004 Operational 30.6 BACT BOILERS 

OH-0252 DUKE ENERGY HANGING ROCK Lawrence OH 12/28/2004 Operational 30.6 BACT BOILERS WA-0292 SATSOP COMBUSTION TURBINE PROJGrays Harbor WA 10/23/2001 29.3 BACT AUX BOILER 

 LA-0240 FLOPAM INC. Iberville LA 6/14/2010 25.1 BACT BOILER * AL-0230THYSSENKRUPP STEEL AND STAINLE Mobile AL 8/17/2007 Draft 64.9 BACT BOILERS 

* NV-0049HARRAH'S OPERATING COMPANY, IN

C Clark NV 8/20/2009 Draft 14.34 Other COMMERCIAL BOILER 

TX-0501 TEXSTAR GAS PROCESS FACILITY Henderson TX 7/11/2006 93 BACT INDUSTRIAL BOILERS FL-0285 PROGRESS BARTOW POWER PLANT Pinellas FL 1/26/2007 Operational 99 BACT AUX BOILER FL-0286 FPL WEST COUNTY ENERGY CENTER Palm Beach FL 1/10/2007 Not constructed 99.8 BACT AUX BOILER 

WI-0227 PORT WASHINGTON GENERATING ST Washington WI 10/13/2004 Operational 97.1 BACT AUX BOILER 

* OH-032 TITAN TIRE CORPORATION OF BRYAN Williams OH 6/5/2008 Draft 50.4 BACT BOILER 

OH-0309 TOLEDO SUPPLIER PARK- PAINT SH

O Lucas OH 5/3/2007 20.4 BACT INDUSTRIAL BOILERS 

MN-0053 FAIRBAULT ENERGY PARK Rice MN 7/15/2004 Operational 40 BACT AUX BOILER OK-0129 CHOUTEAU POWER PLANT Mayes OK 1/23/2009 33.5 N/A AUX BOILER CA-1127 GENENTECH, INC. San Mateo CA 9/27/2005 97 BACT COMMERCIAL BOILER 

1 of 6
RBLC Review for Auxiliary Boiler - NOx 

RBLC ID Facility County State Permit Date Status apacity (MMBTU/ Basis Notes 

CA-0946 LACORR PACKAGING Los Angeles CA 7/12/2000 21 LAER BOILER OK-0055 MUSTANG ENERGY PROJECT Canadian OK 2/12/2002 Operational 31 Other AUX BOILER CA-1006 HI-COUNTRY Riverside CA 12/16/1999 20.9 BACT BOILER * NV-0049HARRAH'S OPERATING COMPANY, INC Clark NV 8/20/2009 Draft 24 BACT COMMERCIAL BOILER 

MD-0040 CPV ST CHARLES Charles MD 11/12/2008 Not constructed 93 LAER AUX BOILER * MD-003 MEDIMMUNE FREDERICK CAMPUS Frederick MD 1/28/2008 29.4 LAER BOILERS 

* VA-038 WARREN COUNTY FACILITY Warren VA 1/14/2008 Draft 97 N/A AUX BOILER CA-0940 NATION WIDE BOILER Alameda CA 3/15/2000 28.8 LAER BOILER, PORTABLE NV-0050 MGM MIRAGE Clark NV 11/30/2009 41.64 Other BOILER * NV-0049HARRAH'S OPERATING COMPANY, INC Clark NV 8/20/2009 Draft 8.37 BACT COMMERCIAL BOILER 

 LA-0240 FLOPAM INC. Iberville LA 6/14/2010 25.1 LAER BOILER * NV-0049HARRAH'S OPERATING COMPANY, INC Clark NV 8/20/2009 Draft 16.8 BACT COMMERCIAL BOILER NM-0042 DEMING ENERGY FACILITY Luna NM 12/29/2000 44.1 BACT AUX BOILER * NV-0049HARRAH'S OPERATING COMPANY, INC Clark NV 8/20/2009 Draft 31.38 BACT COMMERCIAL BOILER * AK-0071INTERNATIONAL STATION POWER PLA Anchorage AK 12/20/2010 12.5 BACT AUXILIARY HEATER 

* NV-0049HARRAH'S OPERATING COMPANY, INC Clark NV 8/20/2009 Draft 35.4 BACT COMMERCIAL BOILER 

OH-0309 TOLEDO SUPPLIER PARK- PAINT SHO Lucas OH 5/3/2007 20.4 LAER INDUSTRIAL BOILERS 

NV-0044 HARRAH'S OPERATING COMPANY, INC Clark NV 1/4/2007 35.4 BACT INDUSTRIAL BOILERS 

OH-0252 DUKE ENERGY HANGING ROCK ENER Lawrence OH 12/28/2004 Operational 30.6 BACT BOILERS 

NV-0037 COPPER MOUNTAIN POWER Clark NV 5/14/2004 Not constructed 60 BACT AUX BOILER * NV-0049HARRAH'S OPERATING COMPANY, INC Clark NV 8/20/2009 Draft 14.34 BACT COMMERCIAL BOILER 

WI-0226 WPS - WESTON PLANT Marathon WI 8/27/2004 Operational 46.2 N/A BOILER * NV-0049HARRAH'S OPERATING COMPANY, INC Clark NV 8/20/2009 Draft 33.48 BACT COMMERCIAL BOILER * NH-001 CONCORD STEAM CORPORATION Merrimack NH 2/27/2009 Draft 76.8 LAER AUX BOILER (<700 hours/yr

OH-0323 TITAN TIRE CORPORATION OF BRYAN Williams OH 6/5/2008 50.4 BACT BOILER 

OR-0048 CARTY PLANT Morrow OR 12/29/2010 91 BACT BOILER * OK-013 PRYOR PLANT CHEMICAL Mayes OK 2/23/2009 Draft 80 BACT BOILERS FL-0286 FPL WEST COUNTY ENERGY CENTER Palm Beach FL 1/10/2007 Not constructed 99.8 BACT AUX BOILER 

* OK-012 CHOUTEAU POWER PLANT Mayes OK 1/23/2009 Draft 33.5 BACT AUX BOILER LA-0244 LAKE CHARLES CHEMICAL COMPLEX Calcasieu LA 11/29/2010 21 BACT START HEATER - BACT DE

2 of 6
RBLC Review for Auxiliary Boiler - SO2 

RBLC ID Facility County State Permit Date Status apacity (MMBTU/ Basis Notes 

* NY-0095CAITHNES BELLPORT ENERGY CENTE Suffolk NY 5/10/2006 Draft 29.4 BACT AUX BOILER 

* NV-0049HARRAH'S OPERATING COMPANY, INC Clark NV 8/20/2009 Draft 33.48 Other COMMERCIAL BOILER 

* NV-0049HARRAH'S OPERATING COMPANY, INC Clark NV 8/20/2009 Draft 35.4 Other COMMERCIAL BOILER * NV-0049HARRAH'S OPERATING COMPANY, INC Clark NV 8/20/2009 Draft 31.83 Other COMMERCIAL BOILER * NV-0049HARRAH'S OPERATING COMPANY, INC Clark NV 8/20/2009 Draft 14.34 Other COMMERCIAL BOILER * NV-0049HARRAH'S OPERATING COMPANY, INC Clark NV 8/20/2009 Draft 24 Other COMMERCIAL BOILER * NV-0049HARRAH'S OPERATING COMPANY, INC Clark NV 8/20/2009 Draft 8.37 Other COMMERCIAL BOILER * NV-0049HARRAH'S OPERATING COMPANY, INC Clark NV 8/20/2009 Draft 16.7 Other COMMERCIAL BOILER OH-0309 TOLEDO SUPPLIER PARK- PAINT SHO Lucas OH 5/3/2007 20.4 BACT INDUSTRIAL BOILERS 

WI-0227 PORT WASHINGTON GENERATING ST Washington WI 10/13/2004 Operational 97.1 BACT AUX BOILER 

AR-0077 BLUEWATER PROJECT Mississippi AR 7/22/2004 22 BACT BOILERS IN-0108 NUCOR STEEL Montgomery IN 11/21/2003 34 BACT BOILER IA-0062 EMERY GENERATING STATION Cerro Gordo IA 12/20/2002 Operational 68 Other AUX BOILER IN-0095 ALLEGHENY ENERGY SUPPLY CO. LLC St. Joseph IN 12/7/2001 Not constructed 21 BACT AUX BOILER 

OH-0251 CENTRAL SOYA COMPANY INC. Huron OH 11/29/2001 91.2 BACT BOILER IN-0087 DUKE ENERGY, VIGO LLC Vigo IN 6/6/2001 Not constructed 46 BACT AUX BOILER IN-0086 MIRANT SUGAR CREEK, LLC Vigo IN 5/9/2001 Operational 35 BACT AUX BOILER OH-0255 AEP WATERFORD ENERGY LLC Washington OH 3/29/2001 Operational 85.2 BACT BOILER NV-0050 MGM MIRAGE Clark NV 11/30/2009 41.64 BACT BOILER * OK-012 CHOUTEAU POWER PLANT Mayes OK 1/23/2009 Draft 33.5 N/A AUX BOILER NV-0044 HARRAH'S OPERATING COMPANY, INC Clark NV 1/4/2007 35.4 BACT INDUSTRIAL BOILERS 

OH-0252 DUKE ENERGY HANGING ROCK ENER Lawrence OH 12/28/2004 Operational 30.6 BACT BOILERS 

MN-0054 MANKATO ENERGY CENTER Blue Earth MN 12/4/2003 Not constructed 70 BACT COMMERCIAL BOILER OH-0254 DUKE ENERGY WASHINGTON COUNTYWashington OH 8/14/2003 Operational 30.6 BACT BOILER 

VA-0255 VA POWER - POSSUM POINT Prince William VA 11/18/2002 Operational 99 Other AUX BOILER OK-0071 MCCLAIN ENERGY FACILITY McClain OK 10/25/2001 Operational 22 BACT AUX BOILER OH-0265 DRESDEN ENERGY LLC Muskingum OH 10/16/2001 Not constructed 49 BACT BOILER AL-0168 GENPOWER KELLEY LLC Walker AL 1/12/2001 Not constructed 83 BACT BOILER AZ-0047 WELLTON MOHAWK GENERATING STA Yuma AZ 12/1/2004 Not constructed 38 BACT AUX BOILER 

* OK-013 PRYOR PLANT CHEMICAL Mayes OK 2/23/2009 Draft 80 BACT BOILERS * VA-0308WARREN COUNTY FACILITY Warren VA 1/14/2008 Draft 97 N/A AUX BOILER 

* NV-0049HARRAH'S OPERATING COMPANY, INC Clark NV 8/20/2009 Draft 16.8 Other COMMERCIAL BOILER 

FL-0286 FPL WEST COUNTY ENERGY CENTER Palm Beach FL 1/10/2007 Not constructed 99.8 BACT AUX BOILER 

3 of 6
RBLC Review for Auxiliary Boiler - PM10 

RBLC ID Facility County State Permit Date Status apacity (MMBTU/ Basis Notes 

OH-0323 TITAN TIRE CORPORATION OF BRYAN Williams OH 6/5/2008 50.4 N/A BOILER 

* NY-0095CAITHNES BELLPORT ENERGY CENTE Suffolk NY 5/10/2006 Draft 29.4 BACT AUX BOILER 

AZ-0047 WELLTON MOHAWK GENERATING STA Yuma AZ 12/1/2004 Not constructed 38 BACT AUX BOILER 

OR-0040 KLAMATH GENERATION, LLC Klamath OR 3/12/2003 (50000 LB/H) BACT AUX BOILER MD-0040 CPV ST CHARLES Charles MD 11/12/2008 Not constructed 93 BACT AUX BOILER  LA-0240 FLOPAM INC. Iberville LA 6/14/2010 25.1 BACT BOILER * OK-013 PRYOR PLANT CHEMICAL Mayes OK 2/23/2009 Draft 80 BACT BOILERS * NV-0049HARRAH'S OPERATING COMPANY, INC Clark NV 8/20/2009 Draft 33.48 Other COMMERCIAL BOILER 

* NV-0049HARRAH'S OPERATING COMPANY, INC Clark NV 8/20/2009 Draft 14.34 Other COMMERCIAL BOILER * NV-0049HARRAH'S OPERATING COMPANY, INC Clark NV 8/20/2009 Draft 8.37 Other COMMERCIAL BOILER * NV-0049HARRAH'S OPERATING COMPANY, INC Clark NV 8/20/2009 Draft 24 Other COMMERCIAL BOILER OH-0309 TOLEDO SUPPOLIER PARK- PAINT SH Lucas OH 5/3/2007 20.4 BACT INDUSTRIAL BOILERS NV-0044 HARRAH'S OPERATING COMPANY, INC Clark NV 1/4/2007 35.4 BACT INDUSTRIAL BOILERS WI-0228 WPS - WESTON PLANT Marathon WI 10/19/2004 Operational 229.8 BACT AUX BOILER * AK-0071INTERNATIONAL STATION POWER PLA Anchorage AK 12/20/2010 12.5 BACT AUXILIARY HEATER 

* NV-0049HARRAH'S OPERATING COMPANY, INC Clark NV 8/20/2009 Draft 35.4 Other COMMERCIAL BOILER 

* NV-0049HARRAH'S OPERATING COMPANY, INC Clark NV 8/20/2009 Draft 31.38 Other COMMERCIAL BOILER * NV-0049HARRAH'S OPERATING COMPANY, INC Clark NV 8/20/2009 Draft 21 Other COMMERCIAL BOILER * NV-0049HARRAH'S OPERATING COMPANY, INC Clark NV 8/20/2009 Draft 16.8 Other COMMERCIAL BOILER NV-0050 MGM MIRAGE Clark NV 11/30/2009 41.64 Other BOILER * NV-0049HARRAH'S OPERATING COMPANY, INC Clark NV 8/20/2009 Draft 21 Other COMMERCIAL BOILER OH-0252 DUKE ENERGY HANGING ROCK ENER Lawrence OH 12/28/2004 Operational 30.6 BACT BOILERS 

LA-0244 LAKE CHARLES CHEMICAL COMPLEX Calcasieu LA 11/29/2010 21 BACT START HEATER - BACT DE

FL-0286 FPL WEST COUNTY ENERGY CENTER Palm Beach FL 1/10/2007 Not constructed 99.8 BACT AUX BOILER 

OR-0048 CARTY PLANT Morrow OR 12/29/2010 91 BACT BOILER 

4 of 6
RBLC Review for Auxiliary Boiler - VOC 

RBLC ID Facility County State Permit Date Status apacity (MMBTU/ Basis Notes 

MD-0040 CPV ST CHARLES Charles MD 11/12/2008 Not constructed 93 LAER AUX BOILER NV-0050 MGM MIRAGE Clark NV 11/30/2009 41.64 Other BOILER IN-0108 NUCOR STEEL Montgomery IN 11/21/2003 34 BACT INDUSTRIAL BOILERS  LA-0240 FLOPAM INC. Iberville LA 6/14/2010 25.1 BACT BOILER AZ-0047 WELLINGTON MOHAWK GENERATIN

G Yuma AZ 12/1/2004 Not constructed 38 BACT AUX BOILER 

GA-0098 RINCON POWER PLANT Effingham GA 3/24/2003 Not constructed 83 Other AUX BOILER VA-0255 VA POWER - POSSUM POINT Prince William VA 11/18/2002 Operational 99 Other AUX BOILER AL-0179 TENASKA TALLADEGA GENERATING S Talladega AL 10/3/2001 Not constructed 30 BACT AUX BOILER 

OH-0255 AEP WATERFORD ENERGY LLC Washington OH 3/29/2001 Operational 85.2 BACT AUX BOILER NV-0044 HARRAH'S OPERATING COMPANY, IN

C Clark NV 1/4/2007 35.4 BACT INDUSTRIAL BOILERS 

OK-0046 THUNDERBIRD POWER PLT Cleveland OK 5/17/2001 Not constructed 20 BACT AUX BOILER * NV-0049HARRAH'S OPERATING COMPANY, IN

C Clark NV 8/20/2009 Draft 35.4 Other COMMERCIAL BOILER 

* NV-0049HARRAH'S OPERATING COMPANY, IN

C Clark NV 8/20/2009 Draft 33.48 Other COMMERCIAL BOILER 

* NV-0049HARRAH'S OPERATING COMPANY, IN

C Clark NV 8/20/2009 Draft 31.38 Other COMMERCIAL BOILER 

* NV-0049HARRAH'S OPERATING COMPANY, IN

C Clark NV 8/20/2009 Draft 16.8 Other COMMERCIAL BOILER 

* NV-0049HARRAH'S OPERATING COMPANY, IN

C Clark NV 8/20/2009 Draft 8.37 Other COMMERCIAL BOILER 

* NV-0049HARRAH'S OPERATING COMPANY, IN

C Clark NV 8/20/2009 Draft 24 Other COMMERCIAL BOILER 

* NV-0049HARRAH'S OPERATING COMPANY, IN

C Clark NV 8/20/2009 Draft 14.34 Other COMMERCIAL BOILER 

OH-0309 TOLEDO SUPPLIER PARK- PAINT SH

O Lucas OH 5/3/2007 20.4 LAER INDUSTRIAL BOILERS 

IA-0062 EMERY GENERATING STATION Cerro Gordo IA 12/20/2002 Operational 68 Other AUX BOILER NC-0094 GENPOWER EARLEYS, LLC Hertford NC 1/9/2002 Not constructed 83 BACT AUX BOILER IN-0095 ALLEGHENY ENERGY SUPPLY CO. LL

C St. Joseph IN 12/7/2001 Not constructed 21 BACT AUX BOILER 

IN-0087 DUKE ENERGY, VIGO LLC Vigo IN 6/6/2001 Not constructed 46 BACT AUX BOILER IN-0086 MIRANT SUGAR CREEK, LLC Vigo IN 5/9/2001 Operational 35 BACT AUX BOILER WI-0227 PORT WASHINGTON GENERATING ST Washington WI 10/13/2004 Operational 97.1 BACT AUX BOILER 

MS-0085 Dart Container Corporation Clarke MS 1/31/2007 33.5 BACT NATURAL GAS FIRED BOIL

VA-0308 WARREN COUNTY FACILITY Warren VA 1/14/2008 Not constructed 97 N/A AUX BOILER OH-0252 DUKE ENERGY HANGING ROCK Lawrence OH 12/28/2004 Operational 30.6 BACT BOILERS 

5 of 6
RBLC Review for Auxiliary Boiler - H2SO4 

Facility County State Permit Date Status apacity (MMBTU/ Basis Notes Li

CPV ST CHARLES Charles MD 11/12/2008 Not constructed 93 BACT AUX BOILER WPS - WESTON PLANT Marathon WI 10/19/2004 Operational 229.8 BACT natural gas heaters 0MANKATO ENERGY CENTER Blue Earth MN 12/4/2003 Not constructed 70 BACT BOILER 0.8 

6 of 6
RBLC Review for Large Combined Cycle Turbines - CO 

RBLC ID Facility County State Permit Date Basis Control Limit (PPM) N

CT-0151 KLEEN ENERGY SYSTEMS, LLC Middlesex CT 2/25/2008 BACT-PSD CO Catalyst 0.9 1.7 PPMVD @ 1*VA-0308 WARREN COUNTY FACILITY Warren VA 1/14/2008 BACT-PSD Oxidation catalyst 1.3 Without power a

CPV Valley Energy Center Wawayanda NY NA 2.0Caithness Long Island Energy New York NY NA 2.0Brockton Clean Energy Brockton MA NA 2.0

TX-0590 KING POWER STATION Harris TX 8/5/2010 BACT-PSD Oxidation catalyst 2.0ID-0018 LANGLEY GULCH POWER PLANT Payette ID 6/25/2010 BACT-PSD Oxidation catalyst 2.0GA-0138 LIVE OAKS POWER PLANT Glynn GA 4/8/2010 BACT-PSD Oxidation catalyst 2.0*TX-0546 PATTILLO BRANCH POWER PLANT Fannin TX 6/17/2009 BACT-PSD Oxidation catalyst 2.0NJ-0074 WEST DEPTFORD ENERGY Gloucester NJ 5/6/2009 BACT-PSD Oxidation catalyst 2.0MI-0366 BERRIEN ENERGY, LLC Berrien MI 4/13/2005 BACT-PSD Oxidation catalyst 2.0 4.0 PPMVD PER OR-0039 COB ENERGY FACILITY, LLC Klamath OR 12/30/2003 BACT-PSD Oxidation catalyst 2.0CA-1096 VERNON CITY LIGHT & POWER Los Angeles CA 5/27/2003 BACT-PSD SCR, Oxidation catalyst 2.0CA-1097 MAGNOLIA POWER PROJECT, SCP Los Angeles CA 5/27/2003 BACT-PSD SCR, Oxidation catalyst 2.0

WA-0315 SUMAS ENERGY 2 GENERATION F

A Whatcom WA 4/17/2003 BACT-PSD Oxidation catalyst 2.0

GA-0105 MCINTOSH COMBINED CYCLE FA

C Effingham GA 4/17/2003 BACT-PSD Oxidation catalyst 2.0

WA-0291 WALLULA POWER PLANT Walla Walla WA 1/3/2003 Other Oxidation catalyst 2.0NJ-0043 LIBERTY GENERATING STATION Union NJ 3/28/2002 Other CO Catalyst 2.0GA-0102 WANSLEY COMBINED CYCLE ENER Heard GA 1/15/2002 BACT-PSD Good combustion practices 2.0

WA-0288 LONGVIEW ENERGY DEVELOPMEN Cowlitz WA 9/4/2001 Other Oxidation catalyst 2.0

NJ-0058 PSEG FOSSIL LLC LINDEN GENER

A Union NJ 8/24/2001 BACT-PSD Oxidation catalyst 2.0

NJ-0059 COGEN TECHNOLOGIES LINDEN V Union NJ 5/9/2001 Other Oxidation catalyst 2.0WA-0302 GOLDENDALE ENERGY PROJECT Klickitat WA 2/23/2001 BACT-PSD Oxidation catalyst 2.0NV-0034 LAS VEGAS COGENERATION FACIL Clark NV 11/13/2000 BACT-PSD Oxidation catalyst 2.0

MA-0027 CABOT POWER CORPORATION Suffolk MA 5/7/2000 BACT-PSD Oxidation catalyst 2.0AZ-0043 DUKE ENERGY ARLINGTON VALLE Maricopa AZ 11/12/2003 BACT-PSD Oxidation catalyst 3.0TX-0600 THOMAS C. FERGUSON POWER PL Llano TX 9/1/2011 BACT-PSD Oxidation catalyst 4.0

NJ-0066 AES RED OAK LLC Middlesex NJ 2/16/2006 BACT-PSD Oxidation catalyst 4.0ID-0010 MIDDLETON FACILITY Canyon ID 10/19/2001 BACT-PSD None 5.0 2.0000 PPM @ FL-0303 FPL WEST COUNTY ENERGY CENT Palm Beach FL 7/30/2008 BACT-PSD Good combustion practices 6.0 24-hour standar

TX-0552 WOLF HOLLOW POWER PLANT N

O Hood TX 3/3/2010 BACT-PSD Good combustion practices 11.0 GE7FA

TX-0551 PANDA SHERMAN POWER STATION Grayson TX 2/3/2010 BACT-PSD Good combustion practices 15.0 Combined-cycle 

*TX-0547 LAMAR POWER PARTNERS II LLC Lamar TX 6/22/2009 BACT-PSD Good combustion practices 15.0*TX-0548 MADISON BELL ENERGY CENTER Madison TX 8/18/2009 BACT-PSD Good combustion practices 17.5LA-0136 PLAQUEMINE COGENERATION FA

C Iberville LA 7/23/2008 BACT-PSD Good combustion practices 25.0

1 of 7
RBLC Review for Large Combined Cycle Turbines - NOx 

RBLC ID Facility County State Permit Date Basis Control Limit (PPM Notes

CPV Valley Energy Center Wawayanda NY NA LAER 2.0Caithness Long Island Energy New York NY NA LAER 2.0Brockton Clean Energy Brockton MA NA 2.0

ID-0018 LANGLEY GULCH POWER PLANT Payette ID 06/25/2010 BACT-PSD DLN, SCR 2.0TX-0600 THOMAS C. FERGUSON POWER PL Llano TX 9/1/2011 BACT-PSD DLN, SCR 2.0

*OR-0048 CARTY PLANT Morrow OR 12/29/2010 BACT-PSD SCR 2.0TX-0590 KING POWER STATION Harris TX 8/5/2010 LAER DLN, SCR 2.0TX-0552 WOLF HOLLOW POWER PLANT NO Hood TX 3/3/2010 BACT-PSD DLN, SCR 2.0

TX-0551 PANDA SHERMAN POWER STATION Grayson TX 2/3/2010 BACT-PSD DLN, SCR 2.0 Combined-cycle mod

*TX-0548 MADISON BELL ENERGY CENTER Madison TX 8/18/2009 BACT-PSD SCR 2.0*TX-0547 LAMAR POWER PARTNERS II LLC Lamar TX 6/22/2009 BACT-PSD SCR 2.0*TX-0546 PATTILLO BRANCH POWER PLANT Fannin TX 6/17/2009 BACT-PSD SCR 2.0NJ-0074 WEST DEPTFORD ENERGY Gloucester NJ 5/6/2009 LAER SCR, Water injection 2.0FL-0303 FPL WEST COUNTY ENERGY CENT Palm Beach FL 7/30/2008 BACT-PSD SCR 2.0 24-Hour standards

CT-0151 KLEEN ENERGY SYSTEMS, LLC Middlesex CT 2/25/2008 LAER DLN, SCR 2.0*VA-0308 WARREN COUNTY FACILITY Warren VA 1/14/2008 BACT-PSD Premix, SCR 2.0NY-0098 ATHENS GENERATING PLANT Greene NY 1/19/2007 LAER DLN, SCR, ammonia in 2.0

NY-0100 EMPIRE POWER PLANT Rensselaer NY 6/23/2005 LAER DLN, SCR 2.0 3.0000 PPMVD AT 1

AZ-0043 DUKE ENERGY ARLINGTON VALLE Maricopa AZ 11/12/2003 BACT-PSD SCR 2.0CA-1096 VERNON CITY LIGHT & POWER Los Angeles CA 5/27/2003 BACT-PSD SCR, catalyst 2.0CA-1097 MAGNOLIA POWER PROJECT, SCP Los Angeles CA 5/27/2003 BACT-PSD SCR, catalyst 2.0

WA-0315 SUMAS ENERGY 2 GENERATION FA Whatcom WA 4/17/2003 BACT-PSD DLN, SCR 2.0

NJ-0058 PSEG FOSSIL LLC LINDEN GENERA Union NJ 8/24/2001 BACT-PSD DLN, SCR 2.0

WA-0302 GOLDENDALE ENERGY PROJECT Klickitat WA 2/23/2001 BACT-PSD DLN, SCR 2.0NV-0034 LAS VEGAS COGENERATION FACIL Clark NV 11/13/2000 BACT-PSD SCR, ammonia injectio 2.0

MA-0027 CABOT POWER CORPORATION Suffolk MA 5/7/2000 LAER DLN, SCR 2.0GA-0138 LIVE OAKS POWER PLANT Glynn GA 4/8/2010 BACT-PSD DLN, SCR 2.5MI-0366 BERRIEN ENERGY, LLC Berrien MI 4/13/2005 BACT-PSD DLN, SCR 2.5OR-0039 COB ENERGY FACILITY, LLC Klamath OR 12/30/2003 BACT-PSD DLN, SCR 2.5GA-0105 MCINTOSH COMBINED CYCLE FAC Effingham GA 4/17/2003 BACT-PSD DLN, SCR 2.5

WA-0291 WALLULA POWER PLANT Walla Walla WA 1/3/2003 Other SCR 2.5NJ-0043 LIBERTY GENERATING STATION Union NJ 3/28/2002 Other SCR 2.5WA-0288 LONGVIEW ENERGY DEVELOPMEN Cowlitz WA 9/4/2001 Other SCR 2.5

NJ-0059 COGEN TECHNOLOGIES LINDEN V Union NJ 5/9/2001 BACT-PSD DLN, SCR, ammonia in 2.5

NJ-0066 AES RED OAK LLC Middlesex NJ 2/16/2006 LAER SCR 3.0GA-0102 WANSLEY COMBINED CYCLE ENER Heard GA 1/15/2002 BACT-PSD DLN, SCR 3.0

ID-0010 MIDDLETON FACILITY Canyon ID 10/19/2001 BACT-PSD SCR, catalyst 3.0 3.5000 PPM @ 15% *AK-0071 INTERNATIONAL STATION POWER Anchorage AK 12/20/2010 BACT-PSD DLN, SCR 5.0LA-0136 PLAQUEMINE COGENERATION FAC Iberville LA 7/23/2008 BACT-PSD SCR 5.0

2 of 7
RBLC Review for Large Combined Cycle Turbines - SO2 

RBLC ID Facility County State Permit Date Basis Control Limit (lb/MMBtu) 

*VA-0308 WARREN COUNTY FACILITY Warren VA 1/14/2008 N/A Good combustion practice 0.0003

WA-0302 GOLDENDALE ENERGY PROJECT Klickitat WA 2/23/2001 BACT-PSD Good combustion practice 0.0005OK-0129 CHOUTEAU POWER PLANT Mayes OK 1/23/2009 0.0006 1.06 lb/hrWA-0288 LONGVIEW ENERGY DEVELOPMEN Cowlitz WA 9/4/2001 Other Low sulfur fuel 0.0006

NJ-0059 COGEN TECHNOLOGIES LINDEN V Union NJ 5/9/2001 Other (N) 0.0010WA-0291 WALLULA POWER PLANT Walla Walla WA 1/3/2003 Other Low sulfur fuel 0.0017MA-0027 CABOT POWER CORPORATION Suffolk MA 5/7/2000 BACT-PSD Clean fuels 0.0022CT-0151 KLEEN ENERGY SYSTEMS, LLC Middlesex CT 2/25/2008 BACT-PSD (N) 0.0023 4.9 lb/hrWA-0315 SUMAS ENERGY 2 GENERATION FA Whatcom WA 4/17/2003 BACT-PSD Low sulfur fuel 0.0030

ID-0010 MIDDLETON FACILITY Canyon ID 10/19/2001 BACT-PSD Low sulfur fuel 0.0031 W/ DBNJ-0043 LIBERTY GENERATING STATION Union NJ 3/28/2002 Other Low sulfur fuel 0.0040NJ-0066 AES RED OAK LLC Middlesex NJ 2/16/2006 BACT-PSD Clean fuels 0.0043LA-0136 PLAQUEMINE COGENERATION FAC Iberville LA 7/23/2008 BACT-PSD Clean fuels 0.0142 40.7000 L

TX-0600 THOMAS C. FERGUSON POWER PL Llano TX 9/1/2011 BACT-PSD Pipeline quality natural gas 27.07 LB/

NJ-0074 WEST DEPTFORD ENERGY Gloucester NJ 5/6/2009 Other Clean fuels 5.6600 LBFL-0303 FPL WEST COUNTY ENERGY CENT Palm Beach FL 7/30/2008 BACT-PSD Pipeline quality natural gas 2.0000 G

NJ-0058 PSEG FOSSIL LLC LINDEN GENERA Union NJ 8/24/2001 BACT-PSD (N) 2.0000 LB

NV-0034 LAS VEGAS COGENERATION FACIL Clark NV 11/13/2000 BACT-PSD Low sulfur fuel 0.3000 LB

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RBLC Review for Large Combined Cycle Turbines - PM10 

RBLC ID Facility County State Permit Date Basis Control Limit (lb/MMBtu) 

OK-0129 CHOUTEAU POWER PLANT Mayes OK 1/23/2009 0.0035CT-0151 KLEEN ENERGY SYSTEMS, LLC Middlesex CT 2/25/2008 BACT-PSD (N) 0.0052 11 LB/HR W

Caithness Long Island Energy New York NY NA 0.0055 0.0066 W/ D

OR-0039 COB ENERGY FACILITY, LLC Klamath OR 12/30/2003 BACT-PSD Good combustion practices 0.0061NY-0100 EMPIRE POWER PLANT Rensselaer NY 6/23/2005 0.0063*AK-0071 INTERNATIONAL STATION POWER Anchorage AK 12/20/2010 BACT-PSD Good combustion practices 0.0066

CPV Valley Energy Center Wawayanda NY NA 0.0073

WA-0291 WALLULA POWER PLANT Walla Walla WA 1/3/2003 LAER Natural gas 0.0080GA-0105 MCINTOSH COMBINED CYCLE FAC Effingham GA 4/17/2003 BACT-PSD Clean fuels, Good combustion 0.0090

ID-0010 MIDDLETON FACILITY Canyon ID 10/19/2001 BACT-PSD Pollution prevention 0.0093 0.00939 LB/NJ-0074 WEST DEPTFORD ENERGY Gloucester NJ 5/6/2009 Other Clean fuels 0.0094 18.6600 LBAZ-0043 DUKE ENERGY ARLINGTON VALLE Maricopa AZ 11/12/2003 BACT-PSD (N) 0.0097 0.01103 LB/GA-0102 WANSLEY COMBINED CYCLE ENER Heard GA 1/15/2002 BACT-PSD Good combustion practices 0.0110

LA-0224 ARSENAL HILL POWER PLANT CADDO LA 3/20/2008 0.0115 24.2 LB/HRWA-0299 SUMAS ENERGY 2 GENERATION FA Whatcom WA 9/6/2002 BACT-PSD Good combustion practices 0.0115

LA-0136 PLAQUEMINE COGENERATION FAC Iberville LA 7/23/2008 BACT-PSD Clean fuels 0.0116 33.5000 LB

MI-0366 BERRIEN ENERGY, LLC Berrien MI 4/13/2005 BACT-PSD Good combustion practices 0.0120 19 LB/HR W

MA-0027 CABOT POWER CORPORATION Suffolk MA 5/7/2000 BACT-PSD Clean fuels 0.0120NJ-0058 PSEG FOSSIL LLC LINDEN GENERA Union NJ 8/24/2001 BACT-PSD (N) 0.0127 21.0000 LB

*VA-0308 WARREN COUNTY FACILITY Warren VA 1/14/2008 N/A Good combustion practices 0.0130NJ-0066 AES RED OAK LLC Middlesex NJ 2/16/2006 BACT-PSD Clean fuels 0.0135NJ-0043 LIBERTY GENERATING STATION Union NJ 3/28/2002 BACT-PSD None 0.0150 0.0170 LB/MNJ-0059 COGEN TECHNOLOGIES LINDEN V Union NJ 5/9/2001 BACT-PSD (N) 0.0260TX-0600 THOMAS C. FERGUSON POWER PL Llano TX 9/1/2011 BACT-PSD Pipeline quality natural gas 33.43 LB/H

*OR-0048 CARTY PLANT Morrow OR 12/29/2010 BACT-PSD Clean fuels 2.5 LB/MMCTX-0590 KING POWER STATION Harris TX 8/5/2010 BACT-PSD Low ash fuel 11.1 LB/HRWA-0288 LONGVIEW ENERGY DEVELOPMEN Cowlitz WA 9/4/2001 Other Good combustion practices 10 lb/hr

4 of 7
RBLC Review for Large Combined Cycle Turbines - PM2.5 

0 Brockton Clean Energy Brockton MA NA 0.0055 0.0

NY-0100 EMPIRE POWER PLANT Rensselaer NY 6/23/2005 0.0063*AK-0071 INTERNATIONAL STATION POWER Anchorage AK 12/20/2010 BACT-PSD Good combustion practices 0.0066

0 Caithness Long Island Energy New York NY NA 0.0073 0.0

TX-0600 THOMAS C. FERGUSON POWER PL Llano TX 9/1/2011 BACT-PSD Pipeline quality natural gas 33

TX-0590 KING POWER STATION Harris TX 8/5/2010 BACT-PSD Low ash fuel 11NJ-0074 WEST DEPTFORD ENERGY Gloucester NJ 5/6/2009 Other Clean fuels 18

5 of 7
RBLC Review for Large Combined Cycle Turbines - VOC 

RBLC ID Facility County State Permit Date Basis Control Limit (PPM) 

CPV Valley Energy Center Wawayanda NY NA LAER 0.7 1.8 PPM W/ DB

*VA-0308 WARREN COUNTY FACILITY Warren VA 1/14/2008 N/A Oxidation catalyst 0.7

1.0000 PPMVD WIT1.4000 PPMVD WITPOWER AUGMENT

NY-0100 EMPIRE POWER PLANT Rensselaer NY 6/23/2005 LAER Oxidation catalyst 1.0 7.0000 PPMDV AT NJ-0043 LIBERTY GENERATING STATION Union NJ 3/28/2002 Other CO Catalyst 1.0 1.7000 PPMVD @ 1MA-0027 CABOT POWER CORPORATION Suffolk MA 5/7/2000 BACT-PSD Oxidation catalyst 1.0FL-0303 FPL WEST COUNTY ENERGY CENT Palm Beach FL 7/30/2008 BACT-PSD (N) 1.2

NJ-0059 COGEN TECHNOLOGIES LINDEN V Union NJ 5/9/2001 Other (N) 1.2MI-0366 BERRIEN ENERGY, LLC Berrien MI 4/13/2005 BACT-PSD Oxidation catalyst 1.6 16 LB/H W/ DUCT BTX-0590 KING POWER STATION Harris TX 8/5/2010 LAER DLN, oxidation catalyst 1.8ID-0010 MIDDLETON FACILITY Canyon ID 10/19/2001 BACT-PSD None 1.8 3.8 PPM W/ DBNJ-0074 WEST DEPTFORD ENERGY Gloucester NJ 5/6/2009 LAER Oxidation catalyst, Good combustio 1.9

WA-0288 LONGVIEW ENERGY DEVELOPMEN Cowlitz WA 9/4/2001 Other Good combustion practices 1.9

ID-0018 LANGLEY GULCH POWER PLANT Payette ID 06/25/2010 BACT-PSD Oxidation catalyst 2.0TX-0600 THOMAS C. FERGUSON POWER PL Llano TX 9/1/2011 BACT-PSD Oxidation catalyst 2.0

GA-0138 LIVE OAKS POWER PLANT Glynn GA 4/8/2010 BACT-PSD Oxidation catalyst 2.0*TX-0546 PATTILLO BRANCH POWER PLANT Fannin TX 6/17/2009 BACT-PSD Oxidation catalyst 2.0CA-1096 VERNON CITY LIGHT & POWER Los Angeles CA 5/27/2003 BACT-PSD SCR, Oxidation catalyst 2.0GA-0105 MCINTOSH COMBINED CYCLE FA

C Effingham GA 4/17/2003 BACT-PSD Oxidation catalyst 2.0

GA-0102 WANSLEY COMBINED CYCLE ENER Heard GA 1/15/2002 BACT-PSD Good combustion practices 2.0

OR-0039 COB ENERGY FACILITY, LLC Klamath OR 12/30/2003 BACT-PSD Oxidation catalyst, Good combustio 2.4

*TX-0548 MADISON BELL ENERGY CENTER Madison TX 8/18/2009 BACT-PSD Good combustion practices 2.5TX-0552 WOLF HOLLOW POWER PLANT N

O Hood TX 3/3/2010 BACT-PSD DLN, SCR 3.0 GE7FA

NJ-0066 AES RED OAK LLC Middlesex NJ 2/16/2006 LAER Oxidation catalyst 3.0TX-0551 PANDA SHERMAN POWER STATION Grayson TX 2/3/2010 BACT-PSD DLN, SCR 4.0 Combined-cycle mod

*TX-0547 LAMAR POWER PARTNERS II LLC Lamar TX 6/22/2009 BACT-PSD Good combustion practices 4.0NY-0098 ATHENS GENERATING PLANT Greene NY 1/19/2007 LAER Good combustion practices 4.0AZ-0043 DUKE ENERGY ARLINGTON VALLE Maricopa AZ 11/12/2003 BACT-PSD (N) 4.0CT-0151 KLEEN ENERGY SYSTEMS, LLC Middlesex CT 2/25/2008 BACT-PSD (N) 5.0WA-0291 WALLULA POWER PLANT Walla Walla WA 1/3/2003 Other Good combustion practices 5.0WA-0315 SUMAS ENERGY 2 GENERATION F

A Whatcom WA 4/17/2003 BACT-PSD Good combustion practices 5.2

WA-0302 GOLDENDALE ENERGY PROJECT Klickitat WA 2/23/2001 BACT-PSD Oxidation catalyst, Good combustio 6.0

Caithness Long Island Energy New York NY NA 3.5 LB/H; 6.1 LB/H WBrockton Clean Energy Brockton MA NA 1.0 LB/H; 2.5 LB/H W

NJ-0058 PSEG FOSSIL LLC LINDEN GENER

A Union NJ 8/24/2001 LAER Oxidation catalyst 2.1000 LB/H

NV-0034 LAS VEGAS COGENERATION FACIL Clark NV 11/13/2000 BACT-PSD Oxidation catalyst 2.0000 LB/H

6 of 7
RBLC Review for Large Combined Cycle Turbines - H2SO4 

RBLC ID Facility County State Permit Date Basis Control Limit (lb/MMBtu) 

*VA-0308 WARREN COUNTY FACILITY Warren VA 1/14/2008 N/A Good combustion practices 0.00010WA-0302 GOLDENDALE ENERGY PROJECT Klickitat WA 2/23/2001 Other Good combustion practices 0.00010WA-0315 SUMAS ENERGY 2 GENERATION FA Whatcom WA 4/17/2003 BACT-PSD Low sulfur fuel 0.00062

WA-0291 WALLULA POWER PLANT Walla Walla WA 1/3/2003 Other Natural gas 0.00073NJ-0043 LIBERTY GENERATING STATION Union NJ 3/28/2002 Other None 0.00243NJ-0066 AES RED OAK LLC Middlesex NJ 2/16/2006 BACT-PSD Low sulfur fuel 0.00270TX-0600 THOMAS C. FERGUSON POWER PL Llano TX 9/1/2011 BACT-PSD Pipeline quality natural gas 

7 of 7