This rule establishes mandatory greenhouse gas (GHG) reporting requirements for owners and operators of certain facilities that directly emit GHG as well as for certain suppliers and electric power entities. For suppliers, the GHGs reported are the quantity that would be emitted from the complete combustion or oxidation of the products supplied.

The definitions in this section apply throughout this chapter unless the context clearly requires otherwise.

(1) Definitions specific to this chapter:

(a) "40 C.F.R. Part 98" or "40 C.F.R. § 98" means the United States Environmental Protection Agency's Mandatory Greenhouse Gas Reporting regulation including any applicable subparts. All references are adopted by reference as if it was copied into this rule. References mentioned in this rule are adopted as they exist on February 9, 2022, or the adoption date in WAC 173-400-025(1), whichever is later.

(b) "Asset controlling supplier" or "ACS" means any entity that owns or operates interconnected electricity generating facilities or serves as an exclusive marketer for these facilities even though it does not own them, and has been designated by the department and received a department-published emissions factor for the wholesale electricity procured from its system. Electricity from an asset controlling supplier is considered a specified source of electricity.

(c) "Biomass" means nonfossilized and biodegradable organic material originating from plants, animals, or microorganisms, including products, by-products, residues and waste from agriculture, forestry, and related industries as well as the nonfossilized and biodegradable organic fractions of industrial and municipal wastes, including gases and liquids recovered from the decomposition of nonfossilized and biodegradable organic material.

(d) "Carbon dioxide equivalent" or "CO2e" means a metric measure used to compare the emissions from various greenhouse gases based upon their global warming potential.

(e) "Director" means the director of the department of ecology.

(f) "Ecology" means the Washington state department of ecology.

(g) "Electric power entity" includes any of the following that supply electric power in Washington: (i) Electricity importers and exporters; (ii) retail providers, including multijurisdictional retail providers; and (iii) the asset controlling suppliers. See WAC 173-441-124 for more detail.

(h) "Facility" unless otherwise specified in WAC 173-441-122, 173-441-124, or any subpart of 40 C.F.R. Part 98 as adopted in WAC 173-441-120, means any physical property, plant, building, structure, source, or stationary equipment located on one or more contiguous or adjacent properties in actual physical contact or separated solely by a public roadway or other public right of way and under common ownership or common control, that emits or may emit any greenhouse gas. Operators of military installations may classify such installations as more than a single facility based on distinct and independent functional groupings within contiguous military properties.

(i) "Fuel products" means petroleum products, biomass-derived fuels, coal-based liquid fuels, natural gas, biogas, and liquid petroleum gas as established in 40 C.F.R. Part 98 Subparts LL through NN. Renewable or biogenic versions of fuel products listed in Tables MM-1 or NN-1 of 40 C.F.R. Part 98 are also considered fuel products. Assume complete combustion or oxidation of fuel products when calculating GHG emissions.

(j) "Fuel supplier" means any of the following suppliers of fuel products: (See WAC 173-441-122 for more detail.)

(i) A supplier of fossil fuel other than natural gas, including:

(A) A supplier of petroleum products;

(B) A supplier of liquid petroleum gas;

(C) A supplier of coal-based liquid fuels.

(ii) A supplier of biomass-derived fuels;

(iii) A supplier of natural gas, including:

(A) Operators of interstate and intrastate pipelines;

(B) Suppliers of liquefied or compressed natural gas;

(C) Natural gas liquid fractionators;

(D) Local distribution companies.

(k) "Greenhouse gas," "greenhouse gases," "GHG," and "GHGs" includes carbon dioxide, methane, nitrous oxide, hydrofluorocarbons, perfluorocarbons, and sulfur hexafluoride. Beginning on January 1, 2012, "greenhouse gas" also includes any other gas or gases designated by ecology by rule in Table A-1 in WAC 173-441-040.

(l) "Operator" means any individual or organization who operates or supervises a facility, supplier, or electric power entity. The operator of an electric power entity may be the electric power entity itself.

(m) "Owner" means any individual or organization who has legal or equitable title to, has a leasehold interest in, or control of a facility, supplier, or electric power entity, except an individual or organization whose legal or equitable title to or leasehold interest in the facility, supplier, or electric power entity arises solely because the person is a limited partner in a partnership that has legal or equitable title to, has a leasehold interest in, or control of the facility, supplier, or electric power entity shall not be considered an "owner" of the facility, supplier, or electric power entity.

(n) "Person" includes the owner or operator of:

(i) A facility;

(ii) A supplier; or

(iii) An electric power entity.

(o) "Product data" means data related to a facility's production that is part of the annual GHG report.

(p) "Reporter" means any of the following subject to this chapter:

(i) A facility;

(ii) A supplier; or

(iii) An electric power entity.

(q) "Supplier" means any person who is a:

(i) Fuel supplier that produces, imports, or delivers, or any combination of producing, importing, or delivering, fuel products in Washington; and

(ii) Supplier of carbon dioxide that produces, imports, or delivers a quantity of carbon dioxide in Washington that, if released, would result in emissions in Washington.

(2) Definitions specific to the Climate Commitment Act program.

For those terms not listed in subsection (1) of this section, WAC 173-441-122(2), or 173-441-124(2), the definitions from chapter 70A.65 RCW, as described in chapters 173-446 and 173-446A WAC apply in this chapter in order of precedence.

(3) Definitions from 40 C.F.R. Part 98. For those terms not listed in subsection (1) or (2) of this section, WAC 173-441-122(2), or 173-441-124(2), the definitions found in 40 C.F.R. § 98.6 or a subpart as adopted in this chapter, apply in this chapter as modified in WAC 173-441-120(2).

The GHG reporting requirements and related monitoring, recordkeeping, and reporting requirements of this chapter apply to the owners and operators of any facility that meets the requirements of subsection (1) of this section; any supplier that meets the requirements of subsection (2) of this section; and any electric power entity that meets the requirements of subsection (3) of this section. In determining whether reporting is required, the requirements of each subsection must be applied independently of the requirements of the other subsections. Research and development activities are not considered to be part of any source category defined in this chapter.

(1) Facility reporting. Reporting is mandatory for an owner or operator of any facility located in Washington state with total GHG emissions that exceeds the reporting threshold defined in (a) of this subsection. GHG emissions from all applicable source categories listed in WAC 173-441-120 at the facility must be included when determining whether emissions from the facility meet the reporting threshold.

(a) Facility reporting threshold. Any facility that emits 10,000 metric tons CO2e or more per calendar year in total GHG emissions from all applicable source categories listed in WAC 173-441-120 exceeds the reporting threshold.

(b) Calculating facility emissions for comparison to the threshold. To calculate GHG emissions for comparison to the reporting threshold, the owner or operator must:

(i) Calculate the total annual emissions of each GHG in metric tons from all applicable source categories that are listed and defined in WAC 173-441-120. The GHG emissions must be calculated using the calculation methodologies specified in WAC 173-441-120 and available company records.

(ii) Include emissions of all GHGs that are listed in Table A-1 of WAC 173-441-040, including all GHG emissions from the combustion of biomass and all fugitive releases of GHG emissions from biomass, calculated as provided in the calculation methods referenced in Table 120-1.

(iii) Sum the emissions estimates for each GHG and calculate metric tons of CO2e using Equation A-1 of this subsection.

(2) Supplier reporting. Beginning with the 2022 emissions year reported in 2023 reporting is mandatory for an owner or operator of any supplier with total GHG emissions in Washington that exceed the reporting threshold defined in (a) of this subsection. GHG emissions from all applicable source categories listed in WAC 173-441-122 from the supplier must be included when determining whether emissions from the supplier meet the reporting threshold.

(a) Supplier reporting threshold. Any supplier that produces, imports, or delivers 10,000 metric tons CO2e or more per calendar year in total GHG emissions from all applicable source categories listed in WAC 173-441-122 exceeds the reporting threshold.

(b) Calculating supplier emissions for comparison to the threshold. To calculate GHG emissions for comparison to the reporting threshold, the owner or operator must:

(i) Calculate the total annual emissions of each GHG in metric tons from all applicable source categories that are listed and defined in WAC 173-441-122. The GHG emissions must be calculated using the calculation methodologies specified in WAC 173-441-122 and available company records. Supplied CO2 is considered emissions.

(ii) Include emissions of all GHGs that are listed in Table A-1 of WAC 173-441-040, including all GHG emissions from the combustion of biomass, calculated as provided in the calculation methods referenced in WAC 173-441-122.

(iii) Sum the emissions estimates for each GHG and calculate metric tons of CO2e using Equation A-1 of this section.

(3) Electric power entity reporting. Beginning with the 2022 emissions year reported in 2023 reporting is mandatory for an owner or operator of any electric power entity with total GHG emissions that exceed the reporting threshold defined in (a) of this subsection. GHG emissions from all applicable source categories listed in WAC 173-441-124 from the electric power entity must be included when determining whether emissions from the electric power entity meet the reporting threshold.

(a) Electric power entity reporting threshold. Any electric power entity that imports or delivers 10,000 metric tons CO2e or more per calendar year in total GHG emissions from all applicable source categories listed in WAC 173-441-124 exceeds the reporting threshold.

(b) Calculating electric power entity emissions for comparison to the threshold. To calculate GHG emissions for comparison to the reporting threshold, the owner or operator must:

(i) Calculate the total annual emissions of each GHG in metric tons from all applicable source categories that are listed and defined in WAC 173-441-124. The GHG emissions must be calculated using the calculation methodologies specified in WAC 173-441-124 and available company records.

(ii) Include emissions of all GHGs that are listed in Table A-1 of WAC 173-441-040, including all GHG emissions from the combustion of biomass, calculated as provided in the calculation methods referenced in WAC 173-441-124.

(iii) Sum the emissions estimates for each GHG and calculate metric tons of CO2e using Equation A-1 of this section.

(4) Applicability over time. A person that does not meet the applicability requirements of subsection (1), (2), or (3) of this section is not subject to this rule. Such a person would become subject to the rule and the reporting requirements of this chapter if they exceed the applicability requirements of subsection (1), (2), or (3) of this section at a later time. Thus, persons should reevaluate the applicability to this chapter (including the revising of any relevant emissions calculations or other calculations) whenever there is any change that could cause a reporter to meet the applicability requirements of subsection (1), (2), or (3) of this section. Such changes include, but are not limited to, process modifications, increases in operating hours, increases in production, changes in fuel or raw material use, addition of equipment, facility expansion, and changes to this chapter.

(5) Voluntary reporting. A person may choose to voluntarily report to ecology GHG emissions that are not required to be reported under subsection (1), (2), or (3) of this section. Persons voluntarily reporting GHG emissions must use the methods established in WAC 173-441-120(3), 173-441-122 (1)(c), and 173-441-124 (1)(c) to calculate any voluntarily reported GHG emissions.

(6) Reporting requirements when emissions of greenhouse gases fall below reporting thresholds. Except as provided in this subsection, once a reporter is subject to the requirements of this chapter, the person must continue for each year thereafter to comply with all requirements of this chapter, including the requirement to submit annual GHG reports (annual GHG reports, GHG report, emissions report, annual report), even if the reporter does not meet the applicability requirements in subsection (1), (2), or (3) of this section in a future year. Reporters with a compliance obligation under chapter 70A.65 RCW, as described in chapter 173-446 WAC must continue to report for any year with a compliance obligation.

(a) If reported emissions are less than 10,000 metric tons CO2e per year for five consecutive years, then the person may discontinue reporting as required by this chapter provided that the person submits a notification to ecology that announces the cessation of reporting and explains the reasons for the reduction in emissions. The notification must be submitted no later than the report submission due date, specified in WAC 173-441-050(2), of the year immediately following the fifth consecutive year of emissions less than 10,000 tons CO2e per year. The person must maintain the corresponding records required under WAC 173-441-050(6) for each of the five consecutive years and retain such records for 10 years following the year that reporting was discontinued. The person must resume reporting if annual emissions in any future calendar year increase above the thresholds in subsection (1) or (2) of this section.

(b) If reported emissions are less than five thousand metric tons CO2e per year for three consecutive years, then the person may discontinue reporting as required by this chapter provided that the person submits a notification to ecology that announces the cessation of reporting and explains the reasons for the reduction in emissions. The notification must be submitted no later than the report submission due date, specified in WAC 173-441-050(2), of the year immediately following the third consecutive year of emissions less than 5,000 tons CO2e per year. The person must maintain the corresponding records required under WAC 173-441-050(6) for each of the three consecutive years and retain such records for 10 years following the year that reporting was discontinued. The person must resume reporting if annual emissions in any future calendar year increase above the thresholds in subsection (1) or (2) of this section. This provision does not apply to electric power entities.

(c) If the operations of a reporter are changed such that all applicable GHG-emitting processes and operations listed in WAC 173-441-120, 173-441-122, and 173-441-124 cease to operate, then the person is exempt from reporting in the years following the year in which cessation of such operations occurs, provided that the person submits a notification to ecology that announces the cessation of reporting and certifies to the closure of all GHG-emitting processes and operations no later than the report submission due date, specified in WAC 173-441-050(2), of the year following such changes. This provision does not apply to seasonal or other temporary cessation of operations. This provision does not apply to facilities with municipal solid waste landfills, industrial waste landfills, or to underground coal mines. The person must resume reporting for any future calendar year during which any of the GHG-emitting processes or operations resume operation.

(1) Greenhouse gases. Table A-1 of this section lists the GHGs regulated under this chapter and their global warming potentials.

(2) CO2e conversion. Use Equation A-1 of WAC 173-441-030 (1)(b)(iii) and the global warming potentials (GWP) listed in Table A-1 of this section to convert emissions into CO2e.

Persons subject to the requirements of this chapter must submit GHG reports to ecology, as specified in this section. Every metric ton of CO2e emitted by a reporter required to report under this chapter and covered under any applicable source category listed in WAC 173-441-120, 173-441-122, or 173-441-124 must be included in the report.

(1) General. Follow the procedures for emission calculation, monitoring, quality assurance, missing data, recordkeeping, and reporting that are specified in each relevant section of this chapter.

(2) Schedule. The annual GHG report must be submitted as follows:

(a) Report submission due date:

(i) A person required to report or voluntarily reporting GHG emissions under WAC 173-441-030 must submit the report required under this chapter to ecology no later than March 31st of each calendar year for GHG emissions in the previous calendar year. Electric power entities reporting under WAC 173-441-124 must submit a report based on best available information by March 31st. Electric power entities reporting under WAC 173-441-124 must submit a final revised report by June 1st of each calendar year for GHG emissions in the previous calendar year consistent with deadlines for electric power entities in external GHG emissions trading programs.

(ii)

Unless otherwise stated, if the final day of any time period falls on a weekend or a state holiday, the time period shall be extended to the next business day.

(b) Reporting requirements begin:

(i) For an existing reporter that began operation before January 1, 2012, report emissions for calendar year 2012 and each subsequent calendar year.

(ii) For a new reporter that begins operation on or after January 1, 2012, and becomes subject to the rule in the year that it becomes operational, report emissions beginning with the first operating month and ending on December 31st of that year. Each subsequent annual report must cover emissions for the calendar year, beginning on January 1st and ending on December 31st.

(iii) For any reporter that becomes subject to this rule because of a physical or operational change that is made after January 1, 2012, report emissions for the first calendar year in which the change occurs.

(A) Reporters begin reporting with the first month of the change and ending on December 31st of that year. For a reporter that becomes subject to this rule solely because of an increase in hours of operation or level of production, the first month of the change is the month in which the increased hours of operation or level of production, if maintained for the remainder of the year, would cause the reporter to exceed the applicable threshold.

(B) Suppliers and electric power entities begin reporting January 1st and ending on December 31st the year of the change.

(C) For all reporters, each subsequent annual report must cover emissions for the calendar year, beginning on January 1st and ending on December 31st.

(3) Content of the annual report. Each annual GHG report must contain the following information. All reported information is subject to verification by ecology as described in subsection (5) of this section.

(a) Reporter name, reporter ID number, and physical street address of the reporter, including the city, state, and zip code. If the facility does not have a physical street address, then the facility must provide the latitude and longitude representing the geographic centroid or center point of facility operations in decimal degree format. This must be provided in a comma-delimited "latitude, longitude" coordinate pair reported in decimal degrees to at least four digits to the right of the decimal point.

(b) Year and months covered by the report.

(c) Date of submittal.

(d) For facilities, report annual emissions of each GHG (as defined in WAC 173-441-020) and each fluorinated heat transfer fluid, as follows:

(i) Annual emissions (including biogenic CO2) aggregated for all GHGs from all applicable source categories in WAC 173-441-120 and expressed in metric tons of CO2e calculated using Equation A-1 of WAC 173-441-030 (1)(b)(iii).

(ii) Annual emissions of biogenic CO2 aggregated for all applicable source categories in WAC 173-441-120, expressed in metric tons.

(iii) Annual emissions from each applicable source category in WAC 173-441-120, expressed in metric tons of each applicable GHG listed in (d)(iii)(A) through (F) of this subsection.

(A) Biogenic CO2.

(B) CO2 (including biogenic CO2).

(C) CH4.

(D) N2O.

(E) Each fluorinated GHG.

(F) For electronics manufacturing each fluorinated heat transfer fluid that is not also a fluorinated GHG as specified under WAC 173-441-040.

(iv) Emissions and other data for individual units, processes, activities, and operations as specified in the "data reporting requirements" section of each applicable source category referenced in WAC 173-441-120.

(v) Indicate (yes or no) whether reported emissions include emissions from a cogeneration unit located at the facility.

(vi) When applying (d)(i) of this subsection to fluorinated GHGs and fluorinated heat transfer fluids, calculate and report CO2e for only those fluorinated GHGs and fluorinated heat transfer fluids listed in WAC 173-441-040.

(vii) For reporting year 2014 and thereafter, you must enter into verification software specified by the director the data specified in the verification software records provision in each applicable recordkeeping section. For each data element entered into the verification software, if the software produces a warning message for the data value and you elect not to revise the data value, you may provide an explanation in the verification software of why the data value is not being revised. Whenever the use of verification software is required or voluntarily used, the file generated by the verification software must be submitted with the facility's annual GHG report.

(e) For suppliers and electric power entities, report annual emissions of each GHG (as defined in WAC 173-441-020) as follows:

(i) Annual emissions (including biogenic CO2) aggregated for all GHGs from all applicable source categories in WAC 173-441-122 and 173-441-124 and expressed in metric tons of CO2e calculated using Equation A-1 of WAC 173-441-030 (1)(b)(iii).

(ii) Annual emissions of biogenic CO2 aggregated for all applicable source categories in WAC 173-441-122 and 173-441-124, expressed in metric tons.

(iii) Annual emissions from each applicable source category in WAC 173-441-122 and 173-441-124, expressed in metric tons of each applicable GHG listed in subsection (3)(d)(iii)(A) through (E) of this section.

(A) Biogenic CO2.

(B) CO2 (including biogenic CO2).

(C) CH4.

(D) N2O.

(E) Each fluorinated GHG.

(iv) Emissions and other data for individual units, processes, activities, and operations as specified in the "data reporting requirements" section of each applicable source category referenced in WAC 173-441-122 and 173-441-124.

(f) A written explanation, as required under subsection (4) of this section, if you change emission or product data calculation methodologies during the reporting period or since the previous reporting period.

(g) Each data element for which a missing data procedure was used according to the procedures of an applicable subpart referenced in WAC 173-441-120, 173-441-122, or 173-441-124 and the total number of hours in the year that a missing data procedure was used for each data element.

(h) A signed and dated certification statement provided by the designated representative of the owner or operator, according to the requirements of WAC 173-441-060 (5)(a).

(i) NAICS code(s) that apply to the reporter. NAICS codes are subject to approval by ecology.

(i) Primary NAICS code. Report the NAICS code that most accurately describes the reporter's primary product/activity/service. The primary product/activity/service is the principal source of revenue for the reporter. A reporter that has two distinct products/activities/services providing comparable revenue may report a second primary NAICS code.

(ii) Additional NAICS code(s). Report all additional NAICS codes that describe all product(s)/activity(s)/service(s) at the reporter that are not related to the principal source of revenue.

(j) Legal name(s) and physical address(es) of the highest-level United States parent company(s) of the owners (or operators) of the reporter and the percentage of ownership interest for each listed parent company as of December 31st of the year for which data are being reported according to the following instructions.

(i) If the reporter is entirely owned by a single United States company that is not owned by another company, provide that company's legal name and physical address as the United States parent company and report 100 percent ownership.

(ii) If the reporter is entirely owned by a single United States company that is, itself, owned by another company (e.g., it is a division or subsidiary of a higher-level company), provide the legal name and physical address of the highest-level company in the ownership hierarchy as the United States parent company and report 100 percent ownership.

(iii) If the reporter is owned by more than one United States company (e.g., company A owns 40 percent, company B owns 35 percent, and company C owns 25 percent), provide the legal names and physical addresses of all the highest-level companies with an ownership interest as the United States parent companies and report the percent ownership of each company.

(iv) If the reporter is owned by a joint venture or a cooperative, the joint venture or cooperative is its own United States parent company. Provide the legal name and physical address of the joint venture or cooperative as the United States parent company, and report 100 percent ownership by the joint venture or cooperative.

(v) If the reporter is entirely owned by a foreign company, provide the legal name and physical address of the foreign company's highest-level company based in the United States as the United States parent company, and report 100 percent ownership.

(vi) If the reporter is partially owned by a foreign company and partially owned by one or more United States companies, provide the legal name and physical address of the foreign company's highest-level company based in the United States, along with the legal names and physical addresses of the other United States parent companies, and report the percent ownership of each of these companies.

(vii) If the reporter is a federally owned facility, report "U.S. Government" and do not report physical address or percent ownership.

(k) An indication of whether the facility includes one or more plant sites that have been assigned a "plant code" by either the Department of Energy's Energy Information Administration or by the Environmental Protection Agency's (EPA) Clean Air Markets Division.

(l) Facilities must report electricity information including:

(i) Total annual electricity purchased in megawatt hours (MWh), itemized by the supplying utility or, if not obtained from a utility, from the supplying electric power entity for each different source of electricity. Total annual purchases must be reported separately for each supplying utility or electric power entity.

(ii) Self-generated electricity should be itemized separately if a facility includes an electricity generating unit as follows:

(A) Total facility nameplate generating capacity in megawatts (MW).

(B) Generated electricity in MWh provided or sold to each retail provider, electricity marketer, or other reportable end-user that is not a part of the facility, itemized by end-user.

(C) Generated electricity for on-site industrial applications not related to electricity generation in MWh.

(m) Report fuel use or supplied as follows:

(i) Facilities, report each fuel combusted separately by type, quantity, and units of measurement.

(ii) Fuel suppliers, report:

(A) Each fuel supplied separately by type, quantity, and units of measurement; and

(B) Separately report the quantity of each fuel type by purpose if the fuel supplier reports that the fuel is used for one of the purposes described in WAC 173-441-122 (5)(d)(xi).

(n) Facilities, report total annual facility product data, units of production, and specific product based on their first primary NAICS code.

(i) Facilities with a primary NAICS code listed in Table 050-1 of this section must report total annual facility product data as described in Table 050-1. Facilities may additionally report total annual facility product data as described in Table 050-1 for any reported secondary NAICS code. Use six digit NAICS codes when available, otherwise use the shorter NAICS codes listed below substituting the values in the full reported six digit NAICS code for "X".

(ii) Facilities without a primary NAICS code listed in Table 050-1 of this section must contact ecology no later than 45 calendar days prior to the emissions report deadline established in subsection (2) of this section and report total annual facility product data as instructed by the department. If ecology does not identify product data for a facility, a facility must use the energy-based calculation method described in Equation 050-1 of this section. Report product data and inputs to the equation. Product data calculated using the energy-based method shall use the following equation:

(iii) Facilities with a change in operation that alters either their primary NAICS code, units of production, or product data measurement method must contact ecology no later than 45 calendar days prior to the emissions report deadline established in subsection (2) of this section and report total annual facility product data as instructed by the department. If ecology does not identify product data for a facility, a facility must use the energy-based calculation method described in Equation 050-1 of this section. Report product data and inputs to the equation.

(iv) For a primary NAICS code in Table 050-1 that has multiple production metrics, a facility that wishes to change their reported production metric must contact ecology no later than 45 calendar days prior to the emissions report deadline established in subsection (2) of this section and report total annual facility production data as instructed by the department.

(o) Reporters that cease operation, other than routine maintenance or seasonal shutdowns, for more than 90 calendar days must provide the following information:

(i) The anticipated type of cessation: Closure or curtailment;

(ii) Date cessation began;

(iii) Date cessation ended (if applicable); and

(iv) Reason for cessation and/or resumption of operation.

(p) If there is an increase or decrease of more than five percent in emissions of greenhouse gases in relation to the previous year, the reporter must provide a brief narrative description of what caused the increase or decrease in emissions.

(4) Emission calculations. In preparing the GHG report, you must use the calculation methodologies specified in the relevant sections of this chapter. For each source category, you must use the same calculation methodology as previous reports. This includes throughout a reporting period, and between reporting years. An owner or operator intending to change methodologies must provide a written explanation at least 60 calendar days before the report submission due date in subsection (2)(a) of this section of why a change in methodology was required. Ecology has 45 calendar days to approve or reject the change in method. The reporter must continue to use existing methods until the change is approved by ecology.

(5) Verification. To verify the completeness and accuracy of reported GHG emissions, ecology may review the certification statements described in subsection (3)(h) of this section and any other credible evidence, in conjunction with a comprehensive review of the GHG reports and periodic audits of selected reporting facilities. Nothing in this section prohibits ecology from using additional information to verify the completeness and accuracy of the reports. Reporters must cooperate with ecology's efforts to verify GHG reports.

(6) Recordkeeping. A person that is required to report GHGs under this chapter must keep records as specified in this subsection. Retain all required records for at least 10 years from the date of submission of the annual GHG report for the reporting year in which the record was generated. Upon request by ecology, the person must submit the records required under this section within 15 business days of receipt of the notification, unless a different schedule is agreed to by ecology. Records may be retained off-site if the records are readily available for expeditious inspection and review. For records that are electronically generated or maintained, the equipment or software necessary to read the records must be made available, or, if requested by ecology, electronic records must be converted to paper documents. You must retain the following records, in addition to those records prescribed in each applicable section of this chapter:

(a) A list of all units, operations, processes, and activities for which GHG emissions were calculated.

(b) The data used to calculate the GHG emissions for each unit, operation, process, and activity, categorized by fuel or material type. These data include, but are not limited to, the following information:

(i) The GHG emissions calculations and methods used.

(ii) Analytical results for the development of site-specific emissions factors.

(iii) The results of all required analyses for high heat value, carbon content, and other required fuel or feedstock parameters.

(iv) Any facility operating data or process information used for the GHG emission calculations.

(c) The annual GHG reports.

(d) Missing data computations. For each missing data event, also retain a record of the cause of the event and the corrective actions taken to restore malfunctioning monitoring equipment.

(e) Owners or operators required to report under WAC 173-441-030 must keep a written GHG monitoring plan (monitoring plan, plan).

(i) At a minimum, the GHG monitoring plan must include the following elements:

(A) Identification of positions of responsibility (i.e., job titles) for collection of the emissions data.

(B) Explanation of the processes and methods used to collect the necessary data for the GHG calculations.

(C) Description of the procedures and methods that are used for quality assurance, maintenance, and repair of all continuous monitoring systems, flow meters, and other instrumentation used to provide data for the GHGs reported under this chapter.

(D) Facilities must reference to one or more simplified block diagrams that provide a clear visual representation of the relative locations and positions of measurement devices and sampling locations, as applicable, required for calculating covered emissions and covered product data (e.g., temperature, total pressure, HHV, fuel consumption). The diagram(s) must include fuel sources, combustion units, and production processes, as applicable.

(ii) The GHG monitoring plan may rely on references to existing corporate documents (e.g., standard operating procedures, quality assurance programs under appendix F to 40 C.F.R. Part 60 or appendix B to 40 C.F.R. Part 75, and other documents) provided that the elements required by (e)(i) of this subsection are easily recognizable.

(iii) The owner or operator must revise the GHG monitoring plan as needed to reflect changes in production processes, monitoring instrumentation, and quality assurance procedures; or to improve procedures for the maintenance and repair of monitoring systems to reduce the frequency of monitoring equipment downtime.

(iv) Upon request by ecology, the owner or operator must make all information that is collected in conformance with the GHG monitoring plan available for review during an audit within 15 business days of receipt of the notification, unless a different schedule is agreed to by ecology. Electronic storage of the information in the plan is permissible, provided that the information can be made available in hard copy upon request during an audit.

(f) The results of all required certification and quality assurance tests of continuous monitoring systems, fuel flow meters, and other instrumentation used to provide data for the GHGs reported under this chapter.

(g) Maintenance records for all continuous monitoring systems, flow meters, and other instrumentation used to provide data for the GHGs reported under this chapter.

(h) Suppliers and electric power entities must retain any other data specified in WAC 173-441-122 and 173-441-124.

(7) Annual GHG report revisions.

(a) A person must submit a revised annual GHG report within 45 calendar days of discovering that an annual GHG report that the person previously submitted contains one or more substantive errors. The revised report must correct all substantive errors.

(b) Ecology may notify the person in writing that an annual GHG report previously submitted by the person contains one or more substantive errors. Such notification will identify each such substantive error. The person must, within 45 calendar days of receipt of the notification, either resubmit the report that, for each identified substantive error, corrects the identified substantive error (in accordance with the applicable requirements of this chapter) or provide information demonstrating that the previously submitted report does not contain the identified substantive error or that the identified error is not a substantive error.

(c) A substantive error is an error that impacts the quantity of GHG emissions reported, product data reported, or otherwise prevents the reported data from being validated or verified.

(d) Notwithstanding (a) and (b) of this subsection, upon request by a person, ecology may provide reasonable extensions of the 45-day period for submission of the revised report or information under (a) and (b) of this subsection. If ecology receives a request for extension of the 45-day period, by email, at least five business days prior to the expiration of the 45 calendar day period, and ecology does not respond to the request by the end of such period, the extension request is deemed to be automatically granted for 15 more calendar days. During the automatic 15-day extension, ecology will determine what extension, if any, beyond the automatic extension is reasonable and will provide any such additional extension.

(e) The owner or operator must retain documentation for 10 years to support any revision made to an annual GHG report.

(8) Calibration and accuracy requirements. The owner or operator of a facility that is subject to the requirements of this chapter must meet the applicable flow meter calibration and accuracy requirements of this subsection. The accuracy specifications in this subsection do not apply where either the use of company records (as defined in WAC 173-441-020(3)) or the use of "best available information" is specified in an applicable subsection of this chapter to quantify fuel usage and/or other parameters. Further, the provisions of this subsection do not apply to stationary fuel combustion units that use the methodologies in 40 C.F.R. Part 75 to calculate CO2 mass emissions. Measurement devices used for financial transactions between two or more independent parties meet the calibration and accuracy requirements of this chapter.

(a) Except as otherwise provided in (d) through (f) of this subsection, flow meters that measure liquid and gaseous fuel feed rates, process stream flow rates, product data measuring devices, or feedstock flow rates and provide data for the GHG emissions calculations or product data, must be calibrated prior to January 1, 2012, for emissions data or January 1, 2023, for product data, using the procedures specified in this subsection when such calibration is specified in a relevant section of this chapter. Each of these flow meters must meet the applicable accuracy specification in (b) or (c) of this subsection. All other measurement devices (e.g., weighing devices) that are required by a relevant subsection of this chapter, and that are used to provide data for the GHG emissions calculations or product data, must also be calibrated prior to January 1, 2012, for emissions data or January 1, 2023, for product data; however, the accuracy specifications in (b) and (c) of this subsection do not apply to these devices. Rather, each of these measurement devices must be calibrated to meet the accuracy requirement specified for the device in the applicable subsection of this chapter, or, in the absence of such accuracy requirement, the device must be calibrated to an accuracy within the appropriate error range for the specific measurement technology, based on an applicable operating standard including, but not limited to, manufacturer's specifications and industry standards. The procedures and methods used to quality-assure the data from each measurement device must be documented in the written monitoring plan, pursuant to subsection (6)(e)(i)(C) of this section.

(i) All flow meters and other measurement devices that are subject to the provisions of this subsection must be calibrated according to one of the following: You may use the manufacturer's recommended procedures; an appropriate industry consensus standard method; or a method specified in a relevant section of this chapter. The calibration method(s) used must be documented in the monitoring plan required under subsection (6)(e) of this section.

(ii) For reporters that become subject to this chapter after January 1, 2012, all flow meters and other measurement devices (if any) that are required by the relevant subsection(s) of this chapter to provide data for the GHG emissions calculations or product data must be installed no later than the date on which data collection is required to begin using the measurement device, and the initial calibration(s) required by this subsection (if any) must be performed no later than that date.

(iii) Except as otherwise provided in (d) through (f) of this subsection, subsequent recalibrations of the flow meters and other measurement devices subject to the requirements of this subsection must be performed at one of the following frequencies:

(A) You may use the frequency specified in each applicable subsection of this chapter.

(B) You may use the frequency recommended by the manufacturer or by an industry consensus standard practice, if no recalibration frequency is specified in an applicable subsection.

(b) Perform all flow meter calibration at measurement points that are representative of the normal operating range of the meter. Except for the orifice, nozzle, and venturi flow meters described in (c) of this subsection, calculate the calibration error at each measurement point using Equation A–2 of this subsection. The terms "R" and "A" in Equation A–2 must be expressed in consistent units of measure (e.g., gallons/minute, ft3/min). The calibration error at each measurement point must not exceed 5.0 percent of the reference value.

(c) For orifice, nozzle, and venturi flow meters, the initial quality assurance consists of in situ calibration of the differential pressure (delta-P), total pressure, and temperature transmitters.

(i) Calibrate each transmitter at a zero point and at least one upscale point. Fixed reference points, such as the freezing point of water, may be used for temperature transmitter calibrations. Calculate the calibration error of each transmitter at each measurement point, using Equation A–3 of this subsection. The terms "R," "A," and "FS" in Equation A–3 of this subsection must be in consistent units of measure (e.g., milliamperes, inches of water, psi, degrees). For each transmitter, the CE value at each measurement point must not exceed 2.0 percent of full-scale. Alternatively, the results are acceptable if the sum of the calculated CE values for the three transmitters at each calibration level (i.e., at the zero level and at each upscale level) does not exceed 6.0 percent.

(ii) In cases where there are only two transmitters (i.e., differential pressure and either temperature or total pressure) in the immediate vicinity of the flow meter's primary element (e.g., the orifice plate), or when there is only a differential pressure transmitter in close proximity to the primary element, calibration of these existing transmitters to a CE of 2.0 percent or less at each measurement point is still required, in accordance with (c)(i) of this subsection; alternatively, when two transmitters are calibrated, the results are acceptable if the sum of the CE values for the two transmitters at each calibration level does not exceed 4.0 percent. However, note that installation and calibration of an additional transmitter (or transmitters) at the flow monitor location to measure temperature or total pressure or both is not required in these cases. Instead, you may use assumed values for temperature and/or total pressure, based on measurements of these parameters at a remote location (or locations), provided that the following conditions are met:

(A) You must demonstrate that measurements at the remote location(s) can, when appropriate correction factors are applied, reliably and accurately represent the actual temperature or total pressure at the flow meter under all expected ambient conditions.

(B) You must make all temperature and/or total pressure measurements in the demonstration described in (c)(ii)(A) of this subsection with calibrated gauges, sensors, transmitters, or other appropriate measurement devices. At a minimum, calibrate each of these devices to an accuracy within the appropriate error range for the specific measurement technology, according to one of the following: You may calibrate using a manufacturer's specification or an industry consensus standard.

(C) You must document the methods used for the demonstration described in (c)(ii)(A) of this subsection in the written GHG monitoring plan under subsection (6)(e)(i)(C) of this section. You must also include the data from the demonstration, the mathematical correlation(s) between the remote readings and actual flow meter conditions derived from the data, and any supporting engineering calculations in the GHG monitoring plan. You must maintain all of this information in a format suitable for auditing and inspection.

(D) You must use the mathematical correlation(s) derived from the demonstration described in (c)(ii)(A) of this subsection to convert the remote temperature or the total pressure readings, or both, to the actual temperature or total pressure at the flow meter, or both, on a daily basis. You must then use the actual temperature and total pressure values to correct the measured flow rates to standard conditions.

(E) You must periodically check the correlation(s) between the remote and actual readings (at least once a year), and make any necessary adjustments to the mathematical relationship(s).

(d) Fuel billing meters are exempted from the calibration requirements of this section and from the GHG monitoring plan and recordkeeping provisions of subsection (6)(e)(i)(C) and (g) of this section, provided that the fuel supplier and any unit combusting the fuel do not have any common owners and are not owned by subsidiaries or affiliates of the same company. Meters used exclusively to measure the flow rates of fuels that are used for unit startup are also exempted from the calibration requirements of this section.

(e) For a flow meter that has been previously calibrated in accordance with (a) of this subsection, an additional calibration is not required by the date specified in (a) of this subsection if, as of that date, the previous calibration is still active (i.e., the device is not yet due for recalibration because the time interval between successive calibrations has not elapsed). In this case, the deadline for the successive calibrations of the flow meter must be set according to one of the following: You may use either the manufacturer's recommended calibration schedule or you may use the industry consensus calibration schedule.

(f) For units and processes that operate continuously with infrequent outages, it may not be possible to meet the deadline established in (a) of this subsection for the initial calibration of a flow meter or other measurement device without disrupting normal process operation. In such cases, the owner or operator may postpone the initial calibration until the next scheduled maintenance outage. The best available information from company records may be used in the interim. The subsequent required recalibrations of the flow meters may be similarly postponed. Such postponements must be documented in the monitoring plan that is required under subsection (6)(e) of this section.

(g) If the results of an initial calibration or a recalibration fail to meet the required accuracy specification, data from the flow meter must be considered invalid, beginning with the hour of the failed calibration and continuing until a successful calibration is completed. You must follow the missing data provisions provided in the relevant missing data sections during the period of data invalidation.

(h) Missing data substitution procedures. Persons must comply with 40 C.F.R. Part 98 when substituting for missing data. Substitute missing data used for product data or other data required under this section that is not included in your 40 C.F.R. Part 98 report by using the best available estimate of the parameter, based on all available data.

(9) Measurement device installation. 40 C.F.R. § 98.3(j) and 40 C.F.R. § 98.3(d) are adopted by reference as modified in WAC 173-441-120(2).

(1) General. Except as provided under subsection (6) of this section, each reporter that is subject to this chapter, must have one and only one designated representative, who must be responsible for certifying, signing, and submitting GHG emissions reports and any other submissions for such reporter respectively to ecology under this chapter. If the reporter is required to submit a GHG emissions report to EPA under 40 C.F.R. Part 98, that designated representative must also be the designated representative responsible for certifying, signing, and submitting GHG emissions reports to ecology under this chapter.

(2) Authorization of a designated representative. The designated representative of the reporter must be an individual selected by an agreement binding on the owners and operators of such reporter and must act in accordance with the certification statement in subsection (9)(d) of this section.

(3) Responsibility of the designated representative. Upon receipt by ecology of a complete certificate of representation under this section for a reporter, the designated representative identified in such certificate of representation must represent and, by his or her representations, actions, inactions, or submissions, legally bind each owner and operator of such reporter in all matters pertaining to this chapter, notwithstanding any agreement between the designated representative and such owners and operators. The owners and operators must be bound by any decision or order issued to the designated representative by ecology, pollution control hearings board, or a court.

(4) Timing. No GHG emissions report or other submissions under this chapter for a reporter will be accepted until ecology has received a complete certificate of representation under this section for a designated representative of the reporter. Such certificate of representation must be submitted at least 60 calendar days before the deadline for submission of the reporter's initial emission report under this chapter.

(5) Certification of the GHG emissions report. Each GHG emission report and any other submission under this chapter for a reporter must be certified, signed, and submitted by the designated representative or any alternate designated representative of the reporter in accordance with this section and 40 C.F.R. § 3.10 as adopted on October 13, 2005.

(a) Each such submission must include the following certification statement signed by the designated representative or any alternate designated representative: "I am authorized to make this submission on behalf of the owners and operators of the reporter, as applicable, 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."

(b) Ecology will accept a GHG emission report or other submission for a reporter under this chapter only if the submission is certified, signed, and submitted in accordance with this section.

(6) Alternate designated representative. A certificate of representation under this section for a reporter may designate one alternate designated representative, who must be an individual selected by an agreement binding on the owners and operators, and may act on behalf of the designated representative, of such reporter. The agreement by which the alternate designated representative is selected must include a procedure for authorizing the alternate designated representative to act in lieu of the designated representative.

(a) Upon receipt by ecology of a complete certificate of representation under this section for a reporter identifying an alternate designated representative:

(i) The alternate designated representative may act on behalf of the designated representative for such reporter.

(ii) Any representation, action, inaction, or submission by the alternate designated representative must be deemed to be a representation, action, inaction, or submission by the designated representative.

(b) Except in this section, whenever the term "designated representative" is used in this chapter, the term must be construed to include the designated representative or any alternate designated representative.

(7) Changing a designated representative or alternate designated representative. The designated representative or alternate designated representative identified in a complete certificate of representation under this section for a reporter received by ecology may be changed at any time upon receipt by ecology of another later signed, complete certificate of representation under this section for the reporter. Notwithstanding any such change, all representations, actions, inactions, and submissions by the previous designated representative or the previous alternate designated representative of the reporter before the time and date when ecology receives such later signed certificate of representation must be binding on the new designated representative and the owners and operators of the reporter.

(8) Changes in owners and operators. In the event an owner or operator of the reporter is not included in the list of owners and operators in the certificate of representation under this section for the reporter, such owner or operator must be deemed to be subject to and bound by the certificate of representation, the representations, actions, inactions, and submissions of the designated representative and any alternate designated representative of the reporter, as if the owner or operator were included in such list. Within 90 calendar days after any change in the owners and operators of the reporter (including the addition of a new owner or operator), the designated representative or any alternate designated representative must submit a certificate of representation that is complete under this section except that such list must be amended to reflect the change. If the designated representative or alternate designated representative determines at any time that an owner or operator of the reporter is not included in such list and such exclusion is not the result of a change in the owners and operators, the designated representative or any alternate designated representative must submit, within 90 calendar days of making such determination, a certificate of representation that is complete under this section except that such list must be amended to include such owner or operator.

(9) Certificate of representation. A certificate of representation shall be complete if it includes the following elements in a format prescribed by ecology in accordance with this section:

(a) Identification of the reporter for which the certificate of representation is submitted.

(b) The name, organization name (company affiliation-employer), address, email address (if any), telephone number, and facsimile transmission number (if any) of the designated representative and any alternate designated representative.

(c) A list of the owners and operators of the reporter identified in (a) of this subsection, provided that, if the list includes the operators of the reporter and the owners with control of the reporter, the failure to include any other owners must not make the certificate of representation incomplete.

(d) The following certification statements by the designated representative and any alternate designated representative:

(i) "I certify that I was selected as the designated representative or alternate designated representative, as applicable, by an agreement binding on the owners and operators of the facility, supplier, or electric power entity, as applicable."

(ii) "I certify that I have all the necessary authority to carry out my duties and responsibilities under chapter 173-441 WAC on behalf of the owners and operators of the facility, supplier, or electric power entity, as applicable, and that each such owner and operator must be fully bound by my representations, actions, inactions, or submissions."

(iii) "I certify that the owners and operators of the facility, supplier, or electric power entity, as applicable, must be bound by any order issued to me by ecology, the pollution control hearings board, or a court regarding the reporter."

(iv) "If there are multiple owners and operators of the facility or multiple suppliers, as applicable, I certify that I have given a written notice of my selection as the 'designated representative' or 'alternate designated representative,' as applicable, and of the agreement by which I was selected to each owner and operator of the facility and each supplier."

(e) The signature of the designated representative and any alternate designated representative and the dates signed.

(10) Documents of agreement. Unless otherwise required by ecology, documents of agreement referred to in the certificate of representation shall not be submitted to ecology. Ecology shall not be under any obligation to review or evaluate the sufficiency of such documents, if submitted.

(11) Binding nature of the certificate of representation. Once a complete certificate of representation under this section for a reporter has been received, ecology will rely on the certificate of representation unless and until a later signed, complete certificate of representation under this section for the reporter is received by ecology.

(12) Objections concerning a designated representative.

(a) Except as provided in subsection (7) of this section, no objection or other communication submitted to ecology concerning the authorization, or any representation, action, inaction, or submission, of the designated representative or alternate designated representative must affect any representation, action, inaction, or submission of the designated representative or alternate designated representative, or the finality of any decision or order by ecology under this chapter.

(b) Ecology will not adjudicate any private legal dispute concerning the authorization or any representation, action, inaction, or submission of any designated representative or alternate designated representative.

(13) Delegation by designated representative and alternate designated representative.

(a) A designated representative or an alternate designated representative may delegate his or her own authority, to one or more individuals, to submit an electronic submission to ecology provided for or required under this chapter, except for a submission under this subsection.

(b) In order to delegate his or her own authority, to one or more individuals, to submit an electronic submission to ecology in accordance with (a) of this subsection, the designated representative or alternate designated representative must submit electronically to ecology a notice of delegation, in a format prescribed by ecology, that includes the following elements:

(i) The name, organization name (company affiliation-employer), address, email address (if any), telephone number, and facsimile transmission number (if any) of such designated representative or alternate designated representative.

(ii) The name, address, email address, telephone number, and facsimile transmission number (if any) of each such individual (referred to as an "agent").

(iii) For each such individual, a list of the type or types of electronic submissions under (a) of this subsection for which authority is delegated to him or her.

(iv) For each type of electronic submission listed in accordance with subsection (13)(b)(iii) of this section, the reporter for which the electronic submission may be made.

(v) The following certification statements by such designated representative or alternate designated representative:

(A) "I agree that any electronic submission to ecology that is by an agent identified in this notice of delegation and of a type listed, and for a reporter designated, for such agent in this notice of delegation and that is made when I am a designated representative or alternate designated representative, as applicable, and before this notice of delegation is superseded by another notice of delegation under WAC 173-441-060 (13)(c) must be deemed to be an electronic submission certified, signed, and submitted by me."

(B) "Until this notice of delegation is superseded by a later signed notice of delegation under WAC 173-441-060 (13)(c), I agree to maintain an email account and to notify ecology immediately of any change in my email address unless all delegation of authority by me under WAC 173-441-060(13) is terminated."

(vi) The signature of such designated representative or alternate designated representative and the date signed.

(c) A notice of delegation submitted in accordance with (b) of this subsection must be effective, with regard to the designated representative or alternate designated representative identified in such notice, upon receipt of such notice by ecology and until receipt by ecology of another such notice that was signed later by such designated representative or alternate designated representative, as applicable. The later signed notice of delegation may replace any previously identified agent, add a new agent, or eliminate entirely any delegation of authority.

(d) Any electronic submission covered by the certification in (b)(v)(A) of this subsection and made in accordance with a notice of delegation effective under (c) of this subsection must be deemed to be an electronic submission certified, signed, and submitted by the designated representative or alternate designated representative submitting such notice of delegation.

The following must be submitted electronically in accordance with the requirements of WAC 173-441-050 and 173-441-060 and in a format specified by ecology.

(1) Facility reporters:

(a) GHG report;

(b) Certificate of representation; and

(c) Verification software file.

(2) Suppliers:

(a) GHG report; and

(b) Certificate of representation.

(3) Electric power entities:

(a) GHG report; and

(b) Certificate of representation.

(1) The materials incorporated by reference by EPA in 40 C.F.R. § 98.7, are incorporated by reference in this chapter for use in the sections of this chapter that correspond to the sections of 40 C.F.R. Part 98 referenced here.

(2) Table A–2 of this section provides a conversion table for some of the common units of measure used in this chapter.

Beginning with the 2023 emissions year reported in 2024, a person that emits 25,000 metric tons CO2e or more per calendar year in total GHG emissions as calculated using the methods in WAC 173-441-030 or has a mandatory or voluntary compliance obligation under chapter 70A.65 RCW, as described in chapter 173-446 WAC must have the reporter's annual GHG reports verified by a third party as specified in this section. Third-party verification requirements are in addition to other verification and report correction requirements in this chapter.

(1) Annual GHG reports must be third-party verified each emissions year that:

(a) The reporter emits 25,000 metric tons CO2e or more per calendar year in total GHG emissions as calculated using the methods in WAC 173-441-030;

(b) The reporter has a mandatory or voluntary compliance obligation under chapter 70A.65 RCW, as described in chapter 173-446 WAC;

(c) Is part of a baseline calculation or otherwise covered under chapter 70A.65 RCW, as described in chapter 173-446 WAC; or

(d) For the first year after no longer meeting the requirements of (a) through (c) of this subsection unless the operations of the reporter are changed such that all applicable GHG emitting processes and operations listed in WAC 173-441-120, 173-441-122, and 173-441-124 permanently cease to operate.

(2) Information subject to third-party verification. All GHG emissions and other information reported under this chapter are subject to the requirements of this section. Emissions factors published by ecology based on data previously reported under this chapter that received a positive verification statement would not need to be reverified; however, any calculations based on that information are subject to the requirements of this section.

(3) Verification standards. The third-party verifier must certify that annual GHG reports meet the following conditions:

(a) Annual GHG reports must be consistent with the relevant requirements and methods in this chapter.

(b) The absolute value of any discrepancy, omission, or misreporting, or aggregation of the three, must be less than five percent of total reported emissions (metric tons of CO2e) or the verification will result in a material misstatement and an adverse verification statement. This standard also separately applies to any product data in the annual GHG report.

(i) "Discrepancies" means any differences between the reported emissions or product data and the third-party verifier's review of emissions or product data for a data source or product data subject to this chapter.

(ii) "Omissions" means any emissions or product data the third-party verifier concludes must be part of the annual GHG report, but were not included by the reporting entity in the annual GHG report.

(iii) "Misreporting" means duplicate, incomplete or other emissions the third-party verifier concludes should, or should not, be part of the annual GHG report or duplicate or other product data the verifier concludes should not be part of the annual GHG report.

(iv) "Total reported emissions or product data" means the total annual reporter's emissions or total annual reporter's product data for which the third-party verifier is conducting an assessment.

(4) Verification services.

(a) Full verification is required at least once every three reporting years for reporters subject to third-party verification under subsection (1)(b) through (d) of this section. The first year of third-party verification for a reporter subject to third-party verification under subsection (1)(b) through (d) of this section must be full verification. A person required to conduct third-party verification under subsection (1)(b) through (d) of this section may choose to obtain less intensive verification services for the remaining two years in the three-year period as long as:

(i) No year in the three-year period has an adverse verification statement;

(ii) The third-party verifier can provide findings with a reasonable level of assurance;

(iii) There has not been a change in the third-party verifier;

(iv) There has not been a change in operational control of the reporter; and

(v) There has not been a significant change in sources or emissions. A difference in emissions of greater than 25 percent relative to the preceding year's emissions is considered significant unless that change can be directly shown to result from a verifiable change in product data.

(b) Full verification. A full verification report must be in a format specified by ecology and contain:

(i) Documentation identifying the reporter reporting emissions and the scope of emissions verified in the report.

(ii) Documentation identifying the third-party verifier, including all relevant information about the third-party verifier in subsection (7)(a) of this section and the names, roles, and sector specific qualifications (if any) of all individuals working on the verification report.

(iii) Documentation demonstrating and certifying that the requirements of subsection (7)(b) and (c) of this section have been met.

(iv) A verification plan that details the data and methodologies used to verify the annual GHG report and schedule describing when the verification services occurred. This must include a sampling plan that describes how the third-party verifier prioritized which emissions to verify and a summary of the data checks used to determine the reliability of the annual GHG report. Full verification requires a more complete sampling of data and additional data checks than less intensive verification. At a minimum, data checks for a full verification must include the following:

(A) Tracing data in the emissions data report to its origin;

(B) Reviewing the process for data compilation and collection;

(C) Recalculating emission estimates to check original calculations;

(D) Reviewing calculation methodologies used by the reporter for conformance with this chapter; and

(E) Reviewing meter and fuel analytical instrumentation measurement accuracy and calibration for consistency with the requirements of this chapter.

(v) Documentation of the third-party verifier's review of reporter operations to identify applicable GHG emissions sources and product data. Any applicable GHG emissions sources or product data not included in the annual GHG report must be identified. The third-party verifier must also ensure that the reported current NAICS code(s) accurately represents the activities on-site.

(vi) Documentation of any corrections made to the annual GHG report.

(vii) Documentation supporting the third-party verifiers' findings evaluating if the annual GHG report is compliant with the requirements in subsection (3) of this section. This must include a log of any issues (if any) identified in the course of verification, their potential impact on the quality of the annual GHG report, and their resolution.

(viii) The individuals conducting the third-party verification must certify that the verification report is true, accurate, and complete to the best of their knowledge and belief.

(ix) Information about the required on-site visit, including date(s) and a description of the verification services conducted on-site. At least one accredited verifier in the verification team, including the sector specific verifier, if applicable, must at a minimum make one site visit, during each year full verification is required. The third-party verifier must visit the headquarters or other location of central data management when the reporter is a supplier or electric power entity. During the site visit, the third-party verifier must:

(A) Confirm that all applicable emissions are included in the annual GHG report.

(B) Check that all sources specified in the annual GHG report are identified appropriately.

(C) Review and understand the data management systems used by the owners or operators to track, quantify, and report GHG emissions and, when applicable, product data and fuel transactions. The third-party verifier must evaluate the uncertainty and effectiveness of these systems.

(D) Interview key personnel.

(E) Make direct observations of equipment for data sources and equipment supplying data for sources determined to be high risk.

(F) Assess conformance with measurement accuracy, data capture, and missing data substitution requirements.

(G) Review financial transactions to confirm fuel, feedstock, and product data, and confirming the complete and accurate reporting of required data such as reporter fuel suppliers, fuel quantities delivered, and if fuel was received directly from an interstate pipeline.

(c) Less intensive verification. A less intensive verification report must be in a format specified by ecology and meet the requirements of subsection (4)(b)(i) through (viii) of this section. Less intensive verification of an annual GHG report allows for less detailed data checks and document reviews of the annual GHG report based on the analysis and risk assessment in the most current sampling plan developed as part of the most current full verification. Persons subject to third-party verification under subsection (1)(a) through (d) of this section must, at a minimum, conduct less intensive verification for any year full verification is not conducted.

(5) Annual GHG report corrections. Owners or operators subject to this section must correct errors in their annual GHG report.

(a) Corrections are required if errors are identified by:

(i) The third-party verifier;

(ii) The owner or operator;

(iii) Ecology; or

(iv) EPA.

(b) The owner or operator must fix all correctable errors that affect emissions or product data in the submitted emissions data report, and submit a revised emissions data report to ecology. Failure to do so will result in an adverse verification statement.

(c) Failure to fix correctable errors that do not affect emissions or product data represents a nonconformance with this chapter but does not, absent other errors, result in an adverse verification statement.

(d) Any corrections to the annual GHG report identified during the verification process must be submitted to ecology no later than 45 calendar days after discovery of the error or the verification report deadline in subsection (6)(a) of this section, whichever is sooner. Any corrections to the annual GHG report or verification report discovered after the verification report deadline in subsection (6)(a) of this section must be submitted to ecology no later than 45 calendar days after discovery of the error.

(e) The owner or operator must maintain documentation to support any revisions made to the initial emissions data report. Documentation for all emissions data report submittals must be retained by the reporting entity for 10 years.

(6) Report.

(a) The third-party verifier must submit a complete verification report to ecology for each year as required under subsection (1) of this section no later than August 10th for GHG emissions occurring in the previous calendar year.

(b) The third-party verifier must include a certification of one of the following verification statements based on the verification standards in subsection (3) of this section.

(i) A positive verification statement may be issued by a third-party verifier if the third-party verifier can say with high confidence that the submitted GHG data report is free of material misstatement and that the GHG data report conforms to the requirements of this chapter.

(ii) A qualified positive verification statement must be issued by a third-party verifier if the third-party verifier can say with high confidence that the submitted GHG data report is free of material misstatement and contains no errors that affect emissions or product data, but the GHG data report may include one or more other nonconformance(s) with the requirements of this chapter which do not result in a material misstatement.

(iii) An adverse verification statement must be issued by a third-party verifier if the third-party verifier cannot say with high confidence that the submitted GHG data report is free of material misstatement, or that the emissions or product data submitted in the GHG data report is free of errors that affect emissions or product data and thus is not in conformance with the requirements to fix such errors.

(c) Records must be retained following the requirements of WAC 173-441-050(6).

(7) Eligible third-party verifiers.

(a) Owners or operators subject to this section must have their annual GHG report verified by a third-party verifier certified by ecology. Certification requires:

(i) Registering as a third-party verifier with ecology. Registration is required for both the verification organization and all individuals performing verification services for the verification organization.

(ii) Demonstrating to ecology's satisfaction that the third-party verifier has sufficient knowledge of the relevant methods and protocols in this chapter. Certification may be limited to certain types or sources of emissions.

(iii) Active accreditation or recognition as a third-party verifier under

California ARB's Mandatory Reporting of Greenhouse Gas Emissions program.

(iv) Ecology may modify, suspend, or revoke certification of a third-party verifier based on the accuracy of their signed verification statements, conformance with conflict of interest provisions, or other requirements of this section.

(b) An owner or operator must not use the same third-party verifier (either organization or individuals) for a period of more than six consecutive years. The owner or operator must wait at least three years before using the previous third-party verifier to verify their annual GHG reports.

(c) An owner or operator and third-party verifier must certify that there is not a conflict of interest in verifying the annual GHG report. The potential for a conflict of interest must be deemed to be high where:

(i) The third-party verifier and reporter share any management staff or board of directors membership, or any of the senior management staff of the reporter have been employed by the third-party verifier, or vice versa, within the previous five years; or

(ii) Any employee of the third-party verifier, or any employee of a related entity, or a subcontractor who is a member of the verification team has provided to the reporter any services within the previous five years, unless the service was part of GHG verification for another jurisdiction. Any years of previous service in the other jurisdiction count towards the limit in (b) of this subsection.

(iii) Any staff member of the third-party verifier provides any type of incentive to a reporter to secure a verification services contract.

(8) Ecology verification. Ecology retains full authority in determining if an annual GHG report contains a discrepancy, omission, or misreporting, or any aggregation of the three, that impacts the verification status of the annual GHG report. Ecology may issue an adverse verification statement for an annual GHG report even if the annual GHG report has received a positive verification statement from the third-party verifier. Ecology may also issue an adverse verification statement for:

(a) Failure to submit a complete annual GHG report in a timely manner;

(b) Failure to complete third-party verification if required by this subsection; or

(c) Other forms of noncompliance with this chapter.

(1) Ecology may assign an emissions level to any annual GHG report that:

(a) Failed to submit a complete annual GHG report by the report submission due date, specified in WAC 173-441-050(2);

(b) Failed to meet the third-party verification requirements in WAC 173-441-085;

(c) Has an adverse verification statement; or

(d) Ecology determines a discrepancy, omission, or misreporting, as described in WAC 173-441-085 (3)(b)(i) through (iv), results in a substantive error as defined in WAC 173-441-050 (7)(c). This standard also separately applies to any product data in the annual GHG report.

(2) The assigned emissions level must be used when determining compliance with chapter 70A.65 RCW, as described in chapter 173-446 WAC.

(3) Ecology must use conservative assumptions when setting the assigned emissions level to avoid underestimating emissions in a compliance year or overestimating emissions in a baseline year.

(a) Within five working days of a written request by ecology, the third-party verifier (if applicable) must provide any available verification services information or correspondence related to the emissions data.

(b) Within five working days of a written request by ecology, the owner or operator of a reporter must provide the data that is required to calculate GHG emissions for the reporter according to the requirements of this chapter, the preliminary or final detailed verification report prepared by the third-party verifier (if applicable), and other information requested by ecology, including the operating days and hours of the reporter during the data year. The owner or operator must also make available personnel who can assist ecology's determination of an assigned emissions level for the data year.

(4) Ecology may adjust the assigned emissions level if the owner or operator is able to obtain a positive verification statement for the annual GHG report at a later date.

(1) Violations. Any violation of any requirement of this chapter must be a violation of chapter 70A.15 RCW and subject to enforcement as provided in that chapter. A violation includes, but is not limited to, failure to submit a complete report by the reporting deadline, failure to report accurately, failure to collect data needed to calculate GHG emissions or product data, failure to continuously monitor and test as required, failure to retain records needed to verify the amount of GHG emissions or product data, failure to calculate GHG emissions or product data following the methodologies specified in this chapter, failure to have the annual GHG report third-party verified, and failure to pay the required reporting fee. Each calendar day and each metric ton CO2e of emissions of a violation constitutes a separate violation.

(2) Enforcement responsibility. Ecology must enforce the requirements of this chapter.

(3) Phased enforcement for some reporting elements for the 2022 emissions year. Ecology is phasing in enforcement for nonconformance with new reporting requirements, including WAC 173-441-122 and 173-441-124, adopted February 9, 2022, during the 2022 emissions year reported in 2023 as follows.

(a) Ecology may issue violations under subsection (1) of this section for any nonconformance with new reporting requirements, including WAC 173-441-122 and 173-441-124, adopted February 9, 2022, during the 2022 emissions year reported in 2023; however, ecology will not issue monetary penalties under this section, except for failure to comply with the requirement to submit a complete report by the reporting deadline, for this period. All other provisions of this chapter apply during this period.

(b) New reporting requirements, including WAC 173-441-122 and 173-441-124, adopted February 9, 2022, are fully subject to compliance and enforcement provisions of this section, including potential monetary penalties for violations, beginning with the 2023 emissions year reported in 2024.

All requests, notifications, and communications to ecology pursuant to this chapter, must be submitted in a format as specified by ecology to either of the following:

(1) For U.S. mail: Greenhouse Gas Reporting, Air Quality Program, Department of Ecology, P.O. Box 47600, Olympia, WA 98504-7600.

(2) For email: ghgreporting@ecy.wa.gov.

(1) Fee determination. All persons required to report or voluntarily reporting under WAC 173-441-030 must pay a reporting fee for each year they submit a report to ecology. Ecology must establish reporting fees based on workload using the process outlined below. The fees must be sufficient to cover ecology's costs to administer the GHG emissions reporting program.

(2) Fee eligible activities. All costs of activities associated with administering this reporting program, as described in RCW 70A.15.2200(2), are fee eligible.

(3) Workload analysis and budget development. Each biennium, ecology must conduct a workload analysis and develop a budget based on the process outlined below:

(a) Ecology must conduct a workload analysis projecting resource requirements for administering the reporting program, organized by categories of fee eligible activities, for the purpose of preparing the budget. Ecology must prepare the workload analysis for the two-year period corresponding to each biennium. The workload analysis must identify the fee eligible administrative activities related to the reporting program that it will perform during the biennium and must estimate the resources required to perform these activities.

(b) Ecology must prepare a budget for administering the reporting program for the two-year period corresponding to each biennium. Ecology must base the budget on the resource requirements identified in the workload analysis for the biennium and must take into account the reporting program account balance at the start of the biennium.

(4) Allocation methodology. Ecology must allocate the reporting program budget among the persons required to report or voluntarily reporting under WAC 173-441-030 according to the following:

(a) The reporting fee for a person that is required to report or voluntarily reporting under WAC 173-441-030 and is subject to third-party verification under WAC 173-441-085 is calculated by the equal division of 90 percent of the budget amount by the total number of persons subject to third-party verification under WAC 173-441-085 in a given calendar year. A person required to report or voluntarily reporting multiple reporters under this category must pay a fee for each reporter.

(b) The reporting fee for a person that is required to report or voluntarily reporting under WAC 173-441-030 but is not subject to third-party verification under WAC 173-441-085 is calculated by the equal division of 10 percent of the budget amount by the total number of persons reporting GHG emissions under this chapter not subject to third-party verification under WAC 173-441-085 in a given calendar year. A person required to report or voluntarily reporting multiple reporters under this category must pay a fee for each reporter.

(5) Fee schedule. Ecology must issue annually a fee schedule reflecting the reporting fee to be paid per reporter. Ecology must base the fee schedule on the budget and workload analysis described above and conducted each biennium. Ecology must publish the fee schedule for the following year on or before October 31st of each year.

(6) Fee payments. Fees specified in this section must be paid within 60 calendar days of receipt of ecology's billing statement. All fees collected under this chapter must be made payable to the Washington department of ecology. A late fee surcharge of $50 or 10 percent of the fee, whichever is more, may be assessed for any fee received after 90 calendar days past the due date for fee payment.

(7) Dedicated account. Ecology must deposit all reporting fees they collect in the air pollution control account.

This section establishes the scope of reportable GHG emissions under this chapter and GHG emissions calculation methods for facilities. Owners and operators of facilities must follow the requirements of this section to determine if they are required to report under WAC 173-441-030(1). Owners and operators of facilities that are subject to this chapter must follow the requirements of this section and all subparts of 40 C.F.R. Part 98 listed in Table 120-1 of this section when calculating emissions. If a conflict exists between a provision in WAC 173-441-010 through 173-441-110 and 173-441-140 through 173-441-170 and any applicable provision of this section, the requirements of those sections must take precedence.

(1) Source categories and calculation methods for facilities. An owner or operator of a facility subject to the requirements of this chapter must report GHG emissions, including GHG emissions from biomass, from all applicable source categories in Washington state listed in Table 120-1 of this section using the methods incorporated by reference in Table 120-1. Table 120-1 and subsection (2) of this section list modifications and exceptions to calculation methods adopted by reference in this section.

(2) Modifications and exceptions to calculation methods adopted by reference. Except as otherwise specifically provided:

(a) Wherever the term "administrator" is used in the rules incorporated by reference in this chapter, the term "director" must be substituted.

(b) Wherever the term "EPA" is used in the rules incorporated by reference in this chapter, the term "ecology" must be substituted.

(c) Wherever the term "United States" is used in the rules incorporated by reference in this chapter, the term "Washington state" must be substituted.

(d) Wherever a calculation method adopted by reference in Table 120-1 of this section or a definition adopted by reference from 40 C.F.R. Part 98.6 refers to another subpart or paragraph of 40 C.F.R. Part 98:

(i) If Table 120-2 of this section lists the reference, then replace the reference with the corresponding reference to this chapter as specified in Table 120-2.

(ii) If the reference is to a subpart or subsection of a reference listed in Table 120-2 of this section, then replace the reference with the appropriate subsection of the corresponding reference to this chapter as specified in Table 120-2.

(iii) If the reference is to a subpart or paragraph of 40 C.F.R. Part 98 Subparts C through UU incorporated by reference in Table 120-1, then use the existing reference except as modified by this chapter.

(e)

Use the following method to obtain specific version or date references for any reference in 40 C.F.R. Part 98 that refers to any document not contained in 40 C.F.R. Part 98:

(i) If the reference in 40 C.F.R. Part 98 includes a specific version or date reference, then use the version or date as specified in 40 C.F.R. Part 98.

(ii) If the reference in 40 C.F.R. Part 98 does not include a specific version or date reference, then use the version of the referenced document as available on the date of adoption of this chapter.

(f) For electrical transmission and distribution equipment use facilities where the electrical power system crosses Washington state boundaries, limit the GHG report to emissions that occur in Washington state using one of the following methods:

(i) Direct, state specific measurements;

(ii) Prorate the total emissions of the electric power system based upon either nameplate capacity or transmission line miles in the respective service areas by state using company records. Update the nameplate capacity or transmission line miles factor each reporting year and include the data used to establish the nameplate capacity or transmission line miles factor with your annual GHG report;

(iii) Prorate the total emissions of the electric power system based upon population in the respective service areas by state using the most recent U.S. Census data. Update the population factor each reporting year and include the data used to establish the population factor with your annual GHG report.

(3) Calculation methods for voluntary reporting. GHG emissions reported voluntarily under WAC 173-441-030 (5) must be calculated using the following methods:

(a) If the GHG emissions have calculation methods specified in Table 120-1 of this section, use the methods specified in Table 120-1.

(b) If the GHG emissions have calculation methods specified in WAC 173-441-122 or 173-441-124, use the methods specified in WAC 173-441-122 or 173-441-124.

(c) For all GHG emissions from facilities not covered in Table 120-1 of this section or persons supplying any product other than those listed in WAC 173-441-122 or 173-441-124, contact ecology for an appropriate calculation method no later than 180 calendar days prior to the emissions report deadline established in WAC 173-441-050(2) or submit a petition for alternative calculation methods according to the requirements of WAC 173-441-140.

(4) Alternative calculation methods approved by petition. An owner or operator may petition ecology to use calculation methods other than those specified in Table 120-1 of this section to calculate its facility GHG emissions. Such alternative calculation methods must be approved by ecology prior to reporting and must meet the requirements of WAC 173-441-140.

(5) Emissions subject to reporting, but not subject to the reporting threshold. Facilities that supply CO2 as described in WAC 173-441-122 (3)(b) required to report or voluntarily reporting under WAC 173-441-030 (1) or (5) based on GHG emissions calculated under subsections (1) through (4) of this section must report supplied CO2 using the 40 C.F.R. Part 98 Subpart PP methods described in WAC 173-441-122 (3)(b) as part of their facility report as described in that section regardless of the amount of GHG emissions. Those emissions do not count towards the reporting threshold in WAC 173-441-030(1).

This section establishes the scope of reportable GHG emissions under this chapter and GHG emissions calculation methods for suppliers. Owners and operators of suppliers must follow the requirements of this section to determine if they are required to report under WAC 173-441-030(2). Owners and operators of suppliers that are subject to this chapter must follow the requirements of this section and all subparts of 40 C.F.R. Part 98 listed in this section when calculating emissions. If a conflict exists between a provision in WAC 173-441-010 through 173-441-110 and 173-441-140 through 173-441-170 and any applicable provision of this section, the requirements of those sections must take precedence.

(1) General requirements. An owner or operator of a supplier subject to the requirements of this chapter must report GHG emissions, including GHG emissions from biomass, from all applicable source categories with GHG emissions in Washington state listed in (a) of this subsection using the methods in this section. All GHG emissions in Washington state from a common primary parent company or owner or operator are considered part of a single supplier for the purposes of this section.

(a) Supplier source categories:

(i) Position holders at terminals and refiners delivering fuel products, other than natural gas described in Subpart NN;

(ii) Enterers that import fuel products, other than natural gas described in Subpart NN, outside the bulk transfer/terminal system, and biofuel production facilities that produce and deliver fuel products outside the bulk/terminal system;

(iii) Refiners that produce liquefied petroleum gas;

(iv) Operators of interstate pipelines delivering natural gas;

(v) Importers of liquefied petroleum gas, compressed natural gas, or liquefied natural gas into Washington;

(vi) Local distribution companies who are public utility gas corporations or publicly owned natural gas utilities delivering natural gas;

(vii) Operators of intrastate pipelines delivering natural gas;

(viii) Natural gas liquid fractionators;

(ix) Producers, importers, and exporters of carbon dioxide;

(x) Facilities that make and deliver liquefied natural gas products or compressed natural gas products by liquefying or compressing natural gas received from interstate pipelines.

(b) All references to 40 C.F.R. Part 98 are modified consistent with WAC 173-441-120 (2)(a) through (e).

(c) The calculation methods for voluntary reporting in WAC 173-441-120(3) apply, except calculation methods in WAC 173-441-120 (3)(b) take precedence over the methods from WAC 173-441-120 (3)(a).

(d) An owner or operator may petition ecology to use calculation methods other than those specified in this section to calculate its supplier GHG emissions. Such alternative calculation methods must be approved by ecology prior to reporting and must meet the requirements of WAC 173-441-140.

(2) Definitions specific to suppliers. The definitions in this subsection apply throughout this section unless the context clearly requires otherwise.

(a) "Biomethane" or "renewable methane" means biogas that meets pipeline quality natural gas standards.

(b) "Biofuel production facility" means a production facility that produces one or more biomass-derived fuels.

(c) "Biomass-derived fuels" means a fuel listed in 40 C.F.R. Part 98 Table MM-2, or any renewable or biogenic version of a product listed in 40 C.F.R. Part 98 Table MM-1.

(d) "Biogas" or "renewable natural gas" means a gas consisting largely of methane and other hydrocarbons derived from the decomposition of organic material in landfills, wastewater treatment facilities, and anaerobic digesters.

(e) "Bulk transfer/terminal system" means a fuel distribution system consisting of refineries, pipelines, vessels, and terminals. Fuel storage and blending facilities that are not fed by pipeline or vessel are considered outside the bulk transfer system.

(f) "Enterer" means an entity that imports fuel products into Washington and who is the importer of record under federal customs law or the owner of fuel upon import into Washington if the fuel is not subject to federal customs law. Only enterers that import the fuels specified in this definition outside the bulk transfer/terminal system are subject to reporting under the regulation.

(g) "Fractionator" means plants that produce fractionated natural gas liquids (NGLs) extracted from produced natural gas and separate the NGLs individual component products: Ethane, propane, butanes and pentane-plus (C5+). Plants that only process natural gas but do not fractionate NGLs further into component products are not considered fractionators. Some fractionators do not process production gas, but instead fractionate bulk NGLs received from natural gas processors. Some fractionators both process natural gas and fractionate bulk NGLs received from other plants.

(h) "Fuel transaction" means the record of the exchange of fuel possession, ownership, or title from one entity to another.

(i) "Importer of fuel" means an entity that imports fuel products into Washington and who is the importer of record under federal customs law. For imported fuel products not subject to federal customs law, the "importer of fuel" is the owner of the fuel product upon its entering into Washington if the eventual transfer of ownership of the product to an end user or marketer located in Washington occurs at a location inside Washington. However, where the transfer of ownership of the fuel product to a Washington end user or marketer occurs at a location outside of Washington, the "importer of fuel" is the producer, marketer, or distributor that is the seller of the fuel product to the end user or marketer located inside Washington. Pursuant to subsection (4) of this section, only importers of liquefied petroleum gas, compressed natural gas, and liquefied natural gas are subject to reporting as an importer of fuel.

(j) "Importer of record" means the owner or purchaser of the goods that are imported into Washington.

(k) "Interstate pipeline" means any entity that owns or operates a natural gas pipeline delivering natural gas to consumers in the state and is subject to rate regulation by the Federal Energy Regulatory Commission.

(l) "Intrastate pipeline" means any pipeline or piping system wholly within Washington state that is delivering natural gas to end users and is not regulated as a public utility gas corporation by the Washington state utilities and transportation commission, is not a publicly owned natural gas utility, and is not regulated as an interstate pipeline by the Federal Energy Regulatory Commission. Only intrastate pipeline operators that physically deliver gas to end users in Washington are subject to reporting under this chapter. This definition includes onshore petroleum and natural gas production facilities and natural gas processing facilities, as defined in 40 C.F.R. Part 98, that deliver pipeline and/or nonpipeline quality natural gas to one or more end users. Facility operators that operate an interconnection pipeline that connects their facility to an interstate pipeline, or that share an interconnection pipeline to an interstate pipeline with other nearby facilities, are not considered intrastate pipeline operators. Facilities that receive gas from an upstream LDC and redeliver a portion of the gas to one or more adjacent facilities are not considered intrastate pipelines.

(m) "Local distribution company" or "LDC," for purposes of this chapter (chapter 173-441 WAC), means a company that owns or operates distribution pipelines, not interstate pipelines, that physically deliver natural gas to end users and includes public utility gas corporations, publicly owned natural gas utilities and intrastate pipelines that are delivering natural gas to end users.

(n) "Position holder" means an entity that holds an inventory position in fuel products as reflected in the records of the terminal operator or a terminal operator that owns fuel products in its terminal. "Position holder" does not include inventory held outside of a terminal, fuel jobbers (unless directly holding inventory at the terminal), retail establishments, or other fuel suppliers not holding inventory at a fuel terminal.

(o) "Producer" means a person who owns, leases, operates, controls, or supervises a Washington state production facility.

(p) "Rack" means a mechanism for delivering motor vehicle fuel or diesel from a refinery or terminal into a truck, trailer, railroad car, or other means of nonbulk transfer.

(q) "Refiner" means, for purposes of this chapter, an individual entity or a corporate-wide entity that delivers fuel products to end users in Washington state that were produced by petroleum refineries owned by that entity or a subsidiary of that entity.

(r) "Terminal" means a fuel product storage and distribution facility that is supplied by pipeline or vessel, and from which fuel product may be removed at a rack. "Terminal" includes a fuel production facility where fuel product is produced and stored and from which fuel product may be removed at a rack.

(s) "Terminal operator" means any entity that owns, operates, or otherwise controls a terminal that is supplied by pipeline or vessel and from which accountable fuel products may be removed at a rack.

(3) Suppliers of carbon dioxide. Any supplier of carbon dioxide with supplied CO2 calculated under this subsection that exceeds the reporting threshold in WAC 173-441-030(2) of this chapter must comply with 40 C.F.R. Part 98 Subpart PP in reporting to ecology, except as otherwise provided in this section. Also use Subpart PP for threshold calculations.

(a) When reporting imported and exported quantities of CO2 as required in 40 C.F.R. § 98.422, the supplier must report quantities of carbon dioxide imported into and exported from Washington state. Exports for purposes of geologic sequestration must be reported separately from exports for other purposes.

(b) Facilities required to report or voluntarily reporting under WAC 173-441-030 (1) or (5) with the following processes must report supplied CO2 using the methods in this section as part of their facility GHG report under WAC 173-441-070(1) regardless of the amount of CO2 supplied.

(i) Production process units located in Washington state that capture a CO2 stream for purposes of supplying CO2 to another entity or facility or that capture the CO2 stream in order to utilize it for geologic sequestration where capture refers to the initial separation and removal of CO2 from a manufacturing process or any other process; or

(ii) CO2 production wells located in Washington state that extract or produce a CO2 stream for purposes of supplying CO2 for commercial applications or that extract a CO2 stream in order to utilize it for geologic sequestration.

(c) Missing data substitution procedures. The supplier must comply with 40 C.F.R. § 98.425 when substituting for missing data, except as otherwise provided below.

(i) If the data capture rate is at least 90 percent for the data year, the supplier must substitute for each missing value using the best available estimate of the parameter, based on all available process data.

(ii) If the data capture rate is at least 80 percent but not at least 90 percent for the data year, the supplier must substitute for each missing value with the highest quality assured value recorded for the parameter during the given data year, as well as the two previous data years.

(iii) If the data capture rate is less than 80 percent for the data year, the supplier must substitute for each missing value with the highest quality assured value recorded for the parameter in all records kept according to WAC 173-441-050.

(iv) The supplier must document and retain records of the procedure used for all missing data estimates pursuant to the recordkeeping requirements of WAC 173-441-050.

(4) Suppliers of natural gas. Any supplier of natural gas, natural gas liquids, liquefied petroleum gas, compressed natural gas, or liquefied natural gas with emissions calculated under this subsection that exceeds the reporting threshold in WAC 173-441-030(2) must comply with 40 C.F.R. Part 98 Subpart NN in reporting emissions and related data to ecology, except as otherwise provided in this section. Also use the methods in this section for threshold calculations.

(a) GHGs to report. In addition to the CO2 emissions specified under 40 C.F.R. § 98.402, all suppliers of natural gas covered in this section must separately report the CO2, CO2 from biomass-derived fuels, CH4, N2O, and CO2e emissions from the complete combustion or oxidation of the annual volume of natural gas delivered, sold or imported in Washington state.

(b) Calculating GHG emissions. When reporting imported and exported quantities of GHGs as required in 40 C.F.R. § 98.403 and (a) of this subsection, the supplier must report quantities of GHGs imported into and exported from Washington state.

(i) Natural gas liquid fractionators must use calculation methodology 2 as specified in 40 C.F.R. § 98.403 (a)(2) to estimate the CO2 emissions that would result from the complete combustion of all natural gas liquid products supplied. For calculating the emissions from liquefied petroleum gas, the fractionators must sum the emissions from the individual constituents of liquefied petroleum gas sold or delivered to others that was produced on-site, except for products for which a final destination outside Washington state can be demonstrated.

(ii) Local distribution companies must estimate CO2 emissions at the state border or city gate for pipeline quality natural gas using calculation methodology 1 as specified in 40 C.F.R. § 98.403 (a)(1), except that the product of HHV and Fuel is replaced by the annual MMBtu of natural gas received.

(iii) For the calculation of CO2j in Equation 122-2, public utility gas corporations and publicly owned natural gas utilities must estimate annual CO2 emissions from instate receipts of pipeline quality natural gas from other public utility gas corporations, interstate pipelines and intrastate transmission pipelines, and annual CO2 emissions from all natural gas redelivered to other public utility gas corporations or interstate pipelines. Annual CO2 emissions from redelivered natural gas to intrastate pipelines or publicly owned natural gas utilities must be estimated only if the intrastate pipeline or publicly owned natural gas utility also reports emissions under this section. Emissions are calculated according to Equation NN-3 of 40 C.F.R. § 98.403 (b)(1) except that CO2j will be the product of MMBtuTotal and the default emission factor from Table NN-1 or the product of MMBtuTotal and the reporter specific emission factor. MMBtuTotal must be calculated as follows:

(iv) For the calculation of CO2l in Equation 122-2, emissions from receipts of pipeline quality natural gas from in-state natural gas producers and net volume of pipeline quality natural gas injected into storage are estimated according to Equation NN-5a of 40 C.F.R. § 98.403 (b)(3) except that CO2l will be calculated as the product of the net annual MMBtu and a default emission factor from Table NN-1 or the product of the net annual MMBtu and a reporter specific emission factor.

(v) For the calculation of CO2n in Equation 122-2, emissions from natural gas received directly by LDC systems from producers or natural gas processing plants from local production, received as a liquid and vaporized for delivery, or received from any other source that bypassed the city gate are estimated according to Equation NN-5b of 40 C.F.R. § 98.403 (b)(3) except that CO2n will be calculated as the product of the net annual MMBtu and a default emission factor from Table NN-1 or the product of the net annual MMBtu and the reporter specific emission factor.

(vi) For the calculation of CO2k in Equation 122-2, natural gas delivered to large end users, use Equation NN-4 of 40 C.F.R. § 98.403 (b)(2), except that CO2k will be calculated as the product of the annual MMBtu delivered and a default emission factor from Table NN-1 or the product of the annual MMBtu delivered and the reporter specific emission factor. A large end user means any end user facility required to report under WAC 173-441-030(1).

(vii) Determination of pipeline quality natural gas is based on the annual weighted average HHV, determined according to Equation C-2b of 40 C.F.R. § 98.33 (a)(2)(ii)(A), for natural gas from a single city gate, storage facility, or connection with an in-state producer, interstate pipeline, intrastate pipeline or local distribution company. If the HHV is outside the range of pipeline quality natural gas, emissions will be calculated using the appropriate subsection (4) of this section replacing the default emission factor with either a reporter specific emission factor as calculated in 40 C.F.R. § 98.404 (b)(2) or one determined as follows:

(A) For natural gas or biomethane with an annual weighted HHV below 970 Btu/scf and not exceeding three percent of total emissions estimated under this section, the local distribution company may use the reporter specific weighted yearly average higher heating value and the default emission factor or an emission factor as determined in 40 C.F.R. § 98.404 (c)(3). If emissions exceed three percent of the total, then the Tier 3 method specified in 40 C.F.R. § 98.33 (a)(3)(iii) must be used with monthly carbon content samples to calculate the annual emissions from the portion of natural gas that is below 970 Btu/scf.

(B) For natural gas or biomethane with an annual HHV above 1100 Btu/scf and not exceeding three percent of total emissions estimated under this section, the local distribution company must use the reporter specific weighted yearly average higher heating value and a default emission factor of 54.67 kg CO2/MMBtu or an emission factor as determined in 40 C.F.R. § 98.404 (c)(3). If emissions exceed three percent of the total, then the Tier 3 method specified in 40 C.F.R. § 98.33 (a)(3)(iii) must be used with monthly carbon content samples to calculate the annual emissions from the portion of natural gas that is above 1100 Btu/scf.

(viii) When calculating total CO2 emissions for Washington state, the equation below must be used:

(ix) The importer of liquefied petroleum gas into Washington state must use calculation methodology 2 described in 40 C.F.R. § 98.403 (a)(2) for calculating CO2 emissions. For liquefied petroleum gas, the importer must sum the emissions from the individual components of the gas to calculate the total emissions. If the composition is not supplied by the producer, the importer must use the default value for liquefied petroleum gas presented in Table C-1 of 40 C.F.R. Part 98. The importer of compressed natural gas or liquefied natural gas into Washington state must estimate CO2 using calculation methodology 1 as specified in 40 C.F.R. § 98.403 (a)(1), except that the product of HHV and fuel is replaced by the annual MMBtu of the imported compressed natural gas and liquefied natural gas.

(x) Operators of facilities that make liquefied natural gas products or compressed natural gas products must estimate CO2 using calculation methodology 1 as specified in 40 C.F.R. § 98.403 (a)(1), except that the product of HHV and fuel is replaced by the annual MMBtu of the liquefied natural gas sold or delivered in Washington state.

(xi) Operators of facilities that make liquefied natural gas products or compressed natural gas products, importers of liquefied petroleum gas, compressed natural gas, or liquefied natural gas into Washington state, natural gas liquid fractionators, and local distribution companies must estimate and report CH4 and N2O emissions using Equation C-8 and Table C-2 as described in 40 C.F.R. § 98.33 (c)(1) for all fuels where annual CO2 emissions are required to be reported. Operators of facilities that make liquefied natural gas products or compressed natural gas products must estimate CH4 and N2O emissions based on the MMBtu of liquefied natural gas sold or delivered. Local distribution companies must use the annual MMBtu determined in (b)(ii) through (vi) of this subsection above in place of the product of the fuel and HHV in Equation C-8 when calculating emissions.

(xii) Local distribution companies must separately and individually calculate end user emissions of CH4, N2O, CO2 from biomass-derived fuels, and CO2e by replacing CO2 in Equation 122-2 with CH4, N2O, CO2 from biomass-derived fuels, and CO2e. CO2 emissions from biomass-derived fuel are based on the fuel the LDC has contractually purchased on behalf of and delivered to end users. LDCs can elect to report biomethane directly purchased by an end user and delivered by the LDC if the LDC can provide the relevant documentation including invoices, shipping reports, in-kind nomination reports, and contracts to demonstrate the receipt of eligible biomethane and the following information for each contracted delivery:

(A) Name and address of the biomethane vendor from which biomethane is purchased;

(B) Annual MMBtu delivered by each biomethane vendor;

(C) Name, address, and facility type of the facility from which the biomethane is produced;

Emissions from contractually purchased biomethane are calculated using the methods for natural gas required by this section, including the use of the emission factor for natural gas found in 40 C.F.R. § 98.408, Table NN-1. Biomass-derived fuels directly purchased by end users and delivered by the LDC must be reported as natural gas by the LDC, unless the LDC has elected to report the delivery as biomethane and can provide the necessary documentation during verification as stated above.

(xiii) All suppliers in this section must also estimate CO2e emissions using Equation A-1.

(c) Monitoring and QA/QC requirements. For each emissions calculation method chosen under this section, the supplier must meet all monitoring and QA/QC requirements specified in 40 C.F.R. § 98.404, except as modified in WAC 173-441-050, 173-441-120, and below.

(i) All natural gas suppliers must measure required values at least monthly.

(ii) All natural gas suppliers must determine reporter specific HHV at least monthly, or if the local distribution company does not make its own measurements according to standard business practices, it must use the delivering pipeline measurement.

(iii) All natural gas liquid fractionators must sample for composition at least monthly.

(iv) All importers of liquefied petroleum gas into Washington state must record composition, if provided by the supplier, and quantity in barrels, corrected to 60 degrees Fahrenheit, for each shipment received.

(d) Data reporting requirements.

(i) For the emissions calculation method selected under (b) of this subsection, natural gas liquid fractionators must report, in addition to the data required by 40 C.F.R. § 98.406(a), the annual volume of liquefied petroleum gas, corrected to 60 degrees Fahrenheit, that was produced on-site and sold or delivered to others, except for products for which a final destination outside Washington state can be demonstrated. Natural gas liquid fractionators must report the annual quantity of liquefied petroleum gas produced and sold or delivered to others as the total volume in barrels as well as the volume of the individual components for all components listed in 40 C.F.R. Part 98 Table MM-1. Fractionators must also include the annual CO2, CH4, N2O, and CO2e mass emissions (metric tons) from the volume of liquefied petroleum gas reported in 40 C.F.R. § 98.406 (a)(5) as modified by this regulation, calculated in accordance with (b) of this subsection.

(ii) For the emissions calculation method selected under (b) of this subsection, local distribution companies must report all the data required by 40 C.F.R. § 98.406(b) subject to the following modifications:

(A) Publicly owned natural gas utilities that report in-state receipts at the city gate under 40 C.F.R. § 98.406 (b)(1) must also identify each delivering entity by name and report the annual energy of natural gas received in MMBtu.

(B) Local distribution companies that report under 40 C.F.R. § 98.406 (b)(1) through (b)(7) must also report the annual energy of natural gas in MMBtu associated with the volumes.

(C) In addition to the requirements in 40 C.F.R. § 98.406 (b)(8), local distribution companies must also include CO2, CO2 from biomass-derived fuels, CH4, N2O, and CO2e annual mass emissions in metric tons calculated in accordance with 40 C.F.R. § 98.403 (a) and (b)(1) through (b)(3) as modified by (b) of this subsection.

(D) Local distribution companies and intrastate pipelines that deliver natural gas to downstream gas pipelines and other local distribution companies, must report the annual energy in MMBtu, and the information required in 40 C.F.R. § 98.406 (b)(12). These requirements are in addition to the requirements of 40 C.F.R. § 98.406 (b)(6).

(E) Local distribution companies and intrastate pipelines must also report the annual energy in MMBtu, customer information required in 40 C.F.R. § 98.406 (b)(12), and ecology reporter ID if available, for all end users required to report under WAC 173-441-030(1). In addition to reporting the information specified in 40 C.F.R. § 98.406 (b)(13), local distribution companies and intrastate pipelines that deliver to end users must report the annual energy in MMBtu delivered to the following end use categories: Residential consumers; commercial consumers; industrial consumers; electricity generating facilities; and other end users not identified as residential, commercial, industrial, or electricity generating facilities. Local distribution companies must also report the total energy in MMBtu delivered to all Washington state end users.

(F) Local distribution companies that report under 40 C.F.R. § 98.406 (b)(9) must report annual CO2, CO2 from biomass-derived fuel, CH4, N2O, and CO2e emissions (metric tons) that would result from the complete combustion or oxidation of the natural gas supplied to all entities calculated in accordance with (b) of this subsection.

(iii) In addition to the information required in 40 C.F.R. § 98.3(c), the operator of an interstate pipeline, which is not a local distribution company, must report the customer name, address, and ecology reporter ID along with the annual energy of natural gas in MMBtu for natural gas delivered to each customer, including themselves.

(iv) In addition to the information required in 40 C.F.R. § 98.3(c), the operator of an intrastate pipeline that delivers natural gas directly to end users must follow the reporting requirements described under Subpart NN of 40 C.F.R. Part 98 and this section for local distribution companies. The intrastate pipeline operator must also report the summed energy (MMBtu) of natural gas delivered to each entity receiving gas from the intrastate pipeline for purposes of estimating the CO2i parameter as specified in (b)(ii) of this subsection. Additionally, intrastate pipeline operators are required to estimate a value for CO2j as specified in (b)(iii) of this subsection for natural gas delivered to local distribution companies, interstate pipelines, and other intrastate pipelines. The CO2l parameter as specified in (b)(iv) of this subsection must have a value of zero for calculating emissions.

(v) In addition to the information required in 40 C.F.R. § 98.3(c), the importer of liquefied petroleum gas into Washington state must report the annual quantity of liquefied petroleum gas imported as the total volume in barrels as well as the volume of its individual components for all components listed in 40 C.F.R. Part 98 Table MM-1, if supplied by the producer, and report CO2, CH4, N2O, and CO2e annual mass emissions in metric tons using the calculation methods in (b) of this subsection. All importers of compressed or liquefied natural gas into Washington state and liquefied natural gas production facilities must report the annual quantities imported, and delivered or sold, respectively, in MMBtu, and report CO2, CH4, N2O, and CO2e annual mass emissions in metric tons separately for compressed natural gas and liquefied natural gas using the calculation methods in (b) of this subsection.

(vi) In addition to the information required in 40 C.F.R. § 98.3(c), all local distribution companies that report biomass emissions from biomethane fuel that was contractually purchased by the LDC on behalf of and delivered to end users, and all liquefied natural gas production facilities reporting biomass emission from biomethane, must report, for each contracted delivery, the information specified in (b)(x) of this subsection.

(vii) All operators of facilities that make liquefied natural gas products must report end user information for deliveries of liquefied natural gas to industrial facilities and natural gas utility customers, including customer name, address, and the annual quantity of liquefied natural gas delivered to each customer in MMBtu.

(viii) All natural gas liquid fractionators and importers of liquefied petroleum gas must report the total quantity in barrels of liquefied petroleum gas that is excluded from emissions reporting due to demonstration of final destination outside Washington state.

(e) Procedures for estimating missing data. Suppliers must follow the missing data procedures specified in 40 C.F.R. § 98.405. The operator must document and retain records of the procedure used for all missing data estimates pursuant to the recordkeeping requirements of WAC 173-441-050.

(5) Fuel suppliers other than suppliers of natural gas. Any supplier of petroleum products, biomass-derived fuels, or coal-based liquid fuels with emissions calculated under this subsection that exceeds the reporting threshold in WAC 173-441-030(2) must comply with 40 C.F.R. Part 98 Subparts LL and MM in reporting emissions and related data to ecology, except as otherwise provided in this section. Also use the methods in this section for threshold calculations. For the purposes of this subsection, fuel products do not include products reported under subsection (4) of this section but do include all fuel products listed in 40 C.F.R. Part 98 Subpart MM Tables MM-1 and MM-2, including products listed in Table MM-1 of Subpart MM that are coal-based (coal-to-liquid products). Renewable or biogenic versions of fuel products listed in Table MM-1 are also considered fuel products.

(a) GHGs to report.

(i) In addition to the CO2 emissions specified under 40 C.F.R. § 98.392, all refiners that produce liquefied petroleum gas must report the CO2, CO2 from biomass-derived fuels, CH4, N2O and CO2e emissions that would result from the complete combustion or oxidation of the annual quantity of liquefied petroleum gas sold or delivered, except for fuel products for which a final destination outside Washington state can be demonstrated.

(ii) Refiners, position holders of fossil fuel products, and biomass-derived fuel products that supply fuel products at Washington state terminal racks, and enterers that import fuel products for distribution outside the bulk transfer/terminal system must report the CO2, CO2 from biomass-derived fuels, CH4, N2O, and CO2e emissions that would result from the complete combustion or oxidation of each fuel product. However, emissions reporting is not required for fuel products in which a final destination outside Washington state can be demonstrated to ecology's satisfaction, or for fuel products that can be demonstrated to ecology's satisfaction to have been previously delivered by a position holder or refiner out of an upstream Washington state terminal or refinery rack prior to delivery out of a second terminal rack. The volume of all fuel products that are excluded from emissions reporting based on the criteria in this paragraph must be reported pursuant to the requirements in (d)(ix) of this subsection. No fuel product shall be reported as finished fuel. Fuel products must be reported as the individual fuel product. For purposes of this chapter, CARBOB blendstocks are reported as RBOB blendstocks.

(b) Calculating GHG emissions.

(i) Refiners, position holders at Washington state terminals, and enterers that import fuel products for distribution outside the bulk transfer system must use Equation MM-1 as specified in 40 C.F.R. § 98.393(a)(1) to estimate the CO2 emissions that would result from the complete combustion of the fuel product. Emissions must be based on the quantity of fuel product removed from the rack (for refiners and position holders), fuel product imported for distribution outside the bulk transfer/terminal system (by enterers), and fuel product sold to unlicensed entities as specified in (d)(iii) of this subsection (by refiners). For fuel products that are blended, emissions must be reported for each individual fuel product separately, and not as motor gasoline (finished), biofuel blends, or other similar finished fuel product. Emissions from denatured fuel ethanol must be calculated as 100 percent ethanol only. The volume of denaturant is assumed to be zero and is not required to be reported. Emission factors must be taken from column C of 40 C.F.R. Part 98 Table MM-1 or MM-2 as specified in Calculation Method 1 of 40 C.F.R. § 98.393 (f)(1), except that the emission factor for renewable diesel is equivalent to the emission factor for Distillate No. 2. The emission factor for a renewable or biogenic version of a fuel product is equivalent to the emission factor for the corresponding nonrenewable or nonbiogenic version of the fuel product listed in Table MM-1. If a position holder in diesel or biodiesel fuel does not have sealed or financial transaction meters at the rack, and the position holder is the sole position holder at the terminal, the position holder must calculate emissions based on the delivering entity's invoiced volume of fuel product or a meter that meets the requirements of 40 C.F.R. § 98.394 either at the rack or at a point prior to the fuel product going into the terminal storage tanks.

(ii) Refiners that produce liquefied petroleum gas must use Equation MM-1 as specified in 40 C.F.R. § 98.393 (a)(1) to estimate the CO2 emissions that would result from the complete combustion of the fuel product supplied. For calculating the emissions from liquefied petroleum gas, the emissions from the individual components must be summed. Emission factors must be taken from column C of 40 C.F.R. Part 98 Table MM-1 as specified in Calculation Method 1 of 40 C.F.R. § 98.393 (f)(1).

(iii) Refiners, position holders at Washington state terminals, and enterers identified in this section must estimate and report CH4 and N2O emissions using Equation C–8 and Table C-2 as described in 40 C.F.R. § 98.33 (c)(1), except for fuel products listed in Table 122-1, which must use the emission factors in Table 122-1 and Equation C-8 as described in 40 C.F.R. § 98.33 (c)(1). Renewable or biogenic versions of a fuel product must use the same emission factor as required for the corresponding nonrenewable or nonbiogenic version of the fuel product.

(iv) All fuel suppliers in this section must estimate CO2e emissions using Equation A-1.

(c) Monitoring and QA/QC requirements. The operator must meet all the monitoring and QA/QC requirements as specified in 40 C.F.R. § 98.394, and the requirements of 40 C.F.R. § 98.3(i) as further specified in WAC 173-441-050 and below.

(i) Position holders are exempt from 40 C.F.R. § 98.3(i) calibration requirements except when the position holder and entity receiving the fuel product have common ownership or are owned by subsidiaries or affiliates of the same company. In such cases the 40 C.F.R. § 98.3(i) calibration requirements apply, unless:

(A) The fuel supplier does not operate the fuel billing meter;

(B) The fuel billing meter is also used by companies that do not share common ownership with the fuel supplier; or

(C) The fuel billing meter is sealed with a valid seal from the county sealer of weights and measures and the operator has no reason to suspect inaccuracies.

(ii) As required by 40 C.F.R. § 98.394 (a)(1)(iii), for fuel products that are liquid at 60 degrees Fahrenheit and one standard atmosphere, the volume reported must be temperature- and pressure-adjusted to these conditions. For liquefied petroleum gas the volume reported must be temperature-adjusted to 60 degrees Fahrenheit.

(d) Data reporting requirements. In addition to reporting the information required in 40 C.F.R. Part 98 Subpart MM, the following entities must also report the information identified below:

(i) Washington state position holders must report the annual quantity in barrels, as reported by the terminal operator, of each fuel product, that is delivered across the rack in Washington state, except for fuel products for which a final destination outside Washington state can be demonstrated to ecology's satisfaction, or for fuel products that can be demonstrated to ecology's satisfaction to have been previously delivered by a position holder or refiner out of an upstream Washington state terminal or refinery rack prior to delivery out of a second terminal rack. Denatured fuel ethanol will be reported with the entire volume as 100 percent ethanol only. The volume of denaturant is assumed to be zero and is not required to be reported.

(ii) Washington state position holders that are also terminal operators and refiners must report the annual quantity in barrels delivered across the rack of each fuel product, except for fuel products for which a final destination outside Washington state can be demonstrated to ecology's satisfaction, or for fuel products that can be demonstrated to ecology's satisfaction to have been previously delivered by a position holder or refiner out of an upstream Washington state terminal or refinery rack prior to delivery out of a second terminal rack. Denatured fuel ethanol will be reported with the entire volume as 100 percent ethanol only. The volume of denaturant is assumed to be zero and is not required to be reported. If there is only a single position holder at the terminal, and only diesel or biodiesel is being dispensed at the rack then the position holder must report the annual quantity of fuel using a meter meeting the requirements of 40 C.F.R. § 98.394 or billing invoices from the entity delivering fuel to the terminal.

(iii) Refiners that supply fuel products within the bulk transfer system to entities not licensed by the Washington state department of licensing as a fuel supplier must report the annual quantity in barrels delivered of each fuel product, except for fuel products for which a final destination outside Washington state can be demonstrated to ecology's satisfaction. Denatured fuel ethanol will be reported with the entire volume as 100 percent ethanol only. The volume of denaturant is assumed to be zero and is not required to be reported.

(iv) Enterers delivering fuel products for distribution outside the bulk transfer/terminal system must report the annual quantity in barrels, as reported on the bill of lading or other shipping documents of each fuel product that is imported as a blended component of a finished fuel product, except for fuel products for which a final destination outside Washington state can be demonstrated to ecology's satisfaction, typically based on bills of lading. The denatured fuel ethanol component of a finished fuel products must be reported with the entire denatured ethanol volume as 100 percent ethanol only. The volume of denaturant is assumed to be zero and is not required to be reported. Biomass-derived blends containing no more than one percent petroleum-derived fuel by volume are considered to be 100 percent biomass-derived fuel. Individual biomass-derived fuels and biomass-derived fuels that are a blended component of an imported fuel product must be reported by enterers.

(v) In addition to the information required in 40 C.F.R. § 98.396, refiners must also report the volume of liquefied petroleum gas in barrels supplied in Washington state as well as the volumes of the individual components as listed in 40 C.F.R. Part 98 Table MM-1, except for fuel for which a final destination outside Washington state can be demonstrated.

(vi) All fuel suppliers identified in this section must also report CO2, CO2 from biomass-derived fuels, CH4, N2O, and CO2e emissions in metric tons that would result from the complete combustion or oxidation of each fuel product calculated according to Equation A-1.

(vii) All fuel suppliers identified in this section, except for refiners that report pursuant to WAC 173-441-120, must report the total quantity of each fuel product that was imported from outside of Washington state for use in Washington state. In addition, for fuel product imports, the designated percentage of oxygenate must be reported.

(viii) Fuel suppliers identified in this section, except for refiners that report pursuant to WAC 173-441-120, must report the total quantity of biomass-derived fuel blended in Washington state petroleum-derived fuel for use in Washington state.

(ix) Fuel suppliers identified in this section must report the total quantity in barrels of each fuel product that is excluded from emissions reporting due to demonstration of final destination outside Washington state, or demonstration to ecology's satisfaction, typically based on bills of lading, that the fuel product was previously delivered by a position holder or refiner out of an upstream Washington state terminal or refinery rack prior to delivery out of a second terminal rack.

(x) Owners and operators of petroleum refineries and biofuel production facilities required to report or voluntarily reporting under WAC 173-441-030 (1) or (5) must submit a complete refiner report, as defined in 40 C.F.R. Part 98 Subpart MM, that includes all products listed in Tables MM-1 and MM-2, as part of their facility GHG report under WAC 173-441-070(1) regardless of the amount of fuel products produced.

(xi) Owners and operators may separately indicate the quantity of each fuel type if the fuel supplier can demonstrate to ecology's satisfaction that the fuel is used for one of the following purposes:

(A) Aviation fuels;

(B) Watercraft fuels that are combusted outside of Washington state; or

(C) Motor vehicle fuel or special fuel that is used exclusively for agricultural purposes by a farm fuel user. The supplier must demonstrate to ecology's satisfaction that the buyer of the fuel provided the seller with an exemption certificate as described in RCW 82.08.865. Fuel used for the purpose of transporting agricultural products on public highways may be included if it is flagged separately and meets the requirements in RCW 82.08.865. For the purposes of (d)(xi) of this subsection, "agricultural purposes" and "farm fuel user" have the same meanings as provided in RCW 82.08.865 and motor vehicle fuel and special fuel have the same meanings as provided in RCW 82.38.020.

(e) Procedures for missing data. For quantities of fuel products that are purchased, sold, or transferred in any manner, fuel suppliers must follow the missing data procedures specified in 40 C.F.R. § 98.395. The supplier must document and retain records of the procedure used for all missing data estimates pursuant to the recordkeeping requirements of WAC 173-441-050.

This section establishes the scope of reportable energy and GHG emissions under this chapter and GHG emissions calculation methods for electric power entities. Owners and operators of electric power entities must follow the requirements of this section to determine if they are required to report under WAC 173-441-030(3). Owners and operators of electric power entities that are subject to this chapter must follow the requirements of this section when calculating emissions. If a conflict exists between a provision in WAC 173-441-010 through 173-441-110 and 173-441-140 through 173-441-170 and any applicable provision of this section, the requirements of those sections must take precedence.

(1) General requirements. An owner or operator of an electric power entity subject to the requirements of this chapter must report GHG emissions, including GHG emissions from biomass, from all applicable categories listed in (a) of this subsection using the methods and procedures in this section.

(a) Electric power entity categories:

(i) Electricity importers and exporters, as defined in this section;

(ii) Retail providers, including multijurisdictional retail providers, as defined in this section;

(iii) Asset controlling suppliers;

(iv) Electric generating facilities in Washington state must report using the methods specified in WAC 173-441-120.

(b) The calculation methods for voluntary reporting in WAC 173-441-120(3) apply, except calculation methods in WAC 173-441-120 (3)(b) take precedence over the methods from WAC 173-441-120 (3)(a).

(c) Alternative calculation methods approved by petition. An owner or operator may petition ecology to use calculation methods other than those specified in this section to calculate its electric power entities GHG emissions. Such alternative calculation methods must be approved by ecology prior to reporting and must meet the requirements of WAC 173-441-140.

(2) Definitions specific to electric power entities. The definitions in this subsection apply throughout this section unless the context clearly requires otherwise.

(a) "Direct delivery of electricity" means electricity that meets any of the following criteria: The facility has a first point of interconnection at a Washington scheduling point or within a power system; The electricity is scheduled for delivery from the specified source to a Washington scheduling point or a power system via a continuous physical transmission path from interconnection of the facility in the balancing authority in which the facility is located to the Washington scheduling point or power system; or there is an agreement to dynamically transfer electricity from the facility to a Washington scheduling point or power system.

(b) "Electricity generating facility" means a facility that generates electricity and includes one or more generating units at the same location.

(c) "Electricity importer" means:

(i) For electricity that is scheduled with an e-tag to a final point of delivery into a balancing authority area located entirely within Washington state, the electricity importer is identified on the e-tag as the purchasing-selling entity on the last segment of the tag's physical path with the point of receipt located outside Washington state and the point of delivery located inside Washington state;

(ii) For facilities physically located outside Washington state with the first point of interconnection to a balancing authority area located entirely within Washington state when the electricity is not scheduled on an e-tag, the electricity importer is the facility operator or owner;

(iii) For electricity imported through a centralized market, the electricity importer is the retail provider, marketer, or asset controlling supplier that conducts an electricity transaction through the EIM that results in EIM power being delivered to final point of delivery in Washington state;

(iv) For electricity from facilities allocated to serve retail electricity customers of a multijurisdictional electric company, the electricity importer is the multijurisdictional electric company;

(v) If the importer identified under (c)(i) of this subsection is a federal power marketing administration over which Washington state does not have jurisdiction, and the federal power marketing administration has not voluntarily elected to comply with this chapter, then the electricity importer is the next purchasing-selling entity in the physical path on the e-tag, or if no additional purchasing-selling entity over which Washington state has jurisdiction, then the electricity importer is the electric utility that operates the Washington state transmission or distribution system, or the generation balancing authority;

(vi) For electricity that is imported into the state by a federal power marketing administration and sold to a public body or cooperative customer or direct service industrial customer located in Washington state pursuant to section 5 (b) or (d) of the Pacific Northwest Electric Power Planning and Conservation Act of 1980, P.L. 96-501, the electricity importer is the federal marketing administration;

(vii) If the importer identified under (c)(vi) of this subsection has not voluntarily elected to comply with this chapter, then the electricity importer is the public body or cooperative customer or direct service industrial customer;

(viii) For electricity that is imported into the state to a designated scheduling point inside the balancing authority area of a federal power marketing administration, the importer is the purchasing-selling entity on the e-tag at the last point on the physical path that is not the sink;

(ix) If the importer identified under (c)(vii) of this subsection is a federal power marketing administration that has not elected to voluntarily comply with this chapter, then the importer is the retail provider with which the scheduling point is associated; or

(x) For electricity from facilities allocated to a consumer-owned utility inside Washington state from a multijurisdictional consumer-owned utility, the electricity importer is the consumer-owned utility inside Washington state.

(d) "First jurisdictional deliverer" means the owner or operator of an electric generating facility in Washington state or an electricity importer.

(e) "Generation providing entity" or "GPE" means a facility or generating unit operator, full or partial owner, party to a contract for a fixed percentage of net generation from the facility or generating unit, party to a tolling agreement with the owner, or exclusive marketer for the facility or generating unit recognized by ecology.

(f) "Retail provider" means any of the following:

(i) An electric utility as defined in RCW 19.405.020(14);

(ii) Multijurisdictional retail providers;

(iii) Multijurisdictional consumer-owned utilities.

(g) "Imported electricity" means electricity generated outside Washington state with a final point of delivery within the state.

(i) "Imported electricity" includes electricity from an organized market, such as the energy imbalance market.

(ii) "Imported electricity" includes imports from linked jurisdictions, but such imports shall be construed as having no emissions.

(iii) Electricity from a system that is marketed by a federal power marketing administration shall be construed as "imported electricity," not electricity generated in Washington state.

(iv) "Imported electricity" does not include electricity imports of unspecified electricity that are netted by exports of unspecified electricity to any jurisdiction not covered by a linked program by the same entity within the same hour.

(v) For a multijurisdictional electric company, "imported electricity" means electricity, other than from in-state facilities, that contributes to a common system power pool. Where a multijurisdictional electric company has a cost allocation methodology approved by the Washington state utilities and transportation commission, the allocation of specific facilities to Washington state's retail load will be in accordance with that methodology.

(vi) For a multijurisdictional consumer-owned utility, "imported electricity" includes electricity from facilities that contribute to a common system power pool that are allocated to a consumer-owned utility inside Washington state pursuant to a methodology approved by the governing board of the consumer-owned utility.

(h) "Multijurisdictional consumer-owned utility" means an electric generation and transmission cooperative owned by a collection of consumer-owned utilities in multiple states or a consumer-owned utility that provides electricity to member owners in Washington state and in one or more other states in a contiguous service territory or from a common power system.

(i) "Multijurisdictional electric company" means an investor-owned utility that provides electricity to customers in Washington state and in one or more other states in a contiguous service territory or from a common power system.

(j) "Multijurisdictional retail provider" means a:

(i) Multijurisdictional electric company; or

(ii) Multijurisdictional consumer-owned utility.

(k) "E-tag" means an energy tag representing transactions on the North American bulk electricity market scheduled to flow between or across balancing authority areas and to and from locations listed in an affiliated registry, as represented in a manner and form created by the North American Electric Reliability Corporation and as maintained by the North American Energy Standards Board or a successor organization.

(l) "Point of delivery" means a point on the electricity transmission or distribution system where a deliverer makes electricity available to a receiver, or available to serve load. This point may be an interconnection with another system or a substation where the transmission provider's transmission and distribution systems are connected to another system, or a distribution substation where electricity is imported into the state over a multijurisdictional retail provider's distribution system.

(m) "Specified source of electricity" or "specified source" means a facility, unit, or asset controlling supplier that is permitted to be claimed as the source of electricity delivered. The reporting entity must have either full or partial ownership in the facility or a written power contract to procure electricity generated by that facility or unit or from an asset controlling supplier at the time of entry into the transaction to procure electricity.

(n) "Unspecified source of electricity" or "unspecified source" means a source of electricity that is not a specified source at the time of entry into the transaction to procure electricity.

(o) "Electricity exporter" means electric power entities that deliver exported electricity. The entity that exports electricity is identified on the e-tag as the purchasing-selling entity (PSE) on the last segment of the tag's physical path, with the point of receipt located inside Washington state and the point of delivery located outside Washington state. For electricity that is exported from a designated scheduling point in the balancing authority area of a federal power marketing administration, the exporter is the purchasing-selling entity at the first point of the physical path of the e-tag that is not the generation source.

(p) "Electricity transaction" means the purchase, sale, import, export or exchange of electric power.

(q) "Energy imbalance market" or "EIM" means the western energy imbalance market operated by the California independent system operator.

(r) "Exported electricity" means electricity generated inside Washington state and delivered to serve load located outside Washington state. This includes electricity delivered from a first point of receipt inside Washington state, to the first point of delivery outside Washington state, with a final point of delivery outside Washington state. Exported electricity delivered across balancing authority areas is documented on e-tags with the first point of receipt located inside Washington state and the final point of delivery located outside Washington state. Exported electricity does not include electricity generated inside Washington state then transmitted outside of Washington state, but with a final point of delivery inside Washington state. Exported electricity does not include electricity generated inside Washington state that is allocated to serve Washington state retail customers of a multijurisdictional retail provider, consistent with a cost allocation methodology approved by the Washington state utilities and transportation commission and the utility regulatory commission of at least one additional state in which the multijurisdictional retail provider provides retail electric service.

(s) "Final point of delivery" means the sink specified on the e-tag, where defined points have been established through the affiliated registry. When e-tags are not used to document electricity deliveries, as may be the case within a balancing authority, the final point of delivery is the location of the load. Exported electricity is disaggregated by the final point of delivery on the e-tag.

(t) "First point of delivery in Washington" means the first defined point on the transmission system located inside Washington state at which imported electricity may be measured, consistent with defined points that have been established through the affiliated registry.

(u) "First point of receipt" means the generation source specified on the e-tag, where defined points have been established through the affiliated registry. When e-tags are not used to document electricity deliveries, as may be the case within a balancing authority, the first point of receipt is the location of the individual generating facility or unit, or group of generating facilities or units.

(v) "Grid" or "electric power grid" means a system of synchronized power providers and consumers connected by transmission and distribution lines and operated by one or more control centers.

(w) "Last point of delivery in Washington" means the last defined point on the transmission system located inside Washington state at which exported electricity may be measured, consistent with defined points that have been established through the North American Energy Standards Board Electric Industry Registry.

(x) "Marketer" means a purchasing-selling entity that delivers electricity and is not a retail provider.

(y) "Point of receipt" or "POR" means the point on an electricity transmission or distribution system where an electricity receiver receives electricity from a deliverer. This point can be an interconnection with another system or a substation where the transmission provider's transmission and distribution systems are connected to another system.

(z) "Power" means electricity, except where the context makes clear that another meaning is intended.

(aa) "Power contract" or "written power contract," as used for the purposes of documenting specified versus unspecified sources of imported and exported electricity, means a written document, including associated verbal or electronic records if included as part of the written power contract, arranging for the procurement of electricity. Power contracts may be, but are not limited to, power purchase agreements, enabling agreements, electricity transactions, and tariff provisions, without regard to duration, or written agreements to import or export on behalf of another entity, as long as that other entity also reports to ecology the same imported or exported electricity. A power contract for a specified source is a contract that is contingent upon delivery of power from a particular facility, unit, or asset-controlling supplier's system that is designated at the time the transaction is executed.

(bb) "Purchasing-selling entity" or "PSE" means the entity that is identified on an e-tag for each physical path segment.

(cc) "Retail end use customer" or "retail end user" means a residential, commercial, agricultural, or industrial electric customer who buys electricity to be consumed as a final product and not for resale.

(dd) "Retail sales" means electricity sold to retail end users.

(ee) "Sink" or "sink to load" or "load sink" means the sink identified on the physical path of e-tags, where defined points have been established through the affiliated registry. Exported electricity is disaggregated by the sink on the e-tag, also referred to as the final point of delivery on the e-tag.

(ff) "Source of generation" or "generation source" means the generation source identified on the physical path of e-tags, where defined points have been established through the affiliated registry. Imported electricity and wheels are disaggregated by the source on the e-tag, also referred to as the first point of receipt.

(gg) "Tolling agreement" means an agreement whereby a party rents a power plant from the owner. The rent is generally in the form of a fixed monthly payment plus a charge for every megawatt generated, generally referred to as a variable payment.

(3) Data requirements and calculation methods. The electric power entity who is required to report under WAC 173-441-030(3) of this chapter must comply with the following requirements.

(a) General requirements and content for GHG emissions data reports for electricity importers and exporters.

(i) Greenhouse gas emissions. The electric power entity must report GHG emissions separately for each category of delivered electricity required, in metric tons of CO2 equivalent (MT of CO2e), with biogenic CO2 reported separately, according to the calculation methods in this section.

(ii) Delivered electricity. The electric power entity must report imported and exported electricity in MWh disaggregated by first point of receipt (POR) or final point of delivery, as applicable, and must also separately report imported and exported electricity from unspecified sources and the energy imbalance market, and from each specified source. First points of receipt and final points of delivery (POD) must be reported using the standardized code used in e-tags, as well as the full name of the POR/POD.

(iii) Imported electricity from unspecified sources. When reporting imported electricity delivered from unspecified sources, the electric power entity must report for each first point of receipt the following information:

(A) Whether the first point of receipt is located in a linked jurisdiction published on the ecology website;

(B) The amount of electricity from unspecified sources as measured at the first point of delivery in Washington state;

(C) The amount of electricity imports of unspecified electricity that are netted by exports of unspecified electricity to any jurisdiction not covered by a linked program by the same entity within the same hour.

(D) The net amount of imported unspecified electricity after taking into account the requirements in (a)(iii)(C) of this subsection.

(E) GHG emissions, including those associated with transmission losses, as required in this section.

(F) When the unspecified power was obtained from the energy imbalance market.

(iv) Delivered electricity from specified facilities or units. The electric power entity must report all direct delivery of electricity as from a specified source for facilities or units in which they are a generation providing entity (GPE) or have a written power contract to procure electricity. An electric power entity must report imported electricity as from a specified source when the electricity power entity is a GPE of that facility. When reporting imported electricity from specified facilities or units, the electric power entity must disaggregate electricity deliveries and associated GHG emissions by facility or unit and by first point of receipt, as applicable. The reporting entity must also report total GHG emissions and MWh from specified sources and the sum of emissions from specified sources explicitly listed as not covered in chapter 70A.65 RCW, as described in chapter 173-446 WAC. Seller Warranty: The sale or resale of specified source electricity is permitted among entities on the e-tag market path insofar as each sale or resale is for specified source electricity in which sellers have purchased and sold specified source electricity, such that each seller warrants the sale of specified source electricity from the source through the market path. Claims of specified sources of imported electricity, must include the following information:

(A) Measured at busbar. The amount of imported electricity from specified facilities or units as measured at the busbar; and

(B) Not measured at busbar. If the amount of imported electricity deliveries from specified facilities or units as measured at the busbar is not provided, report the amount of imported electricity as measured at the first point of delivery in Washington state, including estimated transmission losses as required in this section and the reason why measurement at the busbar is not known.

(v) Imported electricity from the energy imbalance market. The reporting entity must separately report power obtained from the energy imbalance market.

(vi) Imported electricity supplied by asset-controlling suppliers. The reporting entity must separately report imported electricity supplied by asset-controlling suppliers recognized by ecology. The reporting entity must:

(A) Report the asset-controlling supplier standardized purchasing-selling entity (PSE) acronym or code, full name, and the ecology identification number;

(B) Report asset-controlling supplier power that was not acquired as specified power, as unspecified power;

(C) Report delivered electricity from asset-controlling suppliers as measured at the first point of delivery in Washington state; and

(D) Report GHG emissions calculated pursuant to this section, including transmission losses.

(E) To claim power from an asset-controlling supplier, the asset-controlling supplier must be identified in one of the following means:

(I) On the physical path of the e-tag as the PSE at the first point of receipt, or in the case of asset-controlling suppliers that are exclusive marketers, as the PSE immediately following the associated generation owner; or

(II) If there is no e-tag associated with the imported electricity, on a long-term contract that identifies the ACS as the relevant provider of that electricity.

(vii) Exported electricity. The electric power entity must report exported electricity in MWh and associated GHG emissions in MT of CO2e for unspecified sources disaggregated by each final point of delivery outside Washington state, and for each specified source disaggregated by each final point of delivery outside Washington state, as well as the following information:

(A) Exported electricity as measured at the last point of delivery located in Washington state, if known. If unknown, report as measured at the final point of delivery outside Washington state.

(B) Do not report estimated transmission losses.

(C) Report whether the final point of delivery is located in a linked jurisdiction published on the ecology website.

(D) Report GHG emissions calculated pursuant to this section.

(viii) Exchange agreements. The electric power entity must report delivered electricity under power exchange agreements consistent with imported and exported electricity requirements of this section. Electricity delivered into Washington state under exchange agreements must be reported as imported electricity and electricity delivered out of Washington state under exchange agreements must be reported as exported electricity.

(ix) Verification documentation. The electric power entity must retain for purposes of verification documentation of e-tags, written power contracts, settlements data, and all other information required to confirm reported electricity procurements and deliveries pursuant to the recordkeeping requirements of WAC 173-441-050.

(x) Electricity generating units and cogeneration units in Washington state. Electric power entities that also operate electricity generating units or cogeneration units located inside Washington state that meet the applicability requirements of WAC 173-441-030(1) must report GHG emissions to ecology under WAC 173-441-120.

(xi) Electricity generating units and cogeneration units outside Washington state. Operators and owners of electricity generating units and cogeneration units located outside Washington state who elect to report to ecology under WAC 173-441-030(5) must fully comply with the reporting and verification requirements of this chapter.

(b) Calculating GHG emissions.

(i) Calculating GHG emissions from unspecified sources. For electricity from unspecified sources, the electric power entity must calculate the annual CO2 equivalent mass emissions using the method established in WAC 173-444-040(4) and based on the amount of net imported electricity reported consistent with (a)(iii)(D) of this subsection.

(ii) Calculating GHG emissions from specified facilities or units. For electricity from specified facilities or units, the electric power entity must calculate emissions using the following equation:

(A) Ecology shall calculate facility-specific or unit-specific emission factors and publish them on the ecology website using the following equation:

(B) To register a specified unit(s) source of power, the reporting entity must provide to ecology unit level GHG emissions consistent with the data source requirements of this section and net generation data as reported to the EIA, along with contracts for delivery of power from the specified unit(s) to the reporting entity, and proof of direct delivery of the power by the reporting entity as an import to Washington state.

(I) For specified facilities or units whose operators are subject to this chapter or whose owners or operators voluntarily report under this chapter, Esp shall be equal to the sum of CO2e emissions reported pursuant to this section.

(II) For specified facilities or units whose operators are not subject to reporting under this chapter or whose owners or operators do not voluntarily report under this chapter, but are subject to the U.S. EPA GHG Mandatory Reporting Regulation, Esp shall be based on GHG emissions reported to U.S. EPA pursuant to 40 C.F.R. Part 98. For GHG emissions reported to U.S. EPA pursuant to 40 C.F.R. Part 98, if it is not possible to isolate the emissions that are directly related to electricity production, ecology may calculate Esp based on EIA data. Emissions from combustion of biomass-derived fuels will be based on EIA data until such time the emissions are reported to U.S. EPA.

(III) For specified facilities or units whose operators are not subject to reporting under this chapter or whose owners or operators do not voluntarily report under this chapter, nor are subject to the U.S. EPA GHG Mandatory Reporting Regulation, Esp is calculated using heat of combustion data reported to the Energy Information Administration (EIA) as shown below.

(IV) Facilities or units will be assigned an emission factor by the ecology based on the type of fuel combusted or the technology used when a U.S. EPA GHG Report or EIA fuel consumption report is not available, including new facilities and facilities located outside the U.S.

(V) Meter data requirement. For verification purposes, electric power entities shall retain meter generation data to document that the power claimed by the reporting entity was generated by the facility or unit at the time the power was directly delivered.

(VI) A lesser of analysis is applicable to imports from specified sources for which ecology has calculated an emission factor of zero, and for imports from Washington renewable portfolio standard (RPS) eligible resources, excluding the following: Dynamically tagged power deliveries; nuclear power; asset controlling supplier power; and imports from hydroelectric facilities for which an entity's share of metered output on an hourly basis is not established by power contract. A lesser of analysis is required pursuant to the following equation:

(iii) Calculating GHG emissions of imported electricity supplied by asset-controlling suppliers. Based on annual reports submitted to ecology pursuant to WAC 173-441-070(3), ecology will calculate and publish on the ecology website the system emission factor for all asset-controlling suppliers recognized by the ecology. The reporting entity must calculate emissions for electricity supplied using the following equation:

Ecology must calculate the system emission factor for asset-controlling suppliers using the following equations:

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PDF173-441-140

Petitioning ecology to use an alternative calculation method to calculate greenhouse gas emissions.

An owner or operator may petition ecology to use calculation methods other than those specified in WAC 173-441-120, 173-441-122, or 173-441-124 to calculate GHG emissions. The following requirements apply to the submission, review, and approval or denial of a petition:

(1) Petition submittal. An owner or operator must submit a petition that meets the following conditions before ecology may review the petition and issue a determination.

(a) An owner or operator must submit a complete petition no later than 180 calendar days prior to the emissions report deadline established in WAC 173-441-050(2). Such petition must include sufficient information, as described in (b) of this subsection, for ecology to determine whether the proposed alternative calculation method will provide emissions data sufficient to meet the reporting requirements of RCW 70A.15.2200. Ecology will notify the owner or operator within 30 calendar days of receipt of a petition of any additional information ecology requires to approve the proposed calculation methods in the petition. If a petition is under review by ecology at the time an annual emissions report is due under WAC 173-441-050(2), the owner or operator must submit the emissions report using the calculation methods approved under this chapter at the time of submittal of the emissions report.

(b) The petition must include, at a minimum, the following information:

(i) Identifying information as specified in WAC 173-441-060 (9)(b) and 173-441-060 (13)(b)(ii) of the designated representative and any agent submitting a petition;

(ii) Identifying information as specified in WAC 173-441-050 (3)(a) of the facility or facilities where the owner or operator proposes to use the alternative calculation method;

(iii) A clear and complete reference to the subparts or sections in EPA's mandatory greenhouse gas reporting regulation that contain the alternative calculation method and the date that EPA adopted the subparts or sections;

(iv) The source categories that will use the alternative calculation method;

(v) The date that the owner or operator intends to start using the alternative calculation method;

(vi) Any other supporting data or information as requested by ecology as described in subsection (2) of this section; and

(vii) The designated representative must sign and date the petition.

(2) Ecology review of the petition. Ecology must approve the alternative calculation method before the owner or operator may use it to report GHG emissions. Ecology will issue a determination within 60 calendar days of receiving a complete petition. The alternative calculation method must meet the following conditions:

(a) Except as noted in (b) of this subsection, alternative calculation methods for reporters required to report under WAC 173-441-030 must be methods adopted by the United States Environmental Protection Agency in its mandatory greenhouse gas reporting regulation, or otherwise more recent versions of methods adopted in this chapter. The alternative calculation method must be more recent than the method for the given source category adopted by reference in WAC 173-441-120, 173-441-122, or 173-442-124.

(b) For GHG emissions reported voluntarily under WAC 173-441-030 (5), ecology must apply the following criteria when evaluating an alternative calculation method:

(i) If the GHG emissions are covered by a source category adopted by reference in WAC 173-441-120, 173-441-122, or 173-442-124, then the requirements of (a) and (b) of this subsection apply.

(ii) If the GHG emissions are not covered by a source category adopted by reference in WAC 173-441-120, 173-441-122, or 173-441-124, then ecology must consider whether the methods meet the following criteria:

(A) The alternative calculation method is established by a nationally or internationally recognized body in the field of GHG emissions reporting such as:

(I) Ecology;

(II) EPA;

(III) California Air Resources Board;

(IV) The Intergovernmental Panel on Climate Change;

(B) If an alternative calculation method is not available from sources listed in (b)(ii)(A) of this subsection, then ecology may accept a method from an industry or trade association or devised by the owner or operator if ecology determines the alternative calculation method is consistent with the requirements established under RCW 70A.15.2200.

(c) For all source categories, including those covered in (a) and (b) of this subsection, the alternative calculation method must be consistent in content and scope with the requirements established under RCW 70A.15.2200. In the event that a proposed alternative calculation method does not include all required GHG emissions, the owner or operator must use the calculation methods specified in subsection (3) of this section to calculate those emissions.

(3) Calculating emissions not included in alternative calculation method. An owner or operator must report all source categories of GHG emissions for which reporting is required under RCW 70A.15.2200 and for which calculation methods have been established in WAC 173-441-120, 173-441-122, or 173-441-124. If an approved alternative calculation method does not include calculation methods for all required source categories of emissions, then the owner or operator must use a method described in WAC 173-441-120, 173-441-122, 173-441-124, or approved for the owner or operator by ecology in a separate petition to calculate and report those emissions.

(4) Appeal of determination. An approval or denial issued by ecology in response to a written petition filed under this subsection is a determination appealable to the pollution control hearings board per RCW 43.21B.110 (1)(h).

[Statutory Authority: RCW 70A.15.2200. WSR 22-05-050 (Order 21-07), § 173-441-140, filed 2/9/22, effective 3/12/22. Statutory Authority: Chapters 70.235 and 70.94 RCW. WSR 15-04-051 (Order 13-13), § 173-441-140, filed 1/29/15, effective 3/1/15. Statutory Authority: 2010 c 146, and chapters 70.235 and 70.94 RCW. WSR 10-24-108 (Order 10-08), § 173-441-140, filed 12/1/10, effective 1/1/11.]

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PDF173-441-150

Confidentiality.

(1) Emissions data submitted to ecology under this chapter are public information and must not be designated as confidential.

(2) Information considered confidential by EPA or other jurisdictions is not considered confidential by ecology unless it also meets the conditions established in subsection (3) of this section.

(3) Any person submitting information to ecology under this chapter may request that ecology keep information that is not emissions data confidential as proprietary information under RCW 70A.15.2510 or because it is otherwise exempt from public disclosure under the Washington Public Records Act (chapter 42.56 RCW). All such requests for confidentiality must meet the requirements of RCW 70A.15.2510.

(4) Ecology's determinations of the verification status of each report are public information. All confidential data used in the verification process will remain confidential.

[Statutory Authority: RCW 70A.15.2200. WSR 22-05-050 (Order 21-07), § 173-441-150, filed 2/9/22, effective 3/12/22. Statutory Authority: 2010 c 146, and chapters 70.235 and 70.94 RCW. WSR 10-24-108 (Order 10-08), § 173-441-150, filed 12/1/10, effective 1/1/11.]

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PDF173-441-160

Ecology to share information with local air authorities and with the energy facility site evaluation council.

(1) Ecology must share any reporting information reported to it with the local air authority in which the person reporting under these rules operates.

(2) Ecology must share with the energy facility site evaluation council any information reported to ecology under these rules by facilities permitted by the council, including notice of a facility that has failed to report as required.

[Statutory Authority: 2010 c 146, and chapters 70.235 and 70.94 RCW. WSR 10-24-108 (Order 10-08), § 173-441-160, filed 12/1/10, effective 1/1/11.]

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PDF173-441-170

Severability.

If any provision of the regulation or its application to any person or circumstance is held invalid, the remainder of the regulation or application of the provision to other persons or circumstances is not affected.

[Statutory Authority: 2010 c 146, and chapters 70.235 and 70.94 RCW. WSR 10-24-108 (Order 10-08), § 173-441-170, filed 12/1/10, effective 1/1/11.]