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DEPARTMENT OF ENVIRONMENTAL QUALITY

 

DIVISION 228

REQUIREMENTS FOR FUEL BURNING EQUIPMENT AND FUEL SULFUR CONTENT

340-228-0010

Applicability and Jurisdiction

(1) This division applies in all areas of the state.

(2) Subject to the requirements in this division and OAR 340-200-0010(3), LRAPA is designated by the EQC to implement the rules in this division within its area of jurisdiction.

NOTE: This rule is included in the State of Oregon Clean Air Act Implementation Plan that EQC adopted under OAR 340-200-0040.

Stat. Auth.: ORS 468.020 & 468A.025
Stats. Implemented: ORS 468A.025
Hist.: DEQ 10-1995, f. & cert. ef. 5-1-95; DEQ 14-1999, f. & cert. ef. 10-14-99, Renumbered from 340-021-0012; DEQ 7-2015, f. & cert. ef. 4-16-15

340-228-0020

Definitions

The definitions in OAR 340-200-0020, 340-204-0010 and this rule apply to this division. If the same term is defined in this rule and 340-200-0020 or 340-204-0010, the definition in this rule applies to this division.

(1) "Distillate fuel oil" means any oil meeting the specifications of ASTM Grade 1 or 2 fuel oils;

(2) "Residual fuel oil" means any oil meeting the specifications of ASTM Grade 4, 5, or 6 fuel oils.

NOTE: This rule is included in the State of Oregon Clean Air Act Implementation Plan that EQC adopted under OAR 340-200-0040.

Stat. Auth.: ORS 468.020 & 468A
Stats. Implemented: ORS 468A.025
Hist.: [DEQ 16, f. 6-12-70, ef. 7-11-70; DEQ 1-1984, f. & ef. 1-16-84; DEQ 4-1993, f. & cert. ef. 3-10-93; DEQ 3-1996, f. & cert. ef. 1-29-96]; [DEQ 37, f. 2-15-72, ef. 3-1-72; DEQ 4-1993, f. & cert. ef. 3-10-93]; [DEQ 37, f. 2-15-72, ef. 3-1-72; DEQ 4-1993, f. & cert. ef. 3-10-93]; DEQ 14-1999, f. & cert. ef. 10-14-99, Renumbered from 340-021-0005, 340-022-0005, 340-022-0050; DEQ 8-2007, f. & cert. ef. 11-8-07; DEQ 7-2011(Temp), f. & cert. ef. 6-24-11 thru 12-19-11; Administrative correction, 2-6-12; DEQ 1-2012, f. & cert. ef. 5-17-12; DEQ 7-2015, f. & cert. ef. 4-16-15

Sulfur Content of Fuels

340-228-0100

Residual Fuel Oils

No person may sell, distribute, use, or make available for use, any residual fuel oil containing more than 1.75 percent sulfur by weight.

NOTE: This rule is included in the State of Oregon Clean Air Act Implementation Plan as adopted by the Environmental Quality Commission under OAR 340-200-0040.

Stat. Auth.: ORS 468.020 & 468A.025
Stats. Implemented: ORS 468A.025
Hist.: DEQ 37, f. 2-15-72, ef. 3-1-72; DEQ 87, f. 3-25-75, ef. 4-25-75; DEQ 141, f. & ef. 8-25-77; DEQ 4-1993, f. & cert. ef. 3-10-93; DEQ 14-1999, f. & cert. ef. 10-14-99, Renumbered from 340-022-0010; DEQ 7-2015, f. & cert. ef. 4-16-15

340-228-0110

Distillate Fuel Oils

No person shall sell, distribute, use, or make available for use, any distillate fuel oil containing more than the following percentages of sulfur:

(1) ASTM Grade 1 fuel oil — 0.3 percent by weight.

(2) ASTM Grade 2 fuel oil — 0.5 percent by weight.

NOTE: This rule is included in the State of Oregon Clean Air Act Implementation Plan that EQC adopted under OAR 340-200-0040.

Stat. Auth.: ORS 468.020 & 468A.025
Stats. Implemented: ORS 468A.025
Hist.: DEQ 37, f. 2-15-72, ef. 3-1-72; DEQ 4-1993, f. & cert. ef. 3-10-93; DEQ 14-1999, f. & cert. ef. 10-14-99, Renumbered from 340-022-0015; DEQ 7-2015, f. & cert. ef. 4-16-15

340-228-0120

Coal

(1) Except as provided in section (2), no person may sell, distribute, use, or make available for use, any coal containing greater than 1.0 percent sulfur by weight.

(2) No person may sell, distribute, use or make available for use any coal or coal containing fuel with greater than 0.3 percent sulfur and five percent volatile matter as defined in ASTM Method D3175 for direct space heating within the Portland, Salem, Eugene-Springfield, and Medford-Ashland Air Quality Maintenance Areas. For coals subjected to a devolatilization process, compliance with the sulfur limit may be demonstrated on the sulfur content of coal prior to the devolatilization process.

(3) Distributors of coal or coal containing fuel destined for direct residential space heating use must keep records for a five year period which must be available for DEQ inspection and which:

(a) Specify quantities of coal or coal containing fuels sold;

(b) Contain name and address of customers who are sold coal or coal containing fuels;

(c) Specify the sulfur and volatile content of coal or the coal containing fuel sold to residences in the Portland, Salem, Eugene-Springfield, and Medford-Ashland Air Quality Maintenance Areas.

NOTE: This rule is included in the State of Oregon Clean Air Act Implementation Plan that EQC adopted under OAR 340-200-0040.

Stat. Auth.: ORS 468.020 & 468A.025
Stats. Implemented: ORS 468A.025
Hist.: DEQ 37, f. 2-15-72, ef. 3-1-72; DEQ 3-1982, f. & ef. 1-29-82; DEQ 4-1993, f. & cert. ef. 3-10-93; DEQ 14-1999, f. & cert. ef. 10-14-99, Renumbered from 340-022-0020; DEQ 7-2015, f. & cert. ef. 4-16-15

340-228-0130

Exemptions

Exempted from the requirements of OAR 340-228-0100 through 340-228-0120 are:

(1) Fuels used exclusively for the propulsion and auxiliary power requirements of vessels, railroad locomotives, and diesel motor vehicles.

(2) With prior approval of DEQ, fuels used in such a manner or control provided such that sulfur dioxide emissions can be demonstrated to be equal to or less than those resulting from the combustion of fuels complying with the limitations of OAR 340-228-0100 through 340-228-0120.

NOTE: This rule is included in the State of Oregon Clean Air Act Implementation Plan that EQC adopted under OAR 340-200-0040.

Stat. Auth.: ORS 468.020 & 468A.025
Stats. Implemented: ORS 468A.025
Hist.: DEQ 37, f. 2-15-72, ef. 3-1-72; DEQ 4-1993, f. & cert. ef. 3-10-93; DEQ 14-1999, f. & cert. ef. 10-14-99, Renumbered from 340-022-0025; DEQ 7-2015, f. & cert. ef. 4-16-15

General Emission Standards for Fuel Burning Equipment

340-228-0200

Sulfur Dioxide Standards

The following emission standards are only applicable to sources installed, constructed, or modified after January 1, 1972 except recovery furnaces regulated in OAR 340 division 234:

(1) For fuel burning equipment having a heat input capacity between 150 million BTU per hour and 250 million BTU, no person may cause, suffer, allow, or permit the emission into the atmosphere of sulfur dioxide in excess of:

(a) 1.4 pounds per million BTU heat input, maximum three-hour average, when liquid fuel is burned;

(b) 1.6 pounds per million BTU heat input, maximum three-hour average, when solid fuel is burned.

(2) For fuel burning equipment having a heat input capacity of more than 250 million BTU per hour, no person may cause, suffer, allow, or permit the emission into the atmosphere of sulfur dioxide in excess of:

(a) 0.8 pound per million BTU heat input, maximum three-hour average, when liquid fuel is burned;

(b) 1.2 pounds per million BTU heat input, maximum three-hour average, when solid fuel is burned.

NOTE: This rule is included in the State of Oregon Clean Air Act Implementation Plan that EQC adopted under OAR 340-200-0040

Stat. Auth.: ORS 468.020 & 468A.025
Stats. Implemented: ORS 468A.025
Hist.: DEQ 37, f. 2-15-72, ef. 3-1-72; DEQ 4-1993, f. & cert. ef. 3-10-93; DEQ 22-1996, f. & cert. ef. 10-22-96; DEQ 14-1999, f. & cert. ef. 10-14-99, Renumbered from 340-022-0055; DEQ 8-2007, f. & cert. ef. 11-8-07; DEQ 7-2011(Temp), f. & cert. ef. 6-24-11 thru 12-19-11; Administrative correction, 2-6-12; DEQ 1-2012, f. & cert. ef. 5-17-12; DEQ 7-2015, f. & cert. ef. 4-16-15

340-228-0210

Grain Loading Standards

(1) This rule applies to fuel burning equipment, except solid fuel burning devices that have been certified under OAR 340-262-0500.

(2) No person may cause, suffer, allow, or permit particulate matter emissions from any fuel burning equipment in excess of the following limits:

(a) For sources installed, constructed, or modified before June 1, 1970:

(A) 0.10 grains per dry standard cubic foot provided that all representative compliance source test results collected prior to April 16, 2015 demonstrate emissions no greater than 0.080 grains per dry standard cubic foot;

(B) If any representative compliance source test results collected prior to April 16, 2015 demonstrate emissions greater than 0.080 grains per dry standard cubic foot, or if there are no representative compliance source test results, then:

(i) 0.24 grains per dry standard cubic foot until Dec. 31, 2019; and

(ii) 0.15 grains per dry standard cubic foot on and after Jan. 1, 2020; and

(C) In addition to the limits in paragraph (A) or (B), for equipment or a mode of operation (e.g., backup fuel) that is used less than 876 hours per calendar year, 0.24 grains per dry standard cubic foot from April 16, 2015 through December 31, 2019, and 0.20 grains per dry standard cubic foot on and after Jan. 1, 2020.

(b) For sources installed, constructed, or modified on or after June 1, 1970 but prior to April 16, 2015:

(A) 0.10 grains per dry standard cubic foot provided that all representative compliance source test results prior to April 16, 2015 demonstrate emissions no greater than 0.080 grains per dry standard cubic foot; or

(B) If any representative compliance source test results collected prior to April 16, 2019 demonstrate emissions greater than 0.080 grains per dry standard cubic foot, or if there are no representative compliance source test results, then 0.14 grains per dry standard cubic foot.

(c) For sources installed, constructed or modified on or after April 16, 2015, 0.10 grains per dry standard cubic foot.

(d)(A) The owner or operator of a source installed, constructed or modified before June 1, 1970 who is unable to comply with the standard in subparagraph (a)(B)(ii) may request that DEQ set a source specific limit of 0.17 grains per dry standard cubic foot. The owner or operator must submit an application for a permit modification to request the alternative limit by no later than Oct. 1, 2019 that demonstrates, based on a signed report prepared by a registered professional engineer that specializes in boiler/multiclone operation, that the fuel burning equipment will be unable to comply with the standard in subparagraph (a)(B)(ii) after either:

(i) Maintenance or upgrades to an existing multiclone system; or

(ii) Conducting a boiler tune-up if the boiler does not have a particulate matter emission control system.

(B) If a source qualifies under paragraph (A), DEQ will add the 0.17 grains per dry standard cubic foot source specific limit as a significant permit modification (simple fee) for sources with an Oregon Title V Operating Permit or a Simple Technical Modification for sources with an Air Contaminant Discharge Permit.

(e) The owner or operator of a source installed, constructed or modified before June 1, 1970 may request that DEQ grant an extension allowing the source up to one additional year to comply with the standard in paragraph (d)(A) provided that the owner or operator demonstrates, based on an engineering report signed by a registered professional engineer that specializes in boiler/multiclone operation, that the source cannot comply with the source specific limit established in OAR 340-228-0210(2)(d)(A) without making significant changes to the equipment or control equipment or adding control equipment. The request for an extension must be submitted no later than Oct. 1, 2019.

(3) Compliance with the emissions standards in section (2) is determined using Oregon Method 5, or an alternative method approved by DEQ.

(a) For fuel burning equipment that burns wood fuel by itself or in combination with any other fuel, the emission results are corrected to 12% CO2.

(b) For fuel burning equipment that burns fuels other than wood, the emission results are corrected to 50% excess air.

(c) For purposes of this rule, representative compliance source test results are data that was obtained:

(A) No more than ten years before April 16, 2015; and

(B) When a source is operating and maintaining air pollution control devices and emission reduction processes at the highest reasonable efficiency and effectiveness to minimize emissions based on the current configuration of the fuel burning equipment and pollution control equipment.

NOTE: This rule is included in the State of Oregon Clean Air Act Implementation Plan that EQC adopted under OAR 340-200-0040.

Stat. Auth.: ORS 468.020, 468A.025 & 468A.070
Stats. Implemented: ORS 468A.025 & 468A.070
Hist.: DEQ 16, f. 6-12-70, ef. 7-11-70; DEQ 12-1979, f. & ef. 6-8-79; DEQ 6-1981, f. & ef. 2-17-81; DEQ 18-1982, f. & ef. 9-1-82; DEQ 4-1993, f. & cert. ef. 3-10-93; DEQ 3-1996, f. & cert. ef. 1-29-96; DEQ 14-1999, f. & cert. ef. 10-14-99, Renumbered from 340-021-0020; DEQ 8-2007, f. & cert. ef. 11-8-07; DEQ 7-2011(Temp), f. & cert. ef. 6-24-11 thru 12-19-11; Administrative correction, 2-6-12; DEQ 1-2012, f. & cert. ef. 5-17-12; DEQ 7-2015, f. & cert. ef. 4-16-15

Federal Acid Rain Program

340-228-0300

Federal Regulations Adopted by Reference

(1) 40 CFR parts 72, 75, and 76 are by this reference adopted and incorporated herein, for purposes of implementing an acid rain program that meets the requirements of title IV of the FCAA. The term "permitting authority" means the Oregon DEQ and the term "Administrator" means the Administrator of the United States EPA.

(2) If the provisions or requirements of 40 CFR part 72 conflict with or are not included in OAR 340 divisions 218 or 220, the part 72 provisions and requirements must apply and take precedence.

[Publications: Publications referenced are available from the agency.]

Stat. Auth.: ORS 468.020, 468A.025, 468A.040 & 468A.310
Stats. Implemented: ORS 468A.025, 468A.040 & 468A.310
Hist.: DEQ 32-1994, f. & cert. ef. 12-22-94; DEQ 14-1999, f. & cert. ef. 10-14-99, Renumbered from 340-022-0075; DEQ 22-2000, f. & cert. ef. 12-18-00; DEQ 13-2006, f. & cert. ef. 12-22-06; DEQ 5-2011, f. 4-29-11, cert. ef. 5-1-11; DEQ 7-2015, f. & cert. ef. 4-16-15

Mercury Rules For Coal-Fired Power Plants
Utility Mercury Rule

General Provisions

340-228-0600

Purpose

This rule establishes the mandatory reduction levels and monitoring provisions for the Utility Mercury Rule, as a means of reducing mercury (Hg) emissions in Oregon.

Stat. Auth.: ORS 468.020 & 468A.310
Stats. Implemented: ORS 468A.025
Hist.: DEQ 13-2006, f. & cert. ef. 12-22-06; DEQ 15-2008, f. & cert. ef 12-31-08

340-228-0601

Applicability

(1) Except as provided in section (2) of this rule:

(a) The following units in the State shall be coal-fired electric generating units subject to the requirements of OAR 340-228-0600 through 0637: Any stationary, coal-fired boiler or stationary, coal-fired combustion turbine serving at any time, since the later of November 15, 1990 or the start-up of the unit's combustion chamber, a generator with nameplate capacity of more than 25 MWe producing electricity for sale.

(b) If a stationary boiler or stationary combustion turbine that, under subsection (1)(a) of this rule, is not a coal-fired electric generating unit begins to combust coal or coal-derived fuel or to serve a generator with nameplate capacity of more than 25 MWe producing electricity for sale, the unit shall become a coal-fired electric generating unit as provided in subsection (1)(a) of this rule on the first date on which it both combusts coal or coal-derived fuel and serves such generator.

(2) The units in the State that meet the requirements set forth in paragraph (2)(a)(A) or subsection (2)(b) of this rule are not coal-fired electric generating units:

(a) Any unit that is a coal-fired electric generating unit under subsection (1)(a) or (b) of this rule:

(A) Qualifying as a cogeneration unit during the 12-month period starting on the date the unit first produces electricity and continuing to qualify as a cogeneration unit; and not serving at any time, since the later of November 15, 1990 or the start-up of the unit's combustion chamber, a generator with nameplate capacity of more than 25 MWe supplying in any calendar year more than one-third of the unit's potential electric output capacity or 219,000 MWh, whichever is greater, to any utility power distribution system for sale.

(B) If a unit qualifies as a cogeneration unit during the 12-month period starting on the date the unit first produces electricity and meets the requirements of paragraph (2)(a)(A) of this rule for at least one calendar year, but subsequently no longer meets all such requirements, the unit shall become a coal-fired electric generating unit starting on the earlier of January 1 after the first calendar year during which the unit first no longer qualifies as a cogeneration unit or January 1 after the first calendar year during which the unit no longer meets the requirements of paragraph (2)(a)(A) of this rule.

(b) Any unit that is a coal-fired electric generating unit under subsection (1)(a) or (b) of this rule, is a solid waste incineration unit combusting municipal waste, and is subject to the requirements of:

(A) A State Plan approved by the Administrator of the EPA in accordance with 40 CFR part 60 subpart Cb (emissions guidelines and compliance times for certain large municipal waste combustors);

(B) 40 CFR part 60 subpart Eb (standards of performance for certain large municipal waste combustors);

(C) 40 CFR part 60 subpart AAAA (standards of performance for certain small municipal waste combustors);

(D) A State Plan approved by the Administrator of the EPA in accordance with 40 CFR part 60 subpart BBBB (emission guidelines and compliance times for certain small municipal waste combustion units);

(E) 40 CFR part 62 subpart FFF (Federal Plan requirements for certain large municipal waste combustors); or

(F) 40 CFR part 62 subpart JJJ (Federal Plan requirements for certain small municipal waste combustion units).

Stat. Auth.: ORS 468.020 & 468A.310
Stats. Implemented: ORS 468A.025
Hist.: DEQ 15-2008, f. & cert. ef 12-31-08

340-228-0602

Definitions

The terms used in OAR 340-228-0606 through 0639 are defined as follows, in 40 CFR 63.10042, and in Appendix A to 40 CFR part 63 subpart UUUUU:

(1) "Boiler" means an enclosed fossil-or other fuel-fired combustion device used to produce heat and to transfer heat to recirculating water, steam, or other medium.

(2) "CFR" means Code of Federal Regulations and, unless otherwise expressly identified, refers to the July 1, 2012 edition.

(3) "Coal-derived fuel" means any fuel (whether in a solid, liquid, or gaseous state) produced by the mechanical, thermal, or chemical processing of coal.

(4) "Coal-fired" means combusting any amount of coal or coal-derived fuel, alone or in combination with any amount of any other fuel, during any year.

(5) "Combustion turbine" means:

(a) An enclosed device comprising a compressor, a combustor, and a turbine and in which the flue gas resulting from the combustion of fuel in the combustor passes through the turbine, rotating the turbine; and

(b) If the enclosed device under paragraph (a) of this definition is combined cycle, any associated heat recovery steam generator and steam turbine.

(6) "Commence commercial operation" means, with regard to a unit serving a generator:

(a) To have begun to produce steam, gas, or other heated medium used to generate electricity for sale or use, including test generation.

(A) For a unit that is a coal-fired electric generating unit under OAR 340-228-0601 on the date the unit commences commercial operation as defined in paragraph (a) of this definition and that subsequently undergoes a physical change (other than replacement of the unit by a unit at the same source), such date shall remain the unit's date of commencement of commercial operation.

(B) For a unit that is a coal-fired electric generating unit under OAR 340-228-0601 on the date the unit commences commercial operation as defined in paragraph (a) of this definition and that is subsequently replaced by a unit at the same source (e.g., repowered), the replacement unit shall be treated as a separate unit with a separate date for commencement of commercial operation as defined in paragraph (a) or (b) of this definition as appropriate.

(b) Notwithstanding paragraph (a) of this definition, for a unit that is not a coal-fired electric generating unit under OAR 340-228-0601 on the date the unit commences commercial operation as defined in paragraph (a) of this definition, the unit's date for commencement of commercial operation shall be the date on which the unit becomes a coal-fired electric generating unit under OAR 340-228-0601.

(A) For a unit with a date for commencement of commercial operation as defined in paragraph (b) of this definition and that subsequently undergoes a physical change (other than replacement of the unit by a unit at the same source), such date remains the unit's date of commencement of commercial operation.

(B) For a unit with a date for commencement of commercial operation as defined in paragraph (b) of this definition and that is subsequently replaced by a unit at the same source (e.g., repowered), the replacement unit shall be treated as a separate unit with a separate date for commencement of commercial operation as defined in paragraph (a) or (b) of this definition as appropriate.

(7) "Commence operation" means:

(a) To have begun any mechanical, chemical, or electronic process, including, with regard to a unit, start-up of a unit's combustion chamber.

(A) For a unit that is a coal-fired electric generating unit under OAR 340-228-0601 on the date the unit commences operation as defined in paragraph (a) of this definition and that subsequently undergoes a physical change (other than replacement of the unit by a unit at the same source), such date shall remain the unit's date of commencement of operation.

(B) For a unit that is a coal-fired electric generating unit under OAR 340-228-0601 on the date the unit commences operation as defined in paragraph (a) of this definition and that is subsequently replaced by a unit at the same source (e.g., repowered), the replacement unit shall be treated as a separate unit with a separate date for commencement of operation as defined in paragraph (a) or (b) of this definition as appropriate.

(b) Notwithstanding paragraph (a) of this definition, for a unit that is not a coal-fired electric generating unit under OAR 340-228-0601 on the date the unit commences operation as defined in paragraph (a) of this definition, the unit's date for commencement of operation shall be the date on which the unit becomes a coal-fired electric generating unit under OAR 340-228-0601.

(A) For a unit with a date for commencement of operation as defined in paragraph (b) of this definition and that subsequently undergoes a physical change (other than replacement of the unit by a unit at the same source), such date shall remain the unit's date of commencement of operation.

(B) For a unit with a date for commencement of operation as defined in paragraph (b) of this definition and that is subsequently replaced by a unit at the same source (e.g., repowered), the replacement unit shall be treated as a separate unit with a separate date for commencement of operation as defined in paragraph (a) or (b) of this definition as appropriate.

(8) "Emissions" means air pollutants exhausted from a unit or source into the atmosphere, as measured, recorded, and reported to DEQ in accordance with OAR 340-228-0609 through 0637.

(9) "Heat input" means, with regard to a specified period of time, the product (in MMBtu/time) of the gross calorific value of the fuel (in Btu/lb) divided by 1,000,000 Btu/MMBtu and multiplied by the fuel feed rate into a combustion device (in lb of fuel/time), as measured, recorded, and reported to DEQ by the owner or operator and excluding the heat derived from preheated combustion air, recirculated flue gases, or exhaust from other sources.

(10) "Life-of-the-unit, firm power contractual arrangement" means a unit participation power sales agreement under which a utility or industrial customer reserves, or is entitled to receive, a specified amount or percentage of nameplate capacity and associated energy generated by any specified unit and pays its proportional amount of such unit's total costs, pursuant to a contract:

(a) For the life of the unit;

(b) For a cumulative term of no less than 30 years, including contracts that permit an election for early termination; or

(c) For a period no less than 25 years or 70 percent of the economic useful life of the unit determined as of the time the unit is built, with option rights to purchase or release some portion of the nameplate capacity and associated energy generated by the unit at the end of the period.

(11) "Monitoring system" means any monitoring system that meets the requirements of OAR 340-228-0609 through 0637, including a continuous emission monitoring system or an approved alternative monitoring system.

(12) "Nameplate capacity" means, starting from the initial installation of a generator, the maximum electrical generating output (in MWe) that the generator is capable of producing on a steady-state basis and during continuous operation (when not restricted by seasonal or other deratings) as specified by the manufacturer of the generator or, starting from the completion of any subsequent physical change in the generator resulting in an increase in the maximum electrical generating output (in MWe) that the generator is capable of producing on a steady-state basis and during continuous operation (when not restricted by seasonal or other deratings), such increased maximum amount as specified by the person conducting the physical change.

(13) "Operator" means any person who operates, controls, or supervises a coal-fired electric utility steam generating unit and shall include, but not be limited to, any holding company, utility system, or plant manager of such a unit or source.

(14) "Owner" means any of the following persons:

(a) Any holder of any portion of the legal or equitable title in a coal-fired electric utility steam generating unit;

(b) Any holder of a leasehold interest in a coal-fired electric utility steam generating unit; or

(c) Any purchaser of power from a coal-fired electric utility steam generating unit under a life-of-the-unit, firm power contractual arrangement; provided that, unless expressly provided for in a leasehold agreement, owner shall not include a passive lessor, or a person who has an equitable interest through such lessor, whose rental payments are not based (either directly or indirectly) on the revenues or income from such coal-fired electric utility steam generating unit.

(15) "Repowered" means, with regard to a unit, replacement of a coal-fired boiler with one of the following coal-fired technologies at the same source as the coal-fired boiler:

(a) Atmospheric or pressurized fluidized bed combustion;

(b) Integrated gasification combined cycle;

(c) Magnetohydrodynamics;

(d) Direct and indirect coal-fired turbines;

(e) Integrated gasification fuel cells; or

(f) As determined by DEQ in consultation with the Secretary of Energy, a derivative of one or more of the technologies under paragraphs (a) through (e) of this definition and any other coal-fired technology capable of controlling multiple combustion emissions simultaneously with improved boiler or generation efficiency and with significantly greater waste reduction relative to the performance of technology in widespread commercial use as of January 1, 2005.

(16) "Submit or serve" means to send or transmit a document, information, or correspondence to the person specified in accordance with the applicable regulation:

(a) In person;

(b) By United States Postal Service; or

(c) By other means of dispatch or transmission and delivery. Compliance with any ''submission'' or ''service'' deadline shall be determined by the date of dispatch, transmission, or mailing and not the date of receipt.

(17) "Unit" means a stationary coal-fired boiler or a stationary coal-fired combustion turbine.

Stat. Auth.: ORS 468.020 & 468A.310
Stats. Implemented: ORS 468A.025
Hist.: DEQ 13-2006, f. & cert. ef. 12-22-06; DEQ 15-2008, f. & cert. ef 12-31-08; DEQ 4-2013, f. & cert. ef. 3-27-13

340-228-0603

Measurements, Abbreviations, and Acronyms

Measurements, abbreviations, and acronyms used in this part are defined as follows:

(1) Btu-British thermal unit.

(2) CO2-carbon dioxide.

(3) dscm-dry standard cubic meter.

(4) H2O-water.

(5) Hg-mercury.

(6) hr-hour.

(7) kW-kilowatt electrical.

(8) kWh-kilowatt hour.

(9) lb-pound.

(10) m3-standard cubic meter.

(11) MMBtu-million Btu.

(12) MWe-megawatt electrical.

(13) MWh-megawatt hour.

(14) NOX-nitrogen oxides.

(15) O2-oxygen.

(16) ppm-parts per million.

(17) scf-standard cubic foot.

(18) scfh-standard cubic feet per hour.

(19) SO2-sulfur dioxide.

(20) μg-micrograms.

(21) wscm-wet standard cubic meter.

(22) yr-year.

Stat. Auth.: ORS 468.020 & 468A.310
Stats. Implemented: ORS 468A.025
Hist.: DEQ 13-2006, f. & cert. ef. 12-22-06; DEQ 15-2008, f. & cert. ef 12-31-08

340-228-0606

Hg Emission Standards

(1) Mercury emission standards. On and after July 1, 2012 or at commencement of commercial operation, whichever is later, except as allowed under section (2) of this rule, each coal-fired electric utility steam generating unit must achieve at least 90 percent mercury capture or limit mercury emissions to 0.60 pounds per trillion BTU of heat input.

(2) Compliance extension. Up to a 2-year extension may be granted by DEQ if the owner or operator of a coal-fired electric utility steam generating unit demonstrates that it is not practical to install mercury control equipment by July 1, 2012 due to supply limitations, ESP fly ash contamination, or other extenuating circumstances that are beyond the control of the owner or operator.

(3) Compliance demonstration. Commencing in July 2013 or 12 months after commercial startup or 12 months after expiration of the extension granted under section (2) of this rule, whichever is later, each coal-fired electric utility steam generating unit must thereafter demonstrate compliance with one of the standards in subsections (3)(a) or (3)(b) of this rule for each compliance period, except as allowed under sections (4) and (5) of this rule. A compliance period consists of twelve months. Each month commencing with June 2013 or the twelfth month after commencement of commercial operation or twelfth month after expiration of the extension granted under section (2) of this rule, whichever is later, is the end of a compliance period consisting of that month and the previous 11 months.

(a) A mercury emission standard of 0.60 pounds per trillion BTU of heat input calculated by dividing the Hg mass emissions determined using a mercury CEMS or sorbent trap monitoring system by heat input; or

(b) A minimum 90 percent capture of inlet mercury determined as follows:

(A) Inlet mercury must be determined as specified in subparagraph (3)(b)(A)(i) or (3)(b)(A)(ii) of this rule:

(i) Coal sampling and analysis. To demonstrate compliance by coal sampling and analysis, the owner or operator of a coal-fired electric utility steam generating unit must test its coal for mercury consistent with a coal sampling and analysis plan. The coal sampling and analysis plan must be consistent with the requirements of OAR 340-228-0639.

(ii) Hg mass emissions prior to any control device(s). To demonstrate compliance by measuring Hg mass emissions, the owner or operator of a coal-fired electric utility steam generating unit must measure mercury emissions prior to any control device(s) using a Hg CEMS or sorbent trap.

(B) The mercury capture efficiency must be calculated using the Hg emissions determined using a mercury CEMS or sorbent trap monitoring system and the inlet mercury determined using the coal mercury content data obtained in accordance with subparagraph (3)(b)(A)(i) of this rule or the measured inlet mercury data obtained in accordance with subparagraph (3)(b)(A)(ii) of this rule and a calculation methodology approved by DEQ.

(4) Temporary compliance alternative. If the owner or operator of a coal-fired electric utility steam generating unit properly implements the approved control strategy and the strategy fails to achieve at least 90 percent mercury capture or limit mercury emissions to 0.60 pounds per trillion BTU of heat input:

(a) The owner or operator must notify DEQ of the failure within 30 days of the end of the initial compliance period; and

(b) The owner or operator must file an application with EQ for a permit or permit modification in accordance with OAR 340 division 216 to establish a temporary alternative mercury emission limit. The application must be filed within 60 days of the end of the initial compliance period, and must include a continual program of mercury control progression able to achieve at least 90 percent mercury capture or to limit mercury emissions to 0.60 pounds per trillion BTU of heat input and all monitoring and operating data for the coal-fired electric utility steam generating unit.

(c) DEQ may establish a temporary alternative mercury emission limit only if the owner or operator applies for a permit or permit modification, that includes a control strategy that DEQ determines constitutes a continual program of mercury control progression able to achieve at least 90 percent mercury capture or to limit mercury emissions to 0.60 pounds per trillion BTU of heat input.

(d) Establishment of a temporary alternative mercury emission limit requires public notice in accordance with OAR 340 division 209 for Category III permit actions

(e) If the owner or operator files an application under subsection (4)(b) of this rule, the coal-fired electric utility steam generating unit must operate according to the temporary alternative mercury emission limit proposed in the permit or permit modification application until DEQ either denies the application or issues the permit or permit modification. Compliance with the proposed temporary alternative mercury emission limit prior to final DEQ action on the application shall constitute compliance with the limits in section (1) of this rule.

(f) A temporary alternative mercury emission limit established in a permit expires July 1, 2016 or within 2 years of commencement of commercial operation, whichever is later.

(5) Permanent compliance alternative. If the owner or operator of a coal-fired electric utility steam generating unit is unable to achieve at least 90 percent mercury capture or an emission level of 0.60 pounds per trillion BTU of heat input by July 1, 2016 or within 2 years of commencement of commercial operation, whichever is later, despite properly implementing the continual program of mercury progression required in section (4) of this rule:

(a) The owner or operator of the coal-fired electric utility steam generating unit may file an application with DEQ for a permit modification in accordance with OAR 340 division 216 to establish a permanent alternative mercury emission limit that comes as near as technically possible to achieving 90 percent mercury capture or an emission level of 0.60 pounds per trillion BTU of heat input.

(b) DEQ may establish a permanent alternative mercury emission limit only if the owner or operator applies for a permit modification, that proposes an alternative mercury emission limit that DEQ determines comes as near as technically possible to achieving 90 percent mercury capture or an emission level of 0.60 pounds per trillion BTU of heat input.

(c) Establishment of a permanent alternative mercury emission limit requires public notice in accordance with OAR 340 division 209 for Category IV permit actions.

(d) If the owner or operator files an application under subsection (5)(a) of this rule, the coal-fired electric utility steam generating unit must operate according to the permanent alternative mercury emission limit proposed in the permit modification application until DEQ either denies the application or modifies the permit. Compliance with the proposed permanent alternative mercury emission limit prior to final DEQ action on the application shall constitute compliance with the limits in section (1) of this rule.

(6) Emission Caps. Beginning in calendar year 2018, the following coal-fired electric utility steam generating unit specific emission caps shall apply.

(a) Existing Boardman coal-fired electric utility steam generating unit cap. The existing coal-fired electric utility steam generating unit in Boardman shall emit no more than:

(A) 60 pounds of mercury in any calendar year in which there are no new coal-fired electric utility steam generating units operated in Oregon.

(B) 35 pounds of mercury in any calendar year in which there are new coal-fired electric utility steam generating units operated in Oregon.

(b) New coal-fired electric utility steam generating unit cap:

(A) New coal-fired electric utility steam generating units, in aggregate, shall emit no more than:

(i) 25 pounds of mercury in any calendar year in which the existing coal-fired electric utility steam generating unit in Boardman is operated.

(ii) 60 pounds of mercury in any calendar year in which the existing coal-fired electric utility steam generating unit in Boardman is not operated.

(B) The owner or operator of each new coal-fired electric utility steam generating unit must submit to DEQ a request, in a format specified by DEQ, to receive a portion of the new coal-fired electric utility steam generating unit cap. The request may not be submitted until the new coal-fired electric utility steam generating unit has received its Site Certification from the Facility Siting Council, or if the new coal-fired electric utility steam generating unit is not required to obtain a Site Certificate, all governmental approvals necessary to commence construction.

(C) DEQ will allocate the new coal-fired electric utility steam generating unit cap in order of receipt of requests and, once allocated, the new coal-fired electric utility steam generating unit shall be entitled to receive an equal allocation in future years unless the new coal-fired electric utility steam generating unit permanently ceases operations.

(D) Each individual new coal-fired electric utility steam generating unit shall emit no more than the lesser of:

(i) An amount of mercury determined by multiplying the design heat input in TBtu of such coal-fired electric utility steam generating unit by 0.60 pounds per TBtu rounded to the nearest pound as appropriate, or

(ii) The amount of the emission cap under (6)(b) less the amount of the emission cap under (6)(b) that has been allocated to other new coal-fired electric utility steam generating units.

(c) Compliance demonstration. Each coal-fired electric utility steam generating unit must demonstrate compliance with the applicable calendar year emission cap in subsection (6)(a) or (6)(b) of this rule using a mercury CEMS or sorbent trap monitoring system.

Stat. Auth.: ORS 468.020 & 468A.310
Stats. Implemented: ORS 468A.025
Hist.: DEQ 13-2006, f. & cert. ef. 12-22-06; DEQ 15-2008, f. & cert. ef 12-31-08; DEQ 3-2009, f. & cert. ef. 6-30-09; DEQ 8-2009, f. & cert. ef. 12-16-09; DEQ 4-2013, f. & cert. ef. 3-27-13

Monitoring Requirements

340-228-0609

General Requirements

The owners and operators of a coal-fired electric utility steam generating unit must comply with the monitoring requirements as provided in this rule, 40 CFR part 63 subpart UUUUU, and OAR 340-228-0639 (if applicable).

(1) Requirements for installation, certification, and data accounting. The owner or operator of each coal-fired electric utility steam generating unit must:

(a) Install all applicable monitoring systems required under this rule, 40 CFR part 63 subpart UUUUU, and OAR 340-228-0639 for monitoring Hg mass emissions, inlet Hg (if applicable), and individual unit heat input.

(b) Successfully complete all certification tests required under 40 CFR part 63 subpart UUUUU and meet all other requirements of this rule, 40 CFR part 63 subpart UUUUU, and OAR 340-228-0639 applicable to the monitoring systems under subsection (1)(a) of this rule.

(c) Record, report, and quality-assure the data from the monitoring systems under subsection (1)(a) of this rule.

(2) Compliance deadlines. The owner or operator must meet the monitoring system certification and other requirements of section (1) of this rule on or before the following dates. The owner or operator must record, report, and quality-assure the data from the monitoring systems under subsection (1)(a) of this rule on and after the following dates.

(a) Outlet Hg.

(A) For the owner or operator of a coal-fired electric utility steam generating unit that commences commercial operation before July 1, 2008, by January 1, 2009.

(B) For the owner or operator of a coal-fired electric utility steam generating unit that commences commercial operation on or after July 1, 2008, by the later of the following dates:

(i) January 1, 2009; or

(ii) 90 unit operating days or 180 calendar days, whichever occurs first, after the date on which the unit commences commercial operation.

(C) For the owner or operator of a coal-fired electric utility steam generating unit for which construction of a new stack or flue or installation of add-on Hg emission controls, a flue gas desulfurization system, a selective catalytic reduction system, or a compact hybrid particulate collector system is completed after the applicable deadline under paragraph (2)(a)(A) or (B) of this rule, by 90 unit operating days or 180 calendar days, whichever occurs first, after the date on which emissions first exit to the atmosphere through the new stack or flue, add-on Hg emissions controls, flue gas desulfurization system, selective catalytic reduction system, or compact hybrid particulate collector system.

(b) Heat input. For monitoring systems used to monitor heat input in accordance with OAR 340-228-0606(4)(a), if applicable, by the later of the following dates:

(A) July 1, 2012 or the date established under OAR 340-228-0606(3); or

(B) The date on which the unit commences commercial operation.

(c) Inlet Hg. If required to perform coal sampling and analysis in accordance with OAR 340-228-0606(4)(b)(A)(i) or measure Hg emission prior to any control device(s) in accordance with 340-228-0606(4)(b)(A)(ii), if applicable, by the later of the following dates:

(A) July 1, 2012 or the date established under OAR 340-228-0606(3); or

(B) The date on which the unit commences commercial operation.

(3) Reporting data.

(a) Except as provided in subsection (3)(b) of this rule, the owner or operator of a coal-fired electric utility steam generating unit that does not meet the applicable compliance date set forth in section (2) of this rule for any monitoring system under subsection (1)(a) of this rule must, for each monitoring system, determine, record, and report maximum potential (or, as appropriate, minimum potential) values for Hg concentration, stack gas flow rate, stack gas moisture content, and any other parameters required to determine Hg mass emissions and heat input in accordance with OAR 340-228-0637(5).

(b) The owner or operator of a coal-fired electric utility steam generating unit that does not meet the applicable compliance date set forth in paragraph (2)(a)(C) of this rule for any monitoring system under subsection (1)(a) must, for each such monitoring system, determine, record, and report substitute data using the applicable missing data procedures in 40 CFR part 75 subpart D, in lieu of the maximum potential (or, as appropriate, minimum potential) values, for a parameter if the owner or operator demonstrates that there is continuity between the data streams for that parameter before and after the construction or installation under subsection (2)(a)(C) of this rule.

Stat. Auth.: ORS 468.020 & 468A.310
Stats. Implemented: ORS 468A.025
Hist.: DEQ 15-2008, f. & cert. ef 12-31-08; DEQ 4-2013, f. & cert. ef. 3-27-13

Recordkeeping and Reporting

340-228-0635

Recordkeeping

The owner or operator of any coal-fired electric utility steam generating unit must maintain a file of all measurements, data, reports, and other information required in OAR 340-228-0606, 0609, 0637 and 0639 and 40 CFR part 63 subpart UUUUU at the source in a form suitable for inspection for at least 5 years from the date of each record.

Stat. Auth.: ORS 468.020 & 468A.310
Stats. Implemented: ORS 468A.025
Hist.: DEQ 15-2008, f. & cert. ef 12-31-08; DEQ 4-2013, f. & cert. ef. 3-27-13

340-228-0637

Reporting

(1) General reporting provisions. The owner or operator of an affected unit must comply with all reporting requirements in this rule and 40 CFR part 63 subpart UUUUU.

(2) Monitoring plans. The owner or operator of a coal-fired electric utility steam generating unit must prepare, and submit if requested, a monitoring plan in accordance with 40 CFR part 63 subpart UUUUU.

(3) Semiannual compliance reports. The owner or operator must submit semiannual compliance reports in accordance to 40 CFR 63.10031(a) through (e). The first semiannual report must be submitted beginning with the calendar half containing the compliance date in OAR 340-228-0609(2). The owner or operator must also report the pounds of Hg emitted and heat input (if applicable) during the calendar half and year-to-date.

Stat. Auth.: ORS 468.020 & 468A.310
Stats. Implemented: ORS 468A.025
Hist.: DEQ 15-2008, f. & cert. ef 12-31-08; DEQ 4-2013, f. & cert. ef. 3-27-13

340-228-0639

Fuel Analyses and Procedures

(1) The owner or operator must conduct fuel analyses according to the procedures in sections (2) through (5) of this rule and Table 4 to this division, as applicable.

(2) The owner or operator must develop and submit a site-specific fuel analysis plan to the Department for review and approval according to the following procedures and requirements in subsections (2)(a) and (b) of this rule.

(a) The owner or operator must submit the fuel analysis plan no later than 60 days before the date that the owner or operator intends to demonstrate compliance.

(b) The owner or operator must include the information contained in paragraphs (2)(b)(A) through (F) of this rule in the fuel analysis plan.

(A) The identification of all fuel types anticipated to be burned in each boiler or process heater.

(B) For each fuel type, the notification of whether the owner or operator or a fuel supplier will be conducting the fuel analysis.

(C) For each fuel type, a detailed description of the sample location and specific procedures to be used for collecting and preparing the composite samples if the procedures are different from section (3) or (4) of this rule. Samples should be collected at a location that most accurately represents the fuel type, where possible, at a point prior to mixing with other dissimilar fuel types.

(D) For each fuel type, the analytical methods, with the expected minimum detection levels, to be used for the measurement of selected total metals, chlorine, or mercury.

(E) If requesting to use an alternative analytical method other than those required by Table 4 to this division, the owner or operator must also include a detailed description of the methods and procedures that will be used.

(F) If using fuel analysis from a fuel supplier in lieu of site-specific sampling and analysis, the fuel supplier must use the analytical methods required by Table 4 to this division.

(3) At a minimum, the owner or operator must obtain three composite fuel samples for each fuel type according to the procedures in subsection (3)(a) or (b) of this rule.

(a) If sampling from a belt (or screw) feeder, collect fuel samples according to paragraphs (3)(a)(A) and (B) of this rule.

(A) Stop the belt and withdraw a 6-inch wide sample from the full cross-section of the stopped belt to obtain a minimum two pounds of sample. Collect all the material (fines and coarse) in the full cross-section. Transfer the sample to a clean plastic bag.

(B) Each composite sample will consist of a minimum of three samples collected at approximately equal intervals during the testing period.

(b) If sampling from a fuel pile or truck, collect fuel samples according to paragraphs (3)(b)(A) through (C) of this rule.

(A) For each composite sample, select a minimum of five sampling locations uniformly spaced over the surface of the pile.

(B) At each sampling site, dig into the pile to a depth of 18 inches. Insert a clean flat square shovel into the hole and withdraw a sample, making sure that large pieces do not fall off during sampling.

(C) Transfer all samples to a clean plastic bag for further processing.

(4) Prepare each composite sample according to the procedures in subsections (4)(a) through (f) of this rule.

(a) Thoroughly mix and pour the entire composite sample over a clean plastic sheet.

(b) Break sample pieces larger than 3 inches into smaller sizes.

(c) Make a pie shape with the entire composite sample and subdivide it into four equal parts.

(d) Separate one of the quarter samples as the first subset.

(e) Grind the sample in a mill.

(f) If the subset is too large for grinding, repeat the procedures in subsection (4)(c) of this rule to obtain a one-quarter subsample for analysis. If the quarter sample is too large, subdivide it further using the same procedure.

(5) Determine the concentration of pollutants in the fuel (mercury, chlorine, and/or total selected metals) in units of pounds per million Btu of each composite sample for each fuel type according to the procedures in Table 6 to this subpart.

[ED. NOTE: Tables referenced are not included in rule text. Click here for PDF copy of table(s).]

Stat. Auth.: ORS 468.020 & 468A.310
Stats. Implemented: ORS 468A.025
Hist.: DEQ 8-2009, f. & cert. ef. 12-16-09

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