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DEPARTMENT OF ENVIRONMENTAL QUALITY

 

DIVISION 228

REQUIREMENTS FOR FUEL BURNING EQUIPMENT AND FUEL SULFUR CONTENT

340-228-0010

Applicability

This division applies in all areas of the state.

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 & ORS 468A
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

340-228-0020

Definitions

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

(1) "ASTM" means the American Society for Testing and Materials.

(2) "Coastal Areas" means Clatsop, Tillamook, Lincoln, Coos, and Curry Counties and those portions of Douglas and Lane County west of Range 8 West, Willamette Meridian.

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

(4) "Fuel burning equipment" means equipment, other than internal combustion engines, the principal purpose of which is to produce heat or power by indirect heat transfer.

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

(6) "Standard conditions" means a temperature of 68° Fahrenheit and a pressure of 14.7 pounds per square inch absolute.

(7) "Standard cubic foot" means the amount of gas that would occupy a volume of one cubic foot, if the gas were free of uncombined water at standard conditions. When applied to combustion flue gases from fuel or refuse burning, "standard cubic foot" also implies adjustment of gas volume to that which would result at a concentration of 12% carbon dioxide or 50% excess air.

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.

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

Stat. Auth.: ORS 468 & 468A
Stats. Implemented: ORS 468.020,468A.025 & 468A.035
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

Sulfur Content of Fuels

340-228-0100

Residual Fuel Oils

No person shall 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 & ORS 468A
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

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 as adopted by the Environmental Quality Commission under OAR 340-200-0040.]

Stat. Auth.: ORS 468 & ORS 468A
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

340-228-0120

Coal

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

(2) Except as provided for in sections (4) and (5) of this rule, no person shall 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 shall keep records for a five year period which shall 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.

(4) Users of coal for direct residential space heating in 1980 who apply in writing by July 1, 1983 and receive written approval from the Department shall be exempted from the requirement of section (2) of this rule provided they certify that they used more than one-half ton of coal in 1980.

(5) Distributors may sell coal not meeting specification in section (2) of this rule to those users who have applied for and received the exemption provided for in section (4) of this rule.

[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.]

[Publications: The publication(s) referred to or incorporated by reference in this rule are available from the agency.]

Stat. Auth.: ORS 468 & ORS 468A
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

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 the Department of Environmental Quality, 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 as adopted by the Environmental Quality Commission under OAR 340-200-0040.]

Stat. Auth.: ORS 468 & ORS 468A
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

General Emission Standards for Fuel Burning Equipment

340-228-0200

Sulfur Dioxide Standards

The following emission standards are applicable to sources installed, constructed, or modified after January 1, 1972 only:

(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 lb. per million BTU heat input, maximum three-hour average, when liquid fuel is burned;

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

(b) 1.2 lb. 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 as adopted by the Environmental Quality Commission under OAR 340-200-0040.

Stat. Auth.: ORS 468 & 468A
Stats. Implemented: ORS 468.020,468A.025, 468A.035 & 468A.055
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

340-228-0210

Grain Loading Standards

(1) Except as provided in sections (2) and (3) of this rule, no person shall cause, suffer, allow, or permit the emission of particulate matter, from any fuel burning equipment in excess of:

(a) 0.2 grains per standard cubic foot for sources installed, constructed, or modified on or before June 1, 1970;

(b) 0.1 grains per standard cubic foot for sources installed, constructed, or modified after June 1, 1970.

(2) For sources burning salt laden wood waste on July 1, 1981, where salt in the fuel is the only reason for failure to comply with the above limits and when the salt in the fuel results from storage or transportation of logs in salt water, the resulting salt portion of the emissions shall be exempted from subsection (1)(a) or (b) of this rule and OAR 340-208-0110. In no case shall sources burning salt laden woodwaste exceed 0.6 grains per standard cubic foot.

(a) This exemption and the alternative emissions standard are only applicable upon prior notice to the Department.

(b) Sources which utilize this exemption, to demonstrate compliance otherwise with subsection (1)(a) or (b) of this rule, shall submit the results of a particulate emissions source test of the boiler stacks bi-annually.

(3) This rule does not apply to solid fuel burning devices that have been certified under OAR 340-262-0500.

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 & 468A
Stats. Implemented: ORS 468.020,468A.025 & 468A.035
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

Federal Acid Rain Program

340-228-0300

Federal Regulations Adopted by Reference

(1) 40 CFR Parts 72, 75, and 76 (July 2, 2010) 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 Clean Air Act. The term "permitting authority" means the Oregon Department of Environmental Quality and the term "Administrator" shall mean the Administrator of the United States Environmental Protection Agency.

(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 shall apply and take precedence.

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

Stat. Auth.: ORS 468.020 & 468.310(2)
Stats. Implemented: ORS 468A.025
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

340-228-0400

Purpose

(1) OAR 340-228-0400 through 340-228-0530 implement the Western Backstop (WEB) Sulfur Dioxide (SO2) Trading Program provisions in accordance with the federal Regional Haze Rule, 40 CFR 51.309 (2003), and Section 5.5.2.3 of the State Implementation Plan, titled "Sulfur Dioxide Milestones and Backstop Trading Program," incorporated under 340-200-0040.

(2) Nothing in OAR 340-228-0400 through 340-228-0530 waives any requirement otherwise in effect or subsequently required under another program, including Rules governing new sources.

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

Stat. Auth.: ORS 468.020
Stats. Implemented: ORS 468A.035
Hist.: DEQ 19-2003, f. & cert. ef. 12-12-03

340-228-0410

Definitions

The definitions in OAR 340-200-0020 and this rule apply to 340-228-0400 through 340-228-0530. If the same term is defined in this rule and 340-200-0020, the definition in this rule applies to 340-228-0400 through 340-228-0530.

(1) "Account Certificate of Representation" means the completed and signed submission required to designate an Account Representative for a WEB source or an Account Representative for a general account.

(2) "Account Representative" means the individual who is authorized through an Account Certificate of Representation to represent owners and operators of the WEB source with regard to matters under the WEB Trading Program or, for a general account, who is authorized through an Account Certificate of Representation to represent the persons having an ownership interest in allowances in the general account with regard to matters concerning the general account.

(3) "Actual Emissions" means total annual SO2 emissions determined in accordance with OAR 340-228-0480, or determined in accordance with SO2 emission inventory requirements of 340-214-0400 through 340-214-0430 for sources that are not subject to 340-228-0480.

(4) "Allocate" means to assign allowances to a WEB source through State Implementation Plan section 5.5.2.3.3.a.

(5) "Allowance" means the limited authorization under the WEB Trading Program to emit one ton of SO2 during a specified control period or any control period thereafter subject to the terms and conditions for use of unused allowances as established by OAR 340-228-0400 through 340-228-0530.

(6) "Allowance Limitation" means the tonnage of SO2 emissions authorized by the allowances available for compliance deduction for a WEB source for a control period under OAR 340-228-0510(1) on the allowance transfer deadline for that control period.

(7) "Allowance Tracking System" means the system where allowances under the WEB Trading Program are recorded, held, transferred, and deducted.

(8) "Allowance Tracking System account" means an account in the Allowance Tracking System established for purposes of recording, holding, transferring, and deducting allowances.

(9) "Allowance transfer deadline" means the deadline established in OAR 340-228-0490(2) when allowances must be submitted for recording in a WEB source's compliance account in order to demonstrate compliance for that control period.

(10) "Compliance account" means an account established in the Allowance Tracking System under OAR 340-228-0470(1) for the purpose of recording allowances that a WEB source might hold to demonstrate compliance with its allowance limitation.

(11) "Compliance certification" means a submission to the Department by the Account Representative as required under OAR 340-228-0510(2) to report a WEB source's compliance or noncompliance with this rule.

(12) "Control period" means the period beginning January 1 of each year and ending on December 31 of the same year, inclusive.

(13) "Emission unit" means any part of a stationary source that emits or would have the potential to emit any pollutant submitted to regulations under the Clean Air Act.

(14) "Emissions tracking database" means the central database where SO2 emissions for WEB sources as recorded and reported in accordance with OAR 340-228-0400 through 340-228-0530 are tracked to determine compliance with allowance limitations.

(15) "Existing source" means a stationary source that commenced operation before the Program Trigger Date.

(16) "Fugitive emissions" are those emissions that could not reasonably pass through a stack, chimney, vent, or other functionally equivalent opening.

(17) "General account" means an account established in the Allowance Tracking System under OAR 340-228-0470 for the purpose of recording allowances held by a person that are not to be used to show compliance with an allowance limitation.

(18) "Milestone" means the maximum level of stationary source regional sulfur dioxide emissions for each year from 2003 to 2018, established according to the procedures in State Implementation Plan Section 5.5.2.3.1.

(19) "New WEB Source" means a WEB source that commenced operation on or after the Program Trigger Date.

(20) "New Source Set-aside" means a pool of allowances that are available for allocation to new sources in accordance with the provisions of State Implementation Plan Section 5.5.2.3.3.a(2).

(21) "Owner or operator" means any person who is an owner or who operates, controls or supervises a WEB source and includes but is not be limited to any holding company, utility system, or plant manager.

(22) "Potential to emit" means the maximum capacity of a stationary source to emit any air pollutant under its physical and operational design. Any physical or operational limitation on the capacity of a source to emit an air pollutant, including air pollution control equipment and restrictions on hours of operation or on the type or amount of material combusted, stored or processed, will be treated as part of its design if the limitation is enforceable by the EPA Administrator.

(23) "Program trigger date" means the date that the Department determines that the WEB Trading Program has been triggered in accordance with the State Implementation Plan Section 5.5.2.3.1(1)(b).

(24) "Program trigger years" means the years shown in Table 5.5.2-4, column 3, of the State Implementation Plan for the applicable milestone if the WEB Trading Program is triggered as described in State Implementation Plan Section 5.5.2.3.1 c.

(25) "Renewable Energy Resource" means a resource that generates electricity by non-nuclear and non-fossil technologies that results in low or no air emissions. The term includes electricity generated by wind energy technologies; solar photovoltaic and solar thermal technologies; geothermal technologies; technologies based on landfill gas and biomass sources; waste-to-energy facilities that meet maximum achievable control technology (MACT) requirements, and new low-impact hydropower that meets the Low-Impact Hydropower Institute criteria. Biomass includes agricultural, food and wood wastes. The term does not include pumped storage, black liquor, or treated wood.

(26) "Retired source" means a WEB source that has received a retired source exemption as provided in OAR 340-228-0430(4).

(27) "Serial number" means, when referring to allowances, the unique identification number assigned to each allowance by the Tracking Systems Administrator, in accordance with OAR 340-228-0460(2).

(28) "SO2 emitting unit" means any equipment that is located at a WEB source and that emits SO2.

(29) "Stationary source" means any building, structure, facility or installation that emits or may emit any air pollutant subject to regulation under the Clean Air Act.

(30) "Submit" means to send to the appropriate authority under the signature of the Account Representative. For purposes of determining when something is submitted, an official U.S. Postal Service postmark or equivalent electronic time stamp will establish the date of submittal.

(31) "Ton" means 2000 pounds. For any control period, any fraction of a ton equaling 1000 pounds or more will be treated as one ton, and any fraction of a ton equaling less than 1000 pounds will be treated as zero tons.

(32) "Tracking System Administrator" means the person designated by the Department as the administrator of the Allowance Tracking System and the emission tracking database.

(33) "WEB source" means a stationary source that meets the applicability requirements of OAR 340-228-0430.

(34) "Web Trading Program" means OAR 340-228-0400 through 340-228-0530, the Western Backstop SO2 Trading Program, triggered as a backstop in accordance with the provisions in the SO2 Milestones and Backstop Trading Program Implementation Plan, if necessary, to ensure that regional SO2 emissions are reduced.

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

Stat. Auth.: ORS 468.020
Stats. Implemented: ORS 468A.035
Hist.: DEQ 19-2003, f. & cert. ef. 12-12-03

340-228-0420

WEB Trading Program Trigger

(1) OAR 340-228-0400 through 340-228-0530 becomes effective on the program trigger date established by the procedures outlined in the SO2 Milestones and Backstop Trading Program Implementation Plan.

(2) Exception. Special Penalty Provisions for Year 2018, OAR 340-228-0520 becomes effective on January 1, 2018 and remains effective until the requirements of 340-228-0520 have been met.

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

Stat. Auth.: ORS 468.020
Stats. Implemented: ORS 468A.035
Hist.: DEQ 19-2003, f. & cert. ef. 12-12-03

340-228-0430

WEB Trading Program Applicability

(1) General Applicability. Except as provided in section (2) of this rule, OAR 340-228-0400 through 340-228-0530 apply to any stationary source or group of stationary sources that are located on one or more contiguous or adjacent properties and that are under the control of the same person or persons under common control, belong to the same industrial grouping, and are described in subsections (a) through (c) of this section. A stationary source or group of stationary sources is considered part of a single industrial grouping if all of the pollutant emitting activities at such source or group of sources on contiguous or adjacent properties belong to the same Major Group (i.e., all have the same two-digit code) as described in the Standard Industrial Classification Manual, 1987.

(a) All BART-eligible sources as defined in 40 CFR 51.301 (2003) that are BART-eligible due to SO2 emissions.

(b) All stationary sources not meeting the criteria of subsection (a) of this rule that have actual SO2 emissions of 100 tons or more per year in the program trigger years or any subsequent year. The fugitive emissions of a stationary source are not considered in determining whether the source is subject to OAR 340-228-0400 through 340-228-0530 unless the source belongs to one of the following categories of stationary source:

(i) Coal cleaning plants (with thermal dryers);

(ii) Kraft pulp mills;

(iii) Portland cement plants;

(iv) Primary zinc smelters;

(v) Iron and steel mills;

(vi) Primary aluminum ore reduction plants;

(vii) Primary copper smelters;

(viii) Municipal incinerators capable of charging more than 250 tons of refuse per day;

(ix) Hydrofluoric, sulfuric, or nitric acid plants;

(x) Petroleum refineries;

(xi) Lime plants;

(xii) Phosphate rock processing plants;

(xiii) Coke oven batteries;

(xiv) Sulfur recovery plants;

(xv) Carbon black plants (furnace process);

(xvi) Primary lead smelters;

(xvii) Fuel conversion plants;

(xviii) Sintering plants;

(xix) Secondary metal production plants;

(xx) Chemical process plants;

(xxi) Fossil-fuel boilers (or combination thereof) totaling more than 250 million British thermal units per hour heat input;

(xxii) Petroleum storage and transfer units with a total storage capacity exceeding 300,000 barrels;

(xxiii) Taconite ore processing plants;

(xxiv) Glass fiber processing plants;

(xxv) Charcoal production plants;

(xxvi) Fossil-fuel-fired steam electric plants of more than 250 million British thermal units per hour heat input; or

(xxvii) Any other stationary source category, that is being regulated under Section 111 or 112 of the Act as of August 7, 1980.

(c) A new source that begins operation after the program trigger date and has the potential to emit 100 tons or more of SO2 per year.

(2) The Department may determine on a case-by-case basis, with concurrence from the EPA Administrator, that a source is not a WEB source if the source:

(a) had actual sulfur dioxide emissions of 100 tons or more in a single year and in each of the previous five years had actual SO2 emissions of less than 100 tons per year, and

(A)(i) the emissions increase that was caused by a sudden, infrequent, and not reasonably preventable failure of air pollution control equipment, process equipment, or a process to operate in a normal or usual manner and that the source took timely and reasonable action to minimize the temporary emission increase. A temporary emission increase due to poor maintenance or careless operation does not meet the criteria of this section; and

(ii) has corrected the failure of air pollution control equipment, process equipment, or process by the time of the Department's determination under this section; or

(B) had to switch fuels or feedstocks on a temporary basis as a result of an emergency situation or unique and unusual circumstances besides the cost of such fuels or feedstocks.

(3) Duration of Applicability. Except as provided for in section (4) of this rule, once a source is subject to the WEB Trading Program (OAR 340-228-0400 through 340-228-0530), it is subject to the requirements every year thereafter.

(4) Retired Source Exemption.

(a) Application. Any WEB that is permanently retired must apply for a retired source exemption. The WEB source may only be considered permanently retired if all SO2 emitting units at the source are permanently retired. The application must contain the following information:

(A) Identification of the WEB source, including the plant name and an appropriate identification code in a format specified by the Department.

(B) Name of Account Representative.

(C) Description of the status of the WEB source, including the date that the WEB source was permanently retired.

(D) Signed certification that the WEB source is permanently retired and will comply with the requirements of section (4) of this rule.

(E) Verification that the WEB source has a general account where any unused allowances or future allocations will be recorded.

(b) Notice. The retired source exemption becomes effective when the Department notifies the source that the Department has granted the retired source exemption.

(c) Responsibilities of Retired Sources:

(A) A retired source is exempt from OAR 340-228-0480 and 340-228-0510, except as provided below.

(B) A retired source may not emit any SO2 after the date the Department issues a retired source exemption.

(C) A WEB source must submit SO2 emissions reports, as required by OAR 340-228-0480 for any time period the source was operating before the effective date of the retired source exemption. The retired source is subject to the compliance provisions of OAR 340-228-0510, including the requirement to hold allowances in the source's compliance account to cover all SO2 emissions before the date the source was permanently retired.

(D) A retired source that is still in existence but no longer emitting SO2 must, for a period of five years from the date the records are created, retain records demonstrating the effective date of the retired source exemption for purposes of this rule.

(d) Resumption of Operations.

(A) Before resuming operation, the retired source must submit registration materials as follows:

(i) If the source is required to obtain a new source review permit or operating permit under OAR 340, division 224 or division 218, before resuming operation, then registration information as described in 340-228-0450(1) and a copy of the retired source exemption must be submitted with the application required under OAR 340, division 224 or division 218.

(ii) If the source does not meet the criteria under subparagraph (i) of this rule, then registration information as described in OAR 340-228-0450 and a copy of the retired source exemption must be submitted to the Department at least ninety days before the source resumes operation.

(B) The retired source exemption automatically expires on the day the source resumes operation.

(e) Loss of Future Allowances. A WEB source that is permanently retired and that does not apply to the Department for a retired source exemption within ninety days of the date that the source is permanently retired forfeits any unused and future allowances. The Tracking System Administrator must retire the abandoned allowances.

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

Stat. Auth.: ORS 468.020
Stats. Implemented: ORS 468A.035
Hist.: DEQ 19-2003, f. & cert. ef. 12-12-03

340-228-0440

Account Representative for WEB Sources

(1) Each WEB source must identify one Account Representative and may also identify an alternate Account Representative who may act on behalf of the Account Representative. Any representation, action, inaction, or submission by the alternate Account Representative will be deemed to be a representation, action, inaction, or submission by the Account Representative.

(2) Identification and Certification of an Account Representative.

(a) The Account Representative and any Alternate Account Representative must be appointed by an agreement that makes the representations, actions, inactions, or submissions of the Account Representative and any alternate binding on the owners and operators of the WEB source.

(b) The Account Representative must submit to the Department and the Tracking System Administrator a signed and dated Account Certificate of Representation (Certificate) that contains the following elements:

(A) Identification of the WEB source by plant name, state and an appropriate identification code in a format specified by the Department;

(B) The name, address, e-mail (if available), telephone, and facsimile number of the Account Representative and any alternate;

(C) A list of owners and operators of the WEB source;

(D) Information to be part of the emission tracking system database in accordance with the State Implementation Plan. The Department will specify specific data elements that are consistent with the data system structure, including basic facility information that appears in other reports and notices submitted by the WEB source, such as county location, industrial classification codes, and similar general facility information.

(E) The following certification statement: "I certify that I was selected as the Account Representative or alternate Account Representative, as applicable, by an agreement binding on the owners and operators of the WEB source. I certify that I have all the necessary authority to carry out my duties and responsibilities under the WEB Trading Program on behalf of the owners and operators of the WEB source, and that each such owner and operator will be fully bound by my representations, actions, inactions, or submissions and by any decision or order issued to me by the Department regarding the WEB Trading Program."

(c) Once the Department receives the complete Certificate, the Account Representative and any alternate Account Representative represents and, by his or her representations, actions, inactions, or submissions, legally binds each owner and operator of the WEB source in all matters pertaining to the WEB Trading Program. Any order issued by the Department regarding the WEB Trading Program is binding on the owners and operators, subject to the provisions of ORS Chapter 183.

(d) No WEB Allowance Tracking System account may be established for the WEB source until the Tracking System Administrator has received a complete Certificate. Once the account is established, the Account Representative must make all submissions concerning the account, including the deduction or transfer of allowances.

(3) Requirements and Responsibilities.

(a) The Account Representative's responsibilities include, but are not limited to, transferring allowances; submitting monitoring plans, registrations, certification applications, SO2 emissions data, and compliance reports as required by OAR 340-228-0400 through 340-228-0530; and representing the source in all matters pertaining to the WEB Trading Program.

(b) Each submission under this program must be signed and certified by the Account Representative for the WEB source. Each submission must include the following truth and accuracy certification statement by the Account Representative: "I am authorized to make this submission on behalf of the owners and operators of the WEB source for which the submission is made. I certify under penalty of law that I have personally examined and am familiar with the statements and information submitted in this document and all its attachments. Based on my inquiry of those individuals with primary responsibility for obtaining the information, I certify that the statements and information are to the best of my knowledge and belief true, accurate, and complete. I am aware that there are significant penalties for submitting false statements and information or omitting required statements and information, including the possibility of fine or imprisonment."

(4) Changing the Account Representative or Owners and Operators.

(a) Changing the Account Representative or the Alternate Account Representative. The Account Representative or alternate Account Representative may be changed at any time by sending a complete superseding Certificate to the Department and the Tracking System Administrator under OAR 340-228-0440(2)(b). The change will be effective when the Tracking System Administrator receives it. Notwithstanding any such change, all representations, actions, inactions, and submissions by the previous Account Representative or alternate before the Tracking System Administrator receives the superseding Certificate are binding on the new Account Representative and the owners and operators of the WEB source.

(b) Changes in Owners and Operators.

(A) Within thirty days of any change in the owners and operators of the WEB source, including the addition of a new owner or operator, the Account Representative must submit a revised Certificate amending the list of owners and operators to include such change.

(B) If a new owner or operator of a WEB source is not included in the list of owners and operators submitted in the Certificate, such new owner or operator is subject to and bound by the Certificate, the representations, actions, inactions, and submissions of the Account Representative of the WEB source, and the decisions, orders, actions, and inactions of the Department as if the new owner or operator were included in the list.

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

Stat. Auth.: ORS 468.020
Stats. Implemented: ORS 468A.035
Hist.: DEQ 19-2003, f. & cert. ef. 12-12-03

340-228-0450

Registration

(1) Deadlines.

(a) Each source that is a WEB source on or before the Program Trigger Date must register by submitting the initial Certificate required in OAR 340-228-0440(2) to the Department no later than 180 days after the program trigger date.

(b) Any existing source that becomes a WEB source after the program trigger date must register by submitting the initial Certificate required in OAR 340-228-0440(2) to the Department no later than September 30 of the year following the inventory year in which the source exceeded the emission threshold.

(c) Any new WEB source must register by submitting the initial Certificate required in OAR 340-228-0440(2) to the Department before commencing operation.

(2) Any allocation, transfer or deduction of allowance to or from the compliance account of a WEB source does not require revision of the WEB source's operating permit.

(3) Whether or not a WEB source is not required to have a permit under OAR 340-218 or 340-224 at any time after this Rule is effective, it must at all times possess a permit that includes the requirements of 340-228-0400 through 340-228-0530. If it does not possess a Title V permit under this rule, it must satisfy this paragraph's requirements by obtaining or modifying a permit under OAR 340, division 216, to incorporate the requirements of 340-228-0400 through 340-228-0530. The source must at all times possess a permit that includes these requirements.

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

Stat. Auth.: ORS 468.020
Stats. Implemented: ORS 468A.035
Hist.: DEQ 19-2003, f. & cert. ef. 12-12-03

340-228-0460

Allowance Allocations

(1) The Tracking System Administrator must record the allowances for each WEB source in the compliance account for a WEB source after the Department allocates the allowances under Section 5.5.2.3.3(a) of the State Implementation Plan. If applicable, the Tracking System Administrator must record a portion of the SO2 allowances for a WEB source in a WEB source's special reserve compliance account assigned to the Department to account for any allowances to be held by the Department in accordance with OAR 340-228-0480(1)(b).

(2) The Tracking System Administrator must assign a serial number to each allowance in accordance with State Implementation Plan Section 5.5.2.3.3(f).

(3) All allowances must be allocated, recorded, transferred, or used as whole allowances. To determine the number of whole allowances, the number of allowances must be rounded down for decimals less than 0.50 and rounded up for decimals of 0.50 or greater.

(4) An allowance is not a property right. It is a limited authorization to emit one ton of SO2 for the purpose of meeting the requirements of this Rule. No provision of this WEB Trading Program or other law should be construed to limit the authority of the United States or the Department to terminate or limit such authorization.

(5) Early Reduction Bonus Allocation. Any WEB source that reduces its permitted annual SO2 emissions to a level that is below the floor level allocation established for that source in State Implementation Plan Section 5.5.2.3.3.a between 2003 and the program trigger year may apply to the Department for an early reduction bonus allocation. The application must be submitted no later than ninety days after the Program Trigger Date. Any WEB source that applies and receives early reduction bonus allocations must retain the records referenced below for a minimum of five years after the early reduction bonus allowance is certified in accordance with Section 5.5.2.3.3(a)(c) of the State Implementation Plan. The application for an early reduction bonus allocation must contain the following information:

(a) Copies of all permits or other enforceable documents that include annual SO2 emissions limits for the WEB source during the period the WEB source was generating the early reductions. Such permits or enforceable documents require monitoring for SO2 emissions that meets the requirements in OAR 340-228-0480(1)(a) and 340-228-0480(1)(c).

(b) Copies of emissions monitoring reports for the period the WEB source was generating the early reductions that document the actual annual SO2 emissions and demonstrates that the actual annual SO2 emissions were below the floor level allocation established for that source in Section 5.5.2.3.3.a of the State Implementation Plan.

(c) Demonstration that the floor level established for the source in accordance with Section 5.5.2.3.3.a of the State Implementation Plan was calculated using data that are consistent with the new monitoring methodology. If new monitoring techniques will change the floor level for the source, then a demonstration of the new floor level based on new monitoring techniques must be included in the application.

(6) Request for allowances for new WEB sources or modified WEB Sources.

(a) A new WEB source or an existing WEB source that has increased production capacity through a permitted change in operations OAR 340, division 224 may apply to the Department for an allocation from the new source set-aside, as outlined in Section 5.5.2.3.3.c. of the State Implementation Plan.

(A) A new WEB source is eligible to apply for an annual allocation equal to the permitted annual SO2 emission limit for that source after the source has commenced operation.

(B) An existing WEB source is eligible to apply for an annual allocation equal to the permitted annual SO2 emission limit for that source that is attributable to any amount of production capacity that is greater than the permitted production capacity for that source as of January 1, 2003.

(C) A source that has received a retired source exemption under OAR 340-228-0430(4) is not eligible to apply for an allocation from the new source set-aside.

(b) The application for an allocation from the new source set-aside must contain the following information:

(A) for an existing WEB source, documentation of the production capacity before and after the new permit;

(B) for new WEB sources, documentation of the actual date and a copy of the permit.

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

Stat. Auth.: ORS 468.020
Stats. Implemented: ORS 468A.035
Hist.: DEQ 19-2003, f. & cert. ef. 12-12-03

340-228-0470

Establishment of Accounts

(1) Allowance Tracking System Accounts. All WEB sources must open a compliance account. Any person may open a general account for the purpose of holding and transferring allowances. In addition, if a WEB source conducts monitoring under OAR 340-228-480(1)(b), the WEB source must open a special reserve compliance account for allowances associated with units monitored under those provisions. Allowances may not be transferred out of the special reserve account by the WEB source or account representative. The Department shall allocate allowances to the account in accordance with 340-228-0480(1)(b)(E) and all such allowances for each control period shall be retired each year for compliance in accordance with 340-228-0510. To open either type of account, an application that contains the following information must be submitted to the TSA.

(a) The Account Representative's name, mailing address, e-mail address, telephone number, and facsimile number. For a compliance account, include a copy of the Account Certificate of Representation of the Account Representative and any alternate as required in OAR 340-228-0440(2)(b). For a general account, include the Account Certificate of Representation of the Account Representative and any alternate as required in OAR 340-228-0470(3)(b).

(b) The WEB source or organization name;

(c) The type of account to be opened; and

(d) A signed certification of truth and accuracy by the Account Representative according to OAR 340-228-0440(3)(b) for compliance accounts and certification of truth and accuracy by the Account Representative according to 340-228-0470(4) for general accounts.

(2) Account Representative for General Accounts. For a general account, one Account Representative must be identified and an alternate Account Representative may be identified and may act on behalf of the Account Representative. Any representation, action, inaction, or submission by the alternate Account Representative is a representation, action, inaction, or submission by the Account Representative.

(3) Identification and Certification of an Account Representative for General Accounts.

(a) The Account Representative must be appointed by an agreement that makes the representations, actions, inactions, or submissions of the Account Representative binding on all persons who have an ownership interest with respect to allowances held in the general account.

(b) The Account Representative must submit to the Tracking System Administrator a signed and dated Account Certificate of Representation (Certificate) that contains the following elements:

(A) The name, address, e-mail (if available), telephone, and facsimile number of the Account Representative and any alternate;

(B) The organization's name;

(C) The following certification statement: "I certify that I was selected as the Account Representative or alternate Account Representative, as applicable, by an agreement binding on all persons who have an ownership interest in allowances in the general account with regard to matters concerning the general account. I certify that I have all the necessary authority to carry out my duties and responsibilities under the WEB Trading Program on behalf of said persons, and that each such person will be fully bound by my representations, actions, inactions, or submissions and by any decision or order issued to me by the Department regarding the general account."

(c) When the Department receives the complete Certificate, the Account Representative represents and, by his or her representations, actions, inactions, or submissions, legally binds each person who has an ownership interest in allowances held in the general account with regard to all matters concerning the general account. Such persons will be bound by any decision or order issued by the Department.

(d) A WEB Allowance Tracking System general account may not be established until the Tracking System Administrator has received a complete Certificate. Once the account is established, the Account Representative must make all submissions concerning the account, including the deduction or transfer of allowances.

(4) Requirements and Responsibilities for General Accounts. Each submission for the general account must be signed and certified by the Account Representative for the general account. Each submission must include the following truth and accuracy certification statement by the Account Representative: "I am authorized to make this submission on behalf of all person who have an ownership interest in allowances held in the general account. I certify under penalty of law that I have personally examined and am familiar with the statements and information submitted in this document and all its attachments. Based on my inquiry of those individuals with primary responsibility for obtaining the information, I certify that the statements and information are to the best of my knowledge and belief true, accurate, and complete. I am aware that there are significant penalties for submitting false statements and information or omitting required statements and information, including the possibility of fine or imprisonment."

(5) Changing the Account Representative. The Account Representative or alternate Account Representative may be changed at any time by sending a complete superseding Certificate to the Department and the Tracking System Administrator, according to OAR 340-228-0470(3)(b). The change will take effect when the Department receives the Certificate. Notwithstanding any such change, all representations, actions, inactions, and submissions by the previous Account Representative or alternate before the Department receives the superseding Certificate are binding on the new Account Representative and all persons having ownership interest with respect to allowances held in the general account.

(6) Changes to the Account. Any change to the information required in the application for an existing account under OAR 340-228-0470(1) requires a revision of the application.

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

Stat. Auth.: ORS 468.020
Stats. Implemented: ORS 468A.035
Hist.: DEQ 19-2003, f. & cert. ef. 12-12-03

340-228-0480

Monitoring, Recordkeeping and Reporting

(1) General Requirements on Monitoring Methods.

(a) For each SO2 emitting unit at a WEB source the owner or operator must comply with the following, as applicable, to monitor and record SO2 mass emissions:

(A) If a unit is subject to 40 CFR Part 75 (2003) under a requirement separate from the WEB Trading Program, the unit must meet the requirements contained in Part 75 with respect to monitoring, recording and reporting SO2 mass emissions.

(B) If a unit is not subject to 40 CFR Part 75 (2003) under a requirement separate from the WEB Trading Program, a unit must use one of the following monitoring methods, as applicable:

(i) A continuous emission monitoring system (CEMS) for SO2 and flow that complies with all applicable monitoring provisions in 40 CFR Part 75;

(ii) If the unit is a gas- or oil-fired combustion device, the excepted monitoring methodology in Appendix D to 40 CFR Part 75, or, if applicable, the low mass emissions (LME) provisions (with respect to SO2 mass emissions only) of section 75.19 of 40 CFR Part 75; or

(iii) One of the optional WEB protocols, if applicable, in Appendix A to this Rule; or

(iv) A monitoring plan for site-specific monitoring that the source submits for approval by the Department and by the U.S. Environmental Protection Agency in accordance with OAR 340-228-0480(8)(e).

(C) A permanently retired unit is not required to monitor under this rule if such unit was permanently retired and had no emissions for the entire period for which the WEB source implements this paragraph (C) of this rule and the Account Representative certifies in accordance with OAR 340-228-0510(2) that these conditions were met. In the event that a permanently retired unit recommences operation, the WEB source shall meet the requirements of this rule in the same manner as if the unit was a new unit.

(b) Notwithstanding OAR 340-228-0480(1)(a), the owner or operator of a unit that meets one of the conditions of 340-228-0480(1)(b)(A) may elect to have the provisions of this 340-228-0480(1)(b) apply to that unit.

(A) Any of the following units may implement OAR 340-228-0480(1)(b):

(i) Any smelting operation where all of the emissions from the operation are not ducted to a stack; or

(ii) Any flare, except to the extent such flares are used as a fuel gas combustion device at a petroleum refinery.

(iii) Any other type of unit without add-on SO2 control equipment, if no control level was assumed for the WEB source in establishing the floor level (and reducible allocation) provided in Section 5.5.2.3.3.a of the State Implementation Plan.

(B) For each unit covered by OAR 340-228-0480(1)(b), the Account Representative must submit a notice to request that 340-228-0480(1)(b) applies to one or more SO2 emitting units at a WEB source. The notice must be submitted in accordance with the compliance dates specified in 340-228-0480(6)(a) and include the following information (in a format specified by the Department with such additional, related information as may be requested):

(i) A notice of all units at the applicable source, specifying which of the units are covered by OAR 340-228-0480(1)(b);

(ii) Consistent with the emission estimation methodology used to determine the floor level (and reducible allocation) for the source in accordance with State Implementation Plan Section 5.5.2.3.3.a, the portion of the WEB source's overall allowance allocation that is attributable to any unit(s) covered by OAR 340-228-0480(1)(b); and

(iii) An identification of any such units that are permanently retired.

(C) For each new unit at an existing WEB source for which the owner or operator seeks to comply with this OAR 340-228-0480(1)(b) and for which the Account Representative applies for an allocation under the new source set-aside provisions of 340-228-0460(6), the Account Representative must submit a modified notice under 340-228-0480(1)(b)(B) that includes such new SO2 emitting unit(s). The modified notice must be submitted in accordance with the deadlines in 340-228-0480, but no later than the date on which a request is submitted under 340-228-0460(6) for allocations from the set-aside.

(D) The Department will evaluate the information submitted by the WEB source in paragraphs (B) and (C) of this subsection and may issue a notice to the source to exclude any units that do not qualify under OAR 340-228-0480(1)(b) or to adjust the portion of allowances attributable to units that do qualify to be consistent with the emission estimation methodology used to establish the floor level and reducible allocation for the source.

(E) The Department will allocate allowances equal to the adjusted portion of the WEB source's allowances under paragraphs (B), (C), and (D) of this subsection in a special reserve compliance account, provided that no such treatment of the WEB source's allocation will be required for any unit that is permanently retired and had no emissions for the entire period for which the WEB source implements subsection (b) of this rule and the Account Representative certifies in accordance with OAR 340-228-0510 that these conditions were met. In the event that a permanently retired unit recommences operation, the WEB source shall meet the requirements of this 340-228-0480 in the same manner as if the unit was a new unit.

(F) The Account Representative for a WEB source must submit an annual emissions statement for each unit under OAR 340-228-0480(1)(b) pursuant to 340-228-0480(8). The WEB source must maintain operating records sufficient to estimate annual emissions in a manner consistent with the emission estimation methodology used to establish the floor level (and reducible allocation) for the source. In addition, if the estimated emissions from all such units at the WEB source are greater than the allowances for the current control year held in the special reserve account under 340-228-0480(1)(b)(E) for the WEB source, the Account Representative must report the extra amount as part of the annual report for the WEB source under 340-228-0510 and be required to use other allowances in the standard compliance account to account for such emissions, in accordance with 340-228-0510.

(G) The remaining provisions of OAR 340-228-0480 do not apply to units covered by this subsection except where otherwise noted.

(H) A WEB source may modify the monitoring for an SO2 emitting unit by using monitoring under OAR 340-228-0480(1)(a), but any such monitoring change must take effect on January 1 of the next compliance year. In addition, the Account Representative must submit an initial monitoring plan at least 180 days before the date on which the new monitoring will take effect and a detailed monitoring plan in accordance with 340-228-0480(2). The Account Representative must also submit a revised notice under 340-228-0480(1)(b)(B) with the initial monitoring plan.

(c) For any monitoring method that the owner or operator uses under this rule (including OAR 340-228-0480(1)(a)(B)) the owner or operator (and, as applicable, the Account Representative) must install, certify, and operate such monitoring in accordance with this rule and record and report the data from such monitoring as required in this rule. In addition, the owner or operator (and, as applicable, the Account Representative) may not:

(A) Except for an alternative approved by the U.S. EPA Administrator for a WEB source that implements monitoring under OAR 340-228-0480(1)(a)(A), use an alternative monitoring system, alternative reference method, or another alternative for the required monitoring method without having obtained prior written approval in accordance with 340-228-0480(8)(e) (relating to petitions);

(B) Operate an SO2 emitting unit so as to discharge, or allow to be discharged, SO2 emissions to the atmosphere without accounting for these emissions in accordance with the applicable provisions of this rule;

(C) Disrupt the approved monitoring method or any portion thereof and thereby avoid monitoring and recording SO2 mass emissions discharged into the atmosphere, except for periods of recertification or periods when calibration, quality assurance testing, or maintenance is performed in accordance with the applicable provisions of this rule; or

(D) Retire or permanently discontinue use of an approved monitoring method, except under one of the following circumstances:

(i) During a period when the unit is exempt from the requirements of this rule, including retirement of a unit as addressed in OAR 340-228-0480(1)(a)(3);

(ii) The owner or operator is monitoring emissions from the unit with another certified monitoring method approved under this rule for use at the unit that provides data for the same parameter as the retired or discontinued monitoring method; or

(iii) The Account Representative notifies the Department of the date of certification testing of a replacement monitoring system in accordance with this rule, and the owner or operator recertifies thereafter a replacement monitoring system in accordance with the applicable provisions of this rule.

(2) Monitoring Plan.

(a) General Provisions. The owner or operator of an SO2 emitting unit that uses a monitoring method under OAR 340-228-0480(1)(a)(A) must meet the following requirements:

(A) Prepare and submit to the Department an initial monitoring plan for each monitoring method that the owner or operator uses to comply with this rule. In accordance with OAR 340-228-0480(2)(c), the plan must contain sufficient information on the units involved, the applicable method, and the use of data derived from that method to demonstrate that all unit SO2 emissions are monitored and reported. The plan must be submitted in accordance with the compliance deadlines specified in OAR 340-228-0480(6).

(B) Prepare, maintain and submit to the Department a detailed monitoring plan before the first day of certification testing, in accordance with the compliance deadline specified in OAR 340-228-0480(5). The plan must contain the applicable information required by 340-228-0480(2)(d). The Department may require that the monitoring plan (or portions thereof) be submitted electronically. The Department also may require that the plan be submitted on an ongoing basis in electronic format as part of the quarterly report submitted under 340-228-0480(8)(a) of this Rule or resubmitted separately within 30 days after any change is made to the plan in accordance with 340-228-0480(2)(a)(C).

(C) Whenever the owner or operator makes a replacement, modification, or change in one of the systems or methodologies provided for in OAR 340-228-0480(1)(a)(B), including a change in the automated data acquisition and handling system or in the flue gas handling system, that affects information reported in the monitoring plan (e.g., a change to serial number for a component of a monitoring system), then the owner or operator must update the monitoring plan in accordance with the compliance deadline specified in OAR 340-228-0480(5).

(b) The owner or operator of an SO2 emitting unit that uses a method under OAR 340-228-0480(1)(a)(A) (a unit subject to 40 CFR Part 75 (2003) under a program other than this WEB Trading Program) must meet the requirements of 340-228-0480(2)(a)-(f) by preparing, maintaining, and submitting a monitoring plan in accordance with the requirements of 40 CFR Part 75 (2003), provided that the owner or operator also submits the entire monitoring plan to the Department upon request.

(c) Initial Monitoring Plan. The Account Representative must submit an initial monitoring plan for each SO2 emitting unit (or group of units sharing a common methodology) that, except as otherwise specified in the permit monitoring requirements that, except as otherwise specified in an applicable provision in Appendix A, contains the following information:

(A) For all SO2 emitting units involved in the monitoring plan:

(i) Plant name and location (street address, legal address, county, city);

(ii) Plant and unit identification numbers assigned by the Department;

(iii) Type of unit (or units for a group of units using a common monitoring methodology);

(iv) Identification of all stacks or pipes associated with the monitoring plan;

(v) Types of fuel(s) fired (or sulfur containing process materials used in the SO2 emitting unit) and the fuel classification of the unit if combusting more than one type of fuel and using a 40 CFR Part 75 (2003) methodology;

(vi) Type(s) of emissions controls installed or to be installed, including specifications of whether such controls are pre-combustion, post-combustion, or integral to the combustion process;

(vii) Maximum hourly heat input capacity, or process throughput capacity, if applicable;

(viii) Identification of all units using a common stack; and

(ix) Indication of whether any stack identified in the plan is a bypass stack.

(B) For each unit and parameter required to be monitored, identification of monitoring methodology information monitoring methodology, monitor locations, substitute data approach for the methodology, and general identification of quality assurance procedures. If the proposed methodology is a site-specific methodology submitted pursuant to OAR 340-228-0480(1)(a)(B)(iv), the description under this paragraph must describe fully all aspects of the monitoring equipment, installation locations, operating characteristics, certification testing, ongoing quality assurance and maintenance procedures, and substitute data procedures.

(C) If the WEB source intends to petition for a change to any specific monitoring requirement otherwise required under OAR 340-228-0480, such petition may be submitted as part of the initial monitoring plan.

(D) The Department may issue a notice of approval or disapproval of the initial monitoring plan based on the compliance of the proposed methodology with the requirements for monitoring in this rule.

(d) Detailed Monitoring Plan. The Account Representative must submit a detailed monitoring plan that, except as otherwise specified in an applicable provision in Appendix A, contains the following information:

(A) Identification and description of each monitoring component (including each monitor and its identifiable components, such as analyzer and/or probe) in a CEMS (e.g., SO2 pollutant concentration monitor, flow monitor, moisture monitor), a 40 CFR Part 75, Appendix D monitoring system (e.g., fuel flowmeter, data acquisition and handling system), or a protocol in or a protocol in Appendix A, including:

(i) Manufacturer, model number, and serial number;

(ii) Component/system identification code assigned by the facility to each identifiable monitoring component, such as the analyzer and/or probe;

(iii) Designation of the component type and method of sample acquisition or operation (e.g., in situ pollutant concentration monitor or thermal flow monitor);

(iv) Designation of the system as a primary or backup system;

(v) First and last dates the system reported data;

(vi) Status of the monitoring component; and

(vii) Parameter monitored.

(B) Identification and description of all major hardware and software components of the automated data acquisition and handling system, including:

(i) Hardware components that perform emission calculations or store data for quarterly reporting purposes (provide the manufacturer and model number); and

(ii) Software components (provide the identification of the provider and model/version number).

(C) Explicit formulas for each measured emissions parameter, using component/system identification codes for the monitoring system used to measure the parameter that links the system observations with the reported concentrations and mass emissions. The formulas must contain all constants and factors required to derive mass emissions from component/system code observations and an indication of whether the formula is being added, corrected, deleted, or is unchanged. The owner or operator of a low mass emissions unit for which the owner or operator is using the optional low mass emissions excepted methodology in 40 CFR section 75.19(c) (2003) is not required to report such formulas.

(D) for units with flow monitors only, include the inside cross-sectional area (ft2) at flow monitoring location.

(E) If using CEMS for SO2 and flow, for each parameter monitored, include the scale, maximum potential concentration (and method of calculation), maximum expected concentration (if applicable) (and method of calculation), maximum potential flow rate (and method of calculations), span value, full-scale range, daily calibration units of measure, span effective date/hour, span inactivation date/hour, indication of whether dual spans are required, default high range value, flow rate span, and flow rate span value and full scale value (in scfh) for each unit or stack using SO2 or flow component monitors.

(F) If the monitoring system or excepted methodology provides for use of a constant, assumed, or default value for a parameter under specific circumstances, then include the following information for each value of such parameter:

(i) Identification of the parameter;

(ii) Default, maximum, minimum, or constant value, and units of measure for the value;

(iii) Purpose of the value;

(iv) Indicator of use during controlled/uncontrolled hours;

(v) Types of fuel;

(vi) Source of the value;

(vii) Value effective date and hour;

(viii) Date and hour value is no longer effective (if applicable); and

(ix) For units using the excepted methodology under 40 CFR section 75.19 (2003), the applicable SO2 emission factor.

(G) Unless otherwise specified in section 6.5.2.1 of Appendix A to 40 CFR Part 75 (2003), for each unit or common stack on which hardware CEMS are installed:

(i) The upper and lower boundaries of the range of operation (as defined in section 6.5.2.1 of Appendix A to 40 CFR Part 75), or thousand of lb/hr of steam, or ft/sec (as applicable);

(ii) The load or operating level(s) designated as normal in section 6.5.2.1 of Appendix A to 40 CFR Part 75, or thousands of lb/hr of steam, or ft/sec (as applicable);

(iii) The two load or operating levels (i.e., low, mid, or high) identified in section 6.5.2.1 of Appendix A to 40 CFR Part 75 as the most frequently used;

(iv) The date of the data analysis used to determine the normal load (or operating) level(s) and the two most frequently-used load (or operating) levels; and

(v) Activation and deactivation dates when the normal load or operating level(s) change and are updated.

(H) For each unit that is complying with 40 CFR Part 75 (2003) for which the optional fuel flow-to-load test in section 2.1.7 of appendix D to 40 CFR Part 75 is used:

(i) The upper and lower boundaries of the range of operation (as defined in section 6.5.2.1 of Appendix A to 40 CFR Part 75), expressed in thousand of lb/hr of steam;

(ii) The load level designated as normal, pursuant to section 6.5.2.1 of Appendix A to 40 CFR Part 75, expressed in thousands of lb/hr of steam; and

(iii) The date of the load analysis used to determine the normal load level.

(I) Information related to quality assurance testing, including (as applicable): identification of the test strategy; protocol for the relative accuracy test audit; other relevant test information; calibration gas levels (percent of span) for the calibration error test and linearity check; calculations for determining maximum potential concentration, maximum expected concentration (if applicable), maximum potential flow rate, and span;

(J) If applicable, apportionment strategies under 40 CFR sections 75.10 through 75.18 (2003).

(K) Description of site locations for each monitoring component in a monitoring system, including schematic diagrams and engineering drawings and any other documentation that demonstrates each monitor location meets the appropriate siting criteria. For units monitored by a continuous emission monitoring system, diagrams must include:

(i) A schematic diagram identifying entire gas handling system from unit to stack for all units, using identification numbers for units, monitor components, and stacks corresponding to the identification numbers provided in the initial monitoring plan and OAR 340-228-0480(2)(d)(A) and (C). The schematic diagram must depict the height of any monitor locations. Comprehensive and/or separate schematic diagrams must be used to describe groups of units using a common stack.

(ii) Stack and duct engineering diagrams showing the dimensions and locations of fans, turning vanes, air preheaters, monitor components, probes, reference method sampling ports, and other equipment that affects the monitoring system location, performance, or quality control checks.

(L) A data flow diagram denoting the complete information handling path from output signals of CEMS components to final reports.

(e) In addition to supplying the information in OAR 340-228-0480(2)(c) and (d), the owner or operator of an SO2 emitting unit using either of the methodologies in OAR 340-228-0480(1)(a)(B)(ii) must include the following information in its monitoring plan for the specific situations described:

(A) For each gas-fired or oil-fired SO2 emitting unit for which the owner or operator uses the optional protocol in appendix D to 40 CFR Part 75 for SO2 mass emissions, the Account Representative must include the following information in the monitoring plan:

(i) Parameter monitored;

(ii) Type of fuel measured, maximum fuel flow rate, units of measure, and basis of maximum fuel flow rate (i.e., upper range value or unit maximum) for each fuel flowmeter;

(iii) Test method used to check the accuracy of each fuel flowmeter;

(iv) Submission status of the data;

(v) Monitoring system identification code;

(vi) The method used to demonstrate that the unit qualifies for monthly GCV sampling or for daily or annual fuel sampling for sulfur content, as applicable;

(vii) A schematic diagram identifying the relationship between the unit, all fuel supply lines, the fuel flowmeter(s), and the stack(s). The schematic diagram must depict the installation location of each fuel flowmeter and the fuel sampling location(s). Comprehensive and/or separate schematic diagrams will be used to describe groups of units using a common pipe;

(viii) For units using the optional default SO2 emission rate for "pipeline natural gas" or "natural gas" in appendix D to 40 CFR Part 75 (2003), the information on the sulfur content of the gaseous fuel used to demonstrate compliance with either section 2.3.1.4 or 2.3.2.4 of appendix D to 40 CFR Part 75;

(ix) For units using the 720 hour test under section 2.3.6 of appendix D to 40 CFR Part 75 to determine the required sulfur sampling requirements, report the procedures and results of the test; and

(x) For units using the 720 hour test under section 2.3.5 of appendix D to 40 CFR Part 75 to determine the appropriate fuel gross calorific value (GCV) sampling frequency, report the procedures used and the results of the test.

(B) For each SO2 emitting unit for which the owner or operator uses the low mass emission excepted methodology of section 75.19 to 40 CFR Part 75, the Account representative must include the following information in the monitoring plan that accompanies the initial certification application:

(i) The results of the analysis performed to qualify as a low mass emissions unit under 40 CFR section 75.19(c) (2003). This report must include either the previous three years actual or projected emissions. The following items must be included:

(I) Current calendar year of application;

(II) Type of qualification;

(III) Years one, two, and three;

(IV) Annual measured, estimated, or projected SO2 mass emissions for years one, two, and three; and

(V) Annual operating hours for years one, two, and three.

(ii) A schematic diagram identifying the relationship between the unit, all fuel supply lines and tanks, any fuel flowmeter(s), and the stack(s). Comprehensive separate schematic diagrams must be used to describe groups of units using a common pipe;

(iii) For units which use the long term fuel flow methodology under 40 CFR section 75.19(c)(3) (2003), a diagram of the fuel flow to each unit or group of units and a detailed description of the procedures used to determine the long term fuel flow for a unit or group of units for each fuel combusted by the unit or group of units;

(iv) A statement that the unit burns only gaseous fuel(s) and/or fuel oil and a list of the fuels that are burned or a statement that the unit is projected to burn only gaseous fuel(s) and/or fuel oil and a list of the fuels that are projected to be burned;

(v) A statement that the unit meets the applicability requirements in 40 CFR 75.19(a) and (b) with respect to SO2 emissions; and

(vi) Any unit historical actual, estimated and projected SO2 emissions data and calculated SO2 emissions data demonstrating that the unit qualifies as a low mass emissions unit under 40 CFR 75.19(a) and (b).

(C) For each gas-fired unit the Account Representative will include the following in the monitoring plan: current calendar year, fuel usage data as specified in the definition of gas-fired in 40 CFR section 72.2 (2003), and an indication of whether the data are actual or projected data.

(f) The specific elements of a monitoring plan under OAR 340-228-0480(2) must not be part of an operating permit for a WEB source issued in accordance with Title V of the Clean Air Act, and modifications to the elements of the plan must not require a permit modification.

(3) Certification/Recertification

(a) All monitoring systems are subject to initial certification and recertification testing as specified in 40 CFR Part 75 (2003) or Appendix A to this Rule as applicable. Certification or recertification of a monitoring system by the U.S. Environmental Protection Agency for a WEB source that is subject to 40 CFR Part 75 under a requirement separate from this division constitutes certification under the WEB Trading Program.

(b) The owner or operator of an SO2 emitting unit not otherwise subject to 40 CFR Part 75 that monitors SO2 mass emissions in accordance with 40 CFR Part 75 to satisfy the requirements of this rule must perform all of the tests required by that regulation and must submit the following to the Department:

(A) A test notice not later than 21 days before the certification testing of the monitoring system, provided that the Department may establish additional requirements for adjusting test dates after this notice as part of the approval of the initial monitoring plan under OAR 340-228-0480(2)(c); and

(B) An initial certification application within 45 days after testing is complete. A monitoring system will be considered provisionally certified while the application is pending.

(c) A monitoring system is provisionally certified while the application is pending, and the system shall be deemed certified if the Department does not approve or disapprove the system within six months after the date on which the application is submitted.

(d) Whenever an audit of any monitoring certified under OAR 340-228-0400 through 340-228-0530, and a review of the initial certification or recertification application, reveal that any system or component should not have been certified or recertified because it did not meet a particular performance specification or other requirement of 340-228-0400 through 340-228-0530, both at the time of the initial certification or recertification application submission and at the time of the audit, the Department will issue a notice of disapproval of the certification status of such system or component. For the purposes of this subsection, an audit shall be either a field audit of the facility or an audit of any information submitted to the Department regarding the facility. By issuing the notice of disapproval, the certification status is revoked prospectively, and the data measured and recorded shall not be considered valid quality-assured data from the date of issuance of the notification of the revoked certification status until the date and time that the WEB source completes subsequently approved initial certification or recertification tests in accordance with the procedures in 340-228-0480(3). The WEB source shall apply the substitute data procedures in 340-228-0480(5)(b) to replace, prospectively, all of the invalid, non-quality-assured data for each disapproved system or component.

(4) Ongoing Quality Assurance and Quality Control. The WEB source must satisfy the applicable quality assurance and quality control requirements contained in 40 CFR Part 75 (2003) or, if the WEB source is subject to a WEB protocol in Appendix A, the applicable quality assurance and quality control requirements in Appendix A on and after the date that certification testing commences.

(5) Substitute Data Procedures.

(a) For any period after certification testing is complete in which quality-assured, valid data are not being recorded by a monitoring system certified and operating in accordance with OAR 340-228-0400 through 0530, missing or invalid data must be replaced with substitute data in accordance with 40 CFR Part 75 (2003) or, if the WEB source is subject to a WEB protocol in Appendix A, with substitute data in accordance with Appendix A.

(b) For an SO2 emitting unit that does not have a certified (or provisionally certified) monitoring system in place as of the beginning of the first control period for which the unit is subject to the WEB Trading Program, the owner or operator must:

(A) If the owner or operator will use a CEMS to comply with OAR 340-228-0400 through 340-228-0530, substitute the maximum potential concentration of SO2 for the unit and the maximum potential flow rate, as determined in accordance with 40 CFR Part 75 (2003). The procedures for conditional data validation under 40 CFR section 75.20(b)(3) may be used for any monitoring system under this Rule that uses these 40 CFR Part 75 procedures, as applicable;

(B) If the owner or operator will use the 40 CFR Part 75 Appendix D methodology, substitute the maximum potential sulfur content, density, or gross calorific value for the fuel and the maximum potential fuel flow rate, in accordance with section 2.4 of Appendix D to 40 CFR Part 75;

(C) If the owner or operator will use the 40 CFR Part 75 low mass emissions units, substitute the SO2 emission factor required for the unit as specified in 40 CFR section 75.19 and the maximum rated hourly heat input, as defined in 40 CFR section 72.2.

(D) If using a protocol in Appendix A to this Rule, follow the procedures in the applicable protocol.

(6) Compliance Deadlines.

(a) The initial monitoring plan must be submitted by the following dates:

(A) For each source that is a WEB source on or before the Program Trigger Date, the monitoring plan must be submitted 180 days after such Program Trigger Date.

(B) For any existing source that becomes a WEB source after the Program Trigger Date, the monitoring plan must be submitted by September 30 of the year following the inventory year in which the source exceeded the emissions threshold.

(C) For any new WEB source, the monitoring plan must be included with the permit application for New Source Review.

(b) A detailed monitoring plan under OAR 340-228-0480(2)(b) must be submitted no later than 45 days prior to commencing certification testing in accordance with (c) below.

(c) Emission monitoring systems must be installed, operational and meet all of the certification testing requirements of this OAR 340-228-0480 (including any referenced in Appendix A)by the following dates:

(A) For each source that is a WEB source on or before the Program Trigger Date, two years before the start of the first control period as described in OAR 340-228-0510.

(B) For any existing source that becomes a WEB source after the Program Trigger Date, one year after the due date for the monitoring plan OAR 340-228-0480(6)(a)(B).

(C) For any new WEB source (or any new unit at a WEB source under OAR 340-228-0480(c)(A) or (c)(B)), the earlier of 90 unit operating days or 180 calendar days after the date the new source commences operation.

(d) The owner or operator must submit test notices and certification applications in accordance with the deadlines set forth in OAR 340-228-0480(3)(b).

(e) For each applicable control period, the WEB source must submit each quarterly report under OAR 340-228-0480(8) by no later than 30 days after the end of each calendar quarter and must submit the annual report under OAR 340-228-0480(8) no later than 60 days after the end of each calendar year.

(7) Recordkeeping.

(a) Except as provided in OAR 340-228-0480(7)(b), the WEB source must keep copies of all reports, registration materials, compliance certifications, sulfur dioxide emissions data, quality assurance data, and other submissions under 340-228-0400 through 340-228-0530 for a period of five years. In addition, the WEB source shall keep a copy of all Account Certificates of Representation for the duration of the program. Unless otherwise requested by the WEB source and approved by the Department, the copies must be kept on site.

(b) The WEB source must keep records of all operating hours, quality assurance activities, fuel sampling measurements, hourly averages for SO2, stack flow, fuel flow, or other continuous measurements, as applicable, and any other applicable data elements specified in this rule or in Appendix A to this Rule. The WEB source must maintain the applicable records specified in 40 CFR Part 75 for any SO2 emitting unit that uses a Part 75 monitoring method to meet the requirements of this rule.

(8) Reporting.

(a) Quarterly Reports. For each SO2 emitting unit, the Account Representative must submit a quarterly report within thirty days after the end of each calendar quarter. The report must be in a format specified by the Department to include hourly and quality assurance activity information and must be submitted in a manner compatible with the emissions tracking database designed for the WEB Trading Program. If the owner or operator submits a quarterly report under 40 CFR Part 75 to the U.S. EPA Administrator, no additional report under this paragraph (a) are required; provided, however, that the Department may require that a copy of that report (or a separate statement of quarterly and cumulative annual SO2 mass emissions) be submitted separately to the Department.

(b) Annual Report. Based on the quarterly reports, each WEB source must submit an annual statement of total annual SO2 emissions for all SO2 emitting units at the source. The annual report must identify total emissions for all units monitored in accordance with OAR 340-228-0480(1)(a) and the total emissions for all units with emissions estimated in accordance with 340-228-0480(1)(b). The annual report must be submitted within 60 days after the end of a control period.

(c) If the Department so directs, that any monitoring plan, report, certification or recertification, or emissions data required to be submitted under this rule, will be submitted to the Tracking System Administrator.

(d) The Department may review and reject any report submitted under this OAR 340-228-0480(7) that contains errors or fails to satisfy the requirements of this rule, and the Account Representative must resubmit the report to correct any deficiencies.

(e) Petitions. A WEB source may petition for an alternative to any requirement specified in OAR 340-228-0480(1)(a)(B). The petition requires approval by the Department and the U.S. EPA Administrator. Any petition submitted under this paragraph must include sufficient information for evaluating the petition, including, at a minimum, the following information:

(A) Identification of the WEB source and applicable SO2 emitting unit(s);

(B) A detailed explanation of why the proposed alternative is being suggested in lieu of the requirement;

(C) A description and diagram of any equipment and procedures used in the proposed alternative, if applicable;

(D) A demonstration that the proposed alternative is consistent with the purposes of the requirement for which the alternative is proposed is consistent with the purposes of OAR 340-228-0400 through 340-228-0530, and that any adverse effect of approving such alternative will be de minimis; and

(E) Any other relevant information that the Department may require.

(f) Consistency of Identifying Information. For any monitoring plans, reports, or other information submitted under OAR 340-228-0400 through 340-228-0530, the Account Representative must ensure that, where applicable, identifying information is consistent with the identifying information provided in the most recent certificate of representation for the WEB source submitted under 340-228-0440.

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

Stat. Auth.: ORS 468.020
Stats. Implemented: ORS 468A.035
Hist.: DEQ 19-2003, f. & cert. ef. 12-12-03

340-228-0490

Allowance Transfers

(1) Procedure. To transfer allowances, the Account Representative must submit the following information to the Tracking System Administrator:

(a) The transfer account number(s) identifying the transferor account;

(b) The transfer account number(s) identifying the transferee account;

(c) The serial number of each allowance to be transferred; and

(d) The transferor's Account Representative's name, signature, and the date of submission.

(2) Allowance Transfer Deadline. The allowance transfer deadline is midnight Pacific Standard Time March 1 of each year (or if this date is not a business day, midnight of the first business day thereafter) following the end of the control period. By this time, the transfer of the allowances into the WEB source's compliance account must be correctly submitted to the Tracking System Administrator in order to demonstrate compliance under OAR 340-228-0510(1) for that control period.

(3) Retirement of Allowances. To permanently retire allowances, the transferor's account representative must submit the following information to the Tracking System Administrator:

(a) The transfer account number(s) identifying the transferor account;

(b) The serial number of each allowance to be retired; and

(c) The transferor's Account Representative's name, signature, and the date of submission accompanied by a signed statement acknowledging that each retired allowance as no longer available for future transfers from or to any account.

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

Stat. Auth.: ORS 468.020
Stats. Implemented: ORS 468A.035
Hist.: DEQ 19-2003, f. & cert. ef. 12-12-03

340-228-0500

Use of Allowances from a Previous Year

(1) Any allowance that is held in a compliance account or general account remains in the account until the allowance is either deducted in conjunction with the compliance process or transferred to another account.

(2) In order to demonstrate compliance under OAR 340-228-0510(1) for a control period, WEB sources may use allowances allocated for that control period or any previous year. Because all allowances held in a special reserve compliance account for a WEB source that monitors certain units in accordance with 340-228-0480(1)(b) will be deducted for compliance for each control period, no banking of such allowances for use in a subsequent year is permitted by 340-228-0400 through 340-228-0530.

(3) If flow control procedures for the current control period have been triggered as outlined in Section 5.5.2.3.3(h)(2) of the State Implementation Plan, then the use of allowances that were allocated for any previous year will be limited as follows:

(a) The number of allowances that are held in each compliance account and general account as of the allowance transfer deadline for the immediately previous year and that were allocated for any previous year will be determined by the Department.

(b) The number determined in OAR 340-228-0500(3)(a) will be multiplied by the flow control ratio established in accordance with Section 5.5.2.3.3(k)(1) of the State Implementation Plan to determine the number of allowances that were allocated for a previous year that can be used without restriction for the current control period.

(c) Allowances that were allocated for a previous year in excess of the number determined in OAR 340-228-0500(3)(b) may also be used for the current control period. If such allowances are used to make a deduction, two allowances must be deducted for each deduction of one allowance required under 340-228-0510.

(4) Special provisions for the year 2018. After the Department has determined compliance with the 2017 allowance limitation in accordance with OAR 340-228-0510(1), allowances allocated for any year before 2018 may not be used for determining compliance with the 2018 allowance limitation or any future allowance limitation.

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

Stat. Auth.: ORS 468.020
Stats. Implemented: ORS 468A.035
Hist.: DEQ 19-2003, f. & cert. ef. 12-12-03

340-228-0510

Compliance

(1) Compliance with Allowance Limitations.

(a) The WEB source must hold allowances, in accordance with OAR 340-228-0510(1)(b) and 340-228-0500, as of the allowance transfer deadline in the WEB source's compliance account, (together with any current control year allowances held in the WEB source's special reserve compliance account under 340-228-0480(1)(b)) in an amount not less than the total SO2 emissions for the control period from the WEB source, as determined under the monitoring and reporting requirements of 340-228-0480.

(A) For each source that is a WEB source on or before the Program Trigger Date, the first control period is the calendar year that is six years following the calendar year for which SO2 emissions exceeded the milestone in accordance with procedures in Section 5.5.2.3.1 of the State Implementation Plan.

(B) For any existing source that becomes a WEB source after the Program Trigger Date, the first control period is the calendar year that is four years following the inventory year in which the source became a WEB source.

(C) For any new WEB source after the Program Trigger Date, the first control period is the first full calendar year that the source is in operation.

(D) If the WEB Trading Program is triggered in accordance with the year 2013 review procedures in section 5.5.2.3.1(d) of the State Implementation Plan, the first control period for each source that is a WEB source on or before the Program Trigger Date is the year 2018.

(b) An allowance may be deducted from the WEB source's compliance account only if:

(A) the allowance was allocated for the current control period or meets the requirements in OAR 340-228-0500 for use of allowances from a previous control period, and

(B) the allowance was held in the WEB source's compliance account as of the allowance transfer deadline for the current control period, or the allowance was transferred into the compliance account by an allowance transfer correctly submitted for recording by the allowance transfer deadline for the current control period.

(c) Compliance with allowance limitations must be determined as follows:

(A) The total annual SO2 emissions for all SO2 emitting units at the source that are monitored under OAR 340-228-0480(1)(b), as reported by the source in 340-228-0480(8)(b) or (d), and recorded in the emissions tracking database shall be compared to the allowances held in the source's special reserve compliance account as of the allowance transfer deadline for the current control period, adjusted in accordance with 340-228-0500. If the emissions are equal to or less than the allowances in such account, all such allowances shall be retired to satisfy the obligation to hold allowances for such emissions. If the total emissions from such units exceeds the allowances in such special reserve account, the WEB source shall account for such excess emissions in the following paragraph (A) of this subsection.

(B) The total annual SO2 emissions for all SO2 emitting units at the source that are monitored under OAR 340-228-0480(1)(a), as reported by the source in 340-228-0480(8)(b) or (d), and recorded in the emissions tracking database, together with any excess emissions as calculated in the preceding paragraph (A) of this subsection, shall be compared to the allowances held in the source's compliance account as of the allowance transfer deadline for the current control period, adjusted in accordance with 340-228-0500.

(d) Deduction of Allowances. Other than allowances in a special reserve compliance account for units monitored under OAR 340-228-0480(1)(b) to the extent consistent with 340-228-0500, allowances must be deducted for a WEB source for compliance with the allowance limitation as directed by the WEB source's Account Representative. Deduction of any other allowances as necessary for compliance with the allowance limitation must be on a first-in, first-out accounting basis in the order of the date and time of their recording in the WEB source's compliance account, beginning with the allowances allocated to the WEB source and continuing with the allowances transferred to the WEB source's compliance account from another compliance account or general account. The allowances held in a special reserve compliance account pursuant to 340-228-0480(1)(b) shall be deducted as specified in 340-228-0510(1)(c)(A).

(e) SO2 emissions violations by a source subject to (c) and (d) of this rule:

(A) Each ton of SO2 by a source in excess of its allowance limitation for a control period is a violation.

(B) Each day of the control period is a separate violation, and each ton of SO2 emissions in excess of a source's allowance limitation is a separate violation.

(2) Certification of Compliance.

(a) For each control period in which a WEB source is subject to the allowance limitation, the Account Representative of the source must submit to the Department a Compliance Certification report for the source.

(b) The Compliance Certification report must be submitted no later than the allowance transfer deadline of each control period and must contain the following:

(A) Identification of each WEB source;

(B) At the Account Representative's option, the serial numbers of the allowances that are to be deducted from a source's compliance account for compliance with the allowance limitation; and

(C) The Compliance Certification report according to OAR 340-228-0510(2)(c).

(c) In the Compliance Certification report, the Account Representative must certify, based on reasonable inquiry of those persons with primary responsibility for operating the WEB source in compliance with the WEB Trading Program, whether the WEB source for which the compliance certification is submitted was operated in compliance with the requirements of the WEB Trading Program applicable to the source during the control period covered by the report, including:

(A) Whether the WEB source operated in compliance with the SO2 allowance limitation;

(B) Whether SO2 emissions data was submitted to the Department in accordance with OAR 340-228-0480(8) and other applicable requirements, for review, revision as necessary, and finalization;

(C) Whether the monitoring plan for the WEB source has been maintained to reflect the actual operation and monitoring of the source and contains all information necessary to attribute SO2 emissions to the source, in accordance with OAR 340-228-0480(1);

(D) Whether all the SO2 emissions from the WEB source, were monitored or accounted for either through the applicable monitoring or through application of the appropriate missing data procedures;

(E) If applicable, whether any SO2 emitting unit for which the WEB source is not required to monitor in accordance with OAR 340-228-0480(1)(a)(C) remained permanently retired and had no emissions for the entire applicable period; and

(F) Whether there were any changes in the method of operating or monitoring the WEB source that required monitor recertification. If there were any such changes, the report must specify the nature, reason, and date of the change, the method to determine compliance status subsequent to the change, and specifically, the method to determine SO2 emissions.

(3) Penalties for any WEB source exceeding its allowance limitations.

(a) Allowance deduction penalties.

(A) An allowance deduction penalty will be assessed equal to two times the number of the WEB source's tons of SO2 emissions in excess of its allowance limitation for a control period, determined in accordance with OAR 340-228-0510(1). Allowances allocated for that control period in the amount of the allowance deduction penalty will be deducted from the source's compliance account. If the compliance account does not have sufficient allowances allocated for that control period, the required number of allowances will be deducted from the WEB source's compliance account regardless of the control period for which they were allocated, once allowances are recorded in the account.

(B) Any allowance deduction required under OAR 340-228-0510(1)(c) will not affect the liability of the owners and operators of the WEB source for any fine, penalty, or assessment or their obligation to comply with any other remedy for the same violation as ordered under the Clean Air Act, implementing regulations, or applicable state or tribal law. Accordingly, a violation can be assessed each day of the control period for each ton of SO2 emissions in excess of its allowance limitation or for each other violation of OAR 340-228-0400 through 340-228-0530.

(4) Enforcement.

(a) WEB Source liability for non-compliance. In addition to any allowance deduction, a WEB source that violates any requirement of this rule, including those listed under (1)(e) of this section, is subject to civil and criminal penalties, including but not limited to penalties under ORS 468, 468A, the Clean Air Act, and under OAR 340-012.

(b) General liability.

(A) Any provision of the WEB Trading Program that applies to a source or an Account Representative also applies to the owners and operators of such source.

(B) Any person who violates any requirement or prohibition of the WEB Trading Program is subject to enforcement pursuant to OAR 340, division 12.

(C) Any person who knowingly makes a false material statement in any record, submission, or report under this WEB Trading Program is subject to criminal enforcement pursuant to ORS 468.953.

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

Stat. Auth.: ORS 468.020
Stats. Implemented: ORS 468A.035
Hist.: DEQ 19-2003, f. & cert. ef. 12-12-03

340-228-0520

Special Penalty Provisions for 2018 Milestone

(1) If the WEB Trading Program is triggered as outlined in Section 5.5.2.3.1 of the State Implementation Plan, and the first control period will not occur until after the year 2018, the following provisions will apply for the 2018 emissions year.

(a) All WEB sources will register, and will open a compliance account within 180 days after the Program Trigger Date, in accordance with OAR 340-228-0450(1) and 340-228-0470.

(b) The Tracking System Administrator will record the allowances for the 2018 control period for each WEB source in the source's compliance account once the Department allocates the 2018 allowances under Section 5.5.2.3.3(a) of the State Implementation Plan.

(c) The allowance transfer deadline is midnight Pacific Standard Time on May 30, 2021. WEB sources may transfer allowances as provided in OAR 340-228-0490(1) until the allowance transfer deadline.

(d) A WEB source must hold allowances allocated for 2018 including those transferred into the compliance account or a special reserve account by an allowance transfer correctly submitted by the allowance transfer deadline, in an amount not less than the WEB source's total SO2 emissions for 2018. Emissions will be determined using the pre-trigger monitoring provisions in Section 5.5.2.3.2 of the State Implementation Plan, and OAR 340-214-0400 through 340-214-0530.

(e) An allowance deduction and penalty for violation of SO2 allowance limitation will be assessed and levied in accordance with OAR 340-228-0500(4), 340-228-0510(1)(d) and (e), and 340-228-0510(3) and (4), except that SO2 emissions will be determined under 340-228-0520(1)(d).

(2) If the program has been triggered and OAR 340-228-0520(1) is implemented, the provisions of 340-228-0520(3) will apply for each year after the 2018 emission year until:

(a) The first control period under the WEB trading program; or

(b) The Department determined, in accordance with section 5.5.2.3.1(c)(10) of the Implementation Plan, that the 2018 SO2 milestone has been met.

(3) If OAR 340-228-0520(1) was implemented, the following will apply to each emissions year after the 2018 emissions year:

(a) The Tracking System Administrator will record the allowances for the control period for the specific year for each WEB source in the source's compliance account once the Department allocates the allowances under Section 5.5.2.3.3.a of the State Implementation Plan.

(b) The allowance transfer deadline is midnight Pacific Standard Time on March 1 of each year (or if this date is not a business day, midnight of the first business day thereafter) following the end of the specific emissions year. WEB sources may transfer allowances as provided in OAR 340-228-0490(1) until the allowance transfer deadline.

(c) A WEB source must hold allowances allocated for that specific emissions year, or any year after 2018, including those transferred into the compliance account by an allowance transfer correctly submitted by the allowance transfer deadline, in an amount not less than the WEB source's total SO2 emissions for the specific emissions year. Emissions are determined using the pre-trigger monitoring provisions in Section 5.5.2.3.2 of the State Implementation Plan, and OAR 340-214-0400 through 0530.

(d) An allowance deduction and penalty for violation of SO2 allowance limitation will be assessed and levied in accordance with OAR 340-228-0500(4), 340-228-0510(1)(d) and (e), and 340-228-0510(3) and (4), except that SO2 emissions shall be determined under 340-228-0520(3)(c).

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

Stat. Auth.: ORS 468.020
Stats. Implemented: ORS 468A.035
Hist.: DEQ 19-2003, f. & cert. ef. 12-12-03

340-228-0530

Integration into Permits

Any WEB source that is not subject to OAR 340, division 218 at any time after 340-228-0400 through 340-228-0530 becomes effective must obtain a permit under OAR 340, division 216 or modify an existing permit issued under that division that incorporates the requirements of 340-228-0400 through 340-228-0530.

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

Stat. Auth.: ORS 468.020
Stats. Implemented: ORS 468A.035
Hist.: DEQ 19-2003, f. & cert. ef. 12-12-03

 

APPENDIX A: WEB MODEL RULE MONITORING PROTOCOLS

 

Protocol WEB-1: SO2 Monitoring of Fuel Gas Combustion Devices

1. Applicability.

(a) The provisions of this protocol are applicable to fuel gas combustion devices at petroleum refineries.

(b) Fuel gas combustion devices include boilers, process heaters, and flares used to burn fuel gas generated at a petroleum refinery.

(c) Fuel gas means any gas which is generated and combusted at a petroleum refinery. Fuel gas does not include: (1) natural gas, unless combined with other gases generated at a petroleum refinery, (2) gases generated by a catalytic cracking unit catalyst regenerator, (3) gases generated by fluid coking burners, (4) gases combusted to produce sulfur or sulfuric acid, or (5) process upset gases generated due to startup, shutdown, or malfunctions.

2. Monitoring Requirements.

(a) Except as provided in paragraphs (b) and (c) of this Section 2, fuel gas combustion devices shall use a continuous fuel gas monitoring system (CFGMS) to determine the total sulfur content (reported as H2S) of the fuel gas mixture prior to combustion, and continuous fuel flow meters to determine the amount of fuel gas burned.

(1) Fuel gas combustion devices having a common source of fuel gas may be monitored for sulfur content at one location, if monitoring at that location is representative of the sulfur content of the fuel gas being burned in any fuel gas combustion device.

(2) The CFGMS shall meet the performance requirements in Performance Specification 2 in Appendix B to 40 CFR Part 60, and the following:

(i) Continuously monitor and record the concentration by volume of total sulfur compounds in the gaseous fuel reported as ppmv H2S.

(ii) Have the span value set so that the majority of readings fall between 10 and 95% of the range.

(iii) Record negative values of zero drift.

(iv) Calibration drift shall be 5.0% of the span.

(v) Methods 15A, 16, or approved alternatives for total sulfur, are the reference methods for the relative accuracy test. The relative accuracy test shall include a bias test in accordance with paragraph 4(c) of this section.

(3) All continuous fuel flow meters shall comply with the applicable provisions of Appendix D to 40 CFR Part 75.

(4) The hourly mass SO2 emissions shall be calculated using the following equation:

E = (CS)(Qf)(K)

where: E = SO2 emissions in lbs/hr

CS = Sulfur content of the fuel gas as H2S(ppmv)

Qf = Fuel gas flow rate (scfh)

K = 1.660 x 10-7 (lb/scf)/ppmv

(b) In place of a CFGMS in paragraph (a) of this Section 2, fuel gas combustion devices having a common source of fuel gas may be monitored with an SO2 CEMS and flow CEMS at only one location, if the CEMS monitoring at that location is representative of the SO2 emission rate (lb SO2/scf fuel gas burned) of all applicable fuel gas combustion devices. Continuous fuel flow meters shall be used in accordance with paragraph (b), and the fuel gas combustion device monitored by a CEMS shall have separate fuel metering.

(1) Each CEMS for SO2 and flow shall comply with the operating requirements, performance specifications, and quality assurance requirements of 40 CFR Part 75.

(2) All continuous fuel flow meters shall comply with the applicable provisions of Appendix D to 40 CFR Part 75.

(3) The SO2 mass emissions for all the fuel gas combustion devices monitored by this approach shall be determined by the ratio of the amount of fuel gas burned by the CEMS-monitored fuel gas combustion device to the total fuel gas burned by all applicable fuel gas combustion devices using the following equation:

Et = (Em)(Qt)/(Qm)

where: Et = Total SO2 emissions in lbs/hr from applicable fuel gas combustion devices.

Em = SO2 emissions in lbs/hr from the CEMS-monitored fuel gas combustion device.

Qt = Fuel gas flow rate (scfh) from applicable fuel gas combustion devices.

Qm = Fuel gas flow rate (scfh) from the CEMS-monitored fuel gas combustion device.

(c) In place of a CFGMS in paragraph (a) of this section, fuel gas combustion devices having a common source of fuel gas may be monitored with an SO2 -- diluent CEMS at only one location, if the CEMS monitoring at that location is representative of the SO2 emission rate (lb SO2/mmBtu) of all applicable fuel gas combustion devices. If this option is selected, the owner or operator shall conduct fuel gas sampling and analysis for gross calorific value (GCV), and shall use continuous fuel flow metering in accordance with paragraph (a) of this Section 2, with separate fuel metering for the CEMS-monitored fuel gas combustion device.

(1) Each SO2-diluent CEMS shall comply with the applicable provisions for SO2 monitors and diluent monitors in 40 CFR Part 75, and shall use the procedures in section 3 of Appendix F to Part 75 for determining SO2 emission rate (lb/mmBtu) by substituting the term SO2 for NOx in that section.

(2) All continuous fuel flow meters and fuel gas sampling and analysis for GCV to determine the heat input rate from the fuel gas shall comply with the applicable provisions of Appendix D to 40 CFR Part 75.

(3) The SO2 mass emissions for all the fuel gas combustion devices monitored by this approach shall be determined by the ratio of the fuel gas heat input to the CEMS-monitored fuel gas combustion device to the total fuel gas heat input to all applicable fuel gas combustion devices using the following equation:

Et = (Em)(Ht)/(Hm)

where: Et = Total SO2 emissions in lbs/hr from applicable fuel gas combustion devices.

Em = SO2 emissions in lb/mmBtu from the CEMS - monitored fuel gas combustion device.

Ht = Fuel gas heat input (mmBtu/hr) from applicable fuel gas combustion devices.

Hm = Fuel gas heat input (mmBtu/hr) from the CEMS - monitored fuel gas combustion device.

3. Certification/Recertification Requirements.

All monitoring systems are subject to initial certification and recertification testing as follows:

(a) The owner or operator shall comply with the initial testing and calibration requirements in Performance Specification 2 in Appendix B of 40 CFR Part 60 and paragraph 2 (a)(2) of this section for each CFGMS.

(b) Each CEMS for SO2 and flow or each SO2-diluent CEMS shall comply with the testing and calibration requirements specified in 40 CFR Part 75, section 75.20 and Appendices A and B, except that each SO2-diluent CEMS shall meet the relative accuracy requirements for a NOx-diluent CEMS (lb/mmBtu).

(c) A continuous fuel flow meter shall comply with the testing and calibration requirements in 40 CFR Part 75, Appendix D.

4. Quality Assurance/Quality Control Requirements.

(a) A quality assurance/quality control (QA/QC) plan shall be developed and implemented for each CEMS for SO2 and flow or the SO2-diluent CEMS in compliance with Appendix B of 40 CFR Part 75.

(b) A QA/QC plan shall be developed and implemented for each continuous fuel flow meter and fuel sampling and analysis in compliance with Appendix B of 40 CFR Part 75.

(c) A QA/QC plan shall be developed and implemented for each CFGMS in compliance with sections 1 and 1.1 of Appendix B of 40 CFR Part 75, and the following:

(1) Perform a daily calibration error test of each CFGMS at two gas concentrations, one low level and one high level. Calculate the calibration error as described in Appendix A to 40 CFR Part 75. An out of control period occurs whenever the error is greater than 5.0% of the span value.

(2) In addition to the daily calibration error test, an additional calibration error test shall be performed whenever a daily calibration error test is failed, whenever a monitoring system is returned to service following repairs or corrective actions that may affect the monitor measurements, or after making manual calibration adjustments.

(3) Perform a linearity test once every operating quarter. Calculate the linearity as described in Appendix A to 40 CFR Part 75. An out of control period occurs whenever the linearity error is greater than 5.0 percent of a reference value, and the absolute value of the difference between average monitor response values and a reference value is greater than 5.0 ppm.

(4) Perform a relative accuracy test audit once every four operating quarters. Calculate the relative accuracy as described in Appendix A to 40 CFR Part 75. An out of control period occurs whenever the relative accuracy is greater than 20.0% of the mean value of the reference method measurements.

(5) Using the results of the relative accuracy test audit, conduct a bias test in accordance with Appendix A to 40 CFR Part 75, and calculate and apply a bias adjustment factor if required.

5. Missing Data Procedures.

(a) For any period in which valid data are not being recorded by an SO2 CEMS or flow CEMS specified in this section, missing or invalid data shall be replaced with substitute data in accordance with the requirements in Subpart D of 40 CFR Part 75.

(b) For any period in which valid data are not being recorded by an SO2-diluent CEMS specified in this section, missing or invalid data shall be replaced with substitute data on a rate basis (lb/mmBtu) in accordance with the requirements for SO2 monitors in Subpart D of 40 CFR Part 75.

(c) For any period in which valid data are not being recorded by a continuous fuel flow meter or for fuel gas GCV sampling and analysis specified in this section, missing or invalid data shall be replaced with substitute data in accordance with missing data requirements in Appendix D to 40 CFR Part 75.

(d) For any period in which valid data are not being recorded by the CFGMS specified in this section, hourly missing or invalid data shall be replaced with substitute data in accordance with the missing data requirements for units performing hourly gaseous fuel sulfur sampling in section 2.4 of Appendix D to 40 CFR Part 75.

6. Monitoring Plan and Reporting Requirements.

In addition to the general monitoring plan and reporting requirements of Section I of this Rule, the owner or operator shall meet the following additional requirements:

(a) The monitoring plan shall identify each group of units that are monitored by a single monitoring system under this Protocol WEB-1, and the plan shall designate an identifier for the group of units for emissions reporting purposes. For purpose of submitting emissions reports, no apportionment of emissions to the individual units within the group is required.

(b) If the provisions of paragraphs 2(b) or (c) are used, provide documentation and an explanation to demonstrate that the SO2 emission rate from the monitored unit is representative of the rate from non-monitored units.

 

Protocol WEB-2: Predictive Flow Monitoring Systems for Kilns with Positive Pressure Fabric Filter

1. Applicability.

The provisions of this protocol are applicable to cement kilns or lime kilns that (1) are controlled by a positive pressure fabric filter, and (2) have operating conditions upstream of the fabric filter that the WEB source documents would reasonably prevent reliable flow monitor measurements.

2. Monitoring Requirements.

(a) A cement or lime kiln with a positive pressure fabric filter shall use a predictive flow monitoring system (PFMS) to determine the hourly kiln exhaust gas flow.

(b) A PFMS is the total equipment necessary for the determination of exhaust gas flow using process or control device operating parameter measurements and a conversion equation, a graph, or computer program to produce results in cubic feet per hour.

(c) The PFMS shall meet the following performance specifications:

(1) The PFMS must allow for the automatic or manual determination of failed monitors. At a minimum a daily determination must be performed.

(2) The PFMS shall have provisions to check the calibration error of each parameter that is individually measured. The owner or operator shall propose appropriate performance specifications in the initial monitoring plan for all parameters used in the PFMS comparable to the degree of accuracy required for other monitoring systems used to comply with this Rule. The parameters shall be tested at two levels, low: 0 to 20% of full scale, and high: 50 to 100% of full scale. The reference value need not be certified.

(3) The relative accuracy of the PFMS must be < 10.0% of the reference method average value, and include a bias test in accordance with paragraph 4(c) of this section.

3. Certification Requirements.

The PFMS is subject to initial certification testing as follows:

(a) Demonstrate the ability of the PFMS to identify automatically or manually a failed monitor.

(b) Provide evidence of calibration testing of all monitoring equipment. Any tests conducted within the previous 12 months of operation that are consistent with the QA/QC plan for the PFMS are acceptable for initial certification purposes.

(c) Perform an initial relative accuracy test over the normal range of operating conditions of the kiln. Using the results of the relative accuracy test audit, conduct a bias test in accordance with Appendix A to 40 CFR Part 75, and calculate and apply a bias adjustment factor if required.

4. Quality Assurance/Quality Control Requirements.

A QA/QC plan shall be developed and implemented for each PFMS in compliance with sections 1 and 1.1 of Appendix B of 40 CFR Part 75, and the following:

(a) Perform a daily monitor failure check.

(b) Perform calibration tests of all monitors for each parameter included in the PFMS. At a minimum, calibrations shall be conducted prior to each relative accuracy test audit.

(c) Perform a relative accuracy test audit and accompanying bias test once every four operating quarters. Calculate the relative accuracy (and bias adjustment factor) as described in Appendix A to 40 CFR Part 75. An out of control period occurs whenever the flow relative accuracy is greater than 10.0% of the mean value of the reference method.

5. Missing Data.

For any period in which valid data are not being recorded by the PFMS specified in this section, hourly missing or invalid data shall be replaced with substitute data in accordance with the flow monitor missing data requirements for non-load based units in Subpart D of 40 CFR Part 75.

6. Monitoring Plan Requirements.

In addition to the general monitoring plan requirements of Section I of this Rule, the owner or operator shall meet the following additional requirements:

(a) The monitoring plan shall document the reasons why stack flow measurements upstream of the fabric filter are unlikely to provide reliable flow measurements over time.

(b) The initial monitoring plan shall explain the relationship of the proposed parameters and stack flow, and discuss other parameters considered and the reasons for not using those parameters in the PFMS. The [state or tribe] may require that the subsequent monitoring plan include additional explanation and documentation for the reasonableness of the proposed PFMS.

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

Stat. Auth.: ORS 468.020
Stats. Implemented: ORS 468A.035
Hist.: DEQ 19-2003, f. & cert. ef. 12-12-03

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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