
•	Adds natural gas suppliers, carbon dioxide suppliers, and electric power entities to the existing GHG reporting program.
•	Replaces the existing transportation fuel supplier program with a CCA-compatible fuel supplier program.
•	Updates GHG reporting requirements to support the CCA and facilitates program linkage with other jurisdictions.
•	Adds program elements to support the verification of GHG reporting data.
•	Modifies administrative provisions such as deadlines and GHG reporting fees.
•	Includes requirements necessary to support the above items, the overall objectives of the statute or chapter, or the goals of the CCA.
•	Makes administrative changes for correction or clarification.


•	Compliance requirements of the proposed rule.
•	Results of the analysis of relative compliance cost burden.
•	Consideration of lost sales or revenue.
•	Cost-mitigating action taken by ecology, if required.
•	Small business and local government consultation.
•	Industries likely impacted by the proposed rule.
•	Expected net impact on jobs statewide.


•	Existing rule: Chapter 173-441 WAC, Reporting of emissions of greenhouse gases.
•	Authorizing statute: CCA (E2SSB 5126), chapter 316, Laws of 2021.
•	Federal Clean Air Act, 42 U.S.C. §§ 7401 et seq.
•	Washington Clean Air Act, chapter 70A.15 RCW.
•	Limiting greenhouse gas emissions, chapter 70A.45 RCW.
•	Existing federal and state regulations, including those covering GHG reporting at the federal level.


•	Applicability and definitions: The rule would require facilities, suppliers, and electric power entities emitting at least 10,000 metric tons of carbon dioxide equivalent (MTCO2e) GHG per year to report GHG emissions to ecology. Many already report under the existing rules, but the amendment adds electric power entities and some suppliers.
•	Reporting: Expands calculation and report content, including production, fuel use, and electricity use.
•	Third party verification: Reporters emitting at least 25,000 MTCO2e per year or with a compliance obligation under the CCA would need to have verification performed by a third party.
•	Fees: While the rule would continue to base total fees on program administration costs, it would reallocate fees based on degree of third party verification required.
•	Administrative changes such as changing the reporting deadline to match the new deadline set in statute and various clarifications and corrections.


•	Add definitions consistent with statute.
•	Remove references to the Washington state department of licensing, as they are no longer relevant.
•	Amend the definition of facility to account for other specifications in rule.
•	Remove overlap of facility and supplier terminology.
•	Add fuel-related definitions necessary for implementation, and assumptions for consistency with statute.
•	Add definitions specific to the CCA program, per statute.
•	Add definitions consistent with statutory requirements for consistency with federal definitions.


•	Add electric power entities, per statute.
•	Add reporting threshold of 10,000 MTCO2e per year for suppliers and electric power entities, from all source categories, per statute.
•	Amend supplier reporting basis to be the statutory threshold, based on all source categories.
•	Add electric power entity reporting basis to be the statutory threshold, based on all source categories.
•	Add specification that reporters with a compliance obligation under the CCA program must report for any year with an obligation, per statute.


•	Set a universal reporting deadline of March 31, for mandatory and voluntary reporters, per statute.
•	Allow electric power entities to submit a provisional report by March 31, followed by a final report by June 1.
•	Added report contents.
•	Require reporters to use the same emission calculation methods for all reports, but provide a process to request approval to change the method.
•	Specify that reporters must cooperate with ecology verification efforts.
•	Extend recordkeeping from three years to 10 years. This is consistent with California reporting, per statute.
•	Specify a limit of 15 business days to provide ecology with records upon request.
•	Monitoring plan.
•	Clarify that "days" refers to calendar days unless otherwise specified.
•	Increase the number of days a reporter has to request an extension from two days to five days before the report is due and reduce the length of the extension from 30 days to 15 days.
•	Calibration and accuracy.
•	Clarify that facilities use emissions calculations to determine their reporting requirements.
•	Specify which emissions calculation equations municipal solid waste landfills must use for reporting.
•	Specify that entities must report supplied CO2 from facilities, but it does not count toward the reporting threshold.
•	Add calculation methods for suppliers. This is consistent with California reporting, per statute.
•	Add calculation methods for electric power entities. This is consistent with California reporting, per statute.
•	Require electric power entities that import or export electricity to prepare GHG inventory program documentation, in lieu of a GHG monitoring plan.


•	Designated representatives.
•	Certification.
•	Report submittal.
•	Standardized methods and conversion factors incorporated by reference.
•	Petition for alternative methods.


•	Require third party verification for some reporters.
•	Require third party verification for some years.
•	Specify that previously verified emissions factors meeting certain standards do not need reverification, but reports using them do.
•	Allow a maximum five percent discrepancy between reported emissions and verified emissions.
•	Require full third party verification (including site visit), except for reporters without compliance obligation under CCA, once every three years. Use the subsequent two years for less-intensive verification.
•	Add a list of what verification data checks must include.
•	Set a deadline for corrections after verification.
•	Verification report.
•	Limit eligible verifiers to those accredited under the California Air Resources Board (CARB) program.
•	Clarify that conflict of interest does not include working for a reporter to verify GHG emissions in another jurisdiction.
•	Specify that ecology may assign an emissions level in cases of discrepancy, per statute.
•	Specify that ecology may assign the emissions level used under the CCA program, per statute.


•	$700 for reporters not subject to third party verification.
•	$4,000 for reporters subject to third party verification.


•	In addition to six likely new suppliers identified, based on ecology staff professional judgment and experience implementing the GHG reporting program, we assumed between 10 and 20 additional suppliers would become reporters.
•	Based on professional judgement and experience, as well as corroborating information from the Bonneville Power Administration and Washington utilities and transportation commission, we assumed between 50 and 60 electric power entities would become reporters.


•	Facilities (all existing reporters):


º	$5,824 in the first year.
º	$2,229 in subsequent years.


•	Existing supplier reporters:


º	$54,499 in the first year.
º	$52,680 in subsequent years.


•	New supplier reporters:


º	$24,591 - $39,960 in the first year.
º	$23,702 - $38,515 in subsequent years.


•	Electric power entities (all new reporters):


º	$76,846 - $92,215 in the first year.
º	$74,068 - $88,881 in subsequent years.


•	Must undergo full verification the first year of each three-year compliance period, followed by less intensive verification the remaining two years, if they have a compliance obligation under the CCA.
•	Must undergo less intensive verification if they emit over 25,000 MTCO2e per year and do not have a compliance obligation under the CCA.


•	$2,635 per facility.
•	$0 per transportation fuel supplier.


•	$700 for reporters not subject to third party verification.
•	$4,000 for reporters subject to third party verification.


•	Manufacturing: $1 million to $1.2 million.
•	Construction: $600,000 to $1.2 million.
•	Utilities: $600,000 to $1.2 million.


•	Are legal and feasible.
•	Meet the goals and objectives of the authorizing statute.
•	Are within the scope of this rule making.


•	The baseline rule and proposed amendments are reporting rules only. They do not contain substantive regulatory requirements, and we are not proposing any for addition.
•	Recordkeeping and reporting requirements would rely largely on maintaining consistency with other programs, using known operations data and information, and using standardized common calculations.
•	If we consider the equivalent of inspections for the proposed amendments to the reporting rule to be third party verification, the proposed rule amendments limit this verification to where it is necessary for data quality assurance in its support of the CCA program (as required by statute). Smaller reporters are less likely to have compliance obligations or emissions over the threshold that would require third party verification.
•	As part of this rule making, ecology received information that electric power entities (many of which are small) desired later deadlines. While the statute specifies the reporting deadline, the proposed rule amendments require electric power entities to submit a provisional report by the statutory deadline, followed by a final report two months later as proposed by stakeholders. Ecology also made changes to third party verification to streamline the process for smaller utilities.


•	Rule announcement notice sent via email to:


º	Rules and state implementation plan (SIP) listserv.
º	GHG reporting listserv.
º	CCA listserv.
º	Current GHG reporters.
º	WAC track (rule making).


•	Stakeholder meeting materials sent on July 15, 2021, to:


º	Registered participants.
º	GHG reporting listserv.
º	Current GHG reporters.


•	Stakeholder meeting on July 22, 2021, to provide overview of rule changes and get feedback on draft rule language.

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; ((and)) 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 (((1))) must be applied independently of the requirements of the other subsections(((2))). 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 ten thousand 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.

Where:
	CO2e	=	Carbon dioxide equivalent, metric tons/year.
	GHGi	=	Mass emissions of each greenhouse gas listed in Table A-1 of WAC 173-441-040, metric tons/year.
	GWPi	=	Global warming potential for each greenhouse gas from Table A-1 of WAC 173-441-040.
	n	=	The number of greenhouse gases emitted.

(((iv) Include in the emissions calculation any CO2 that is captured for transfer off-site.))

(2) Supplier((s))reporting. Reporting is mandatory for an owner or operator of any supplier ((required to file periodic tax reports to DOL and has))with total ((carbon dioxide))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 ((supplies applicable fuels that are reported to DOL as sold in Washington state of which the complete combustion or oxidation would result in total calendar year emissions of ten thousand metric tons or more of carbon dioxide))produces, imports, or delivers ten thousand 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 ((CO2GHC))GHG emissions for comparison to the reporting threshold, ((a supplier))the owner or operator must:

(i) ((Base its emissions on the applicable fuel quantities as established in WAC 173-441-130(1) and reported to DOL. A supplier must apply the mass in metric tons per year of CO2 that would result from the complete combustion or oxidation of these fuels towards the reporting threshold.

(ii) Calculate the total annual carbon dioxide emissions in metric tons from all applicable fuel quantities and fuel types as established in WAC 173-441-130(1) and reported to DOL. The CO2 emissions must be calculated using the calculation methodologies specified in WAC 173-441-130 and data reported to DOL.

(iii) Only include emissions of carbon dioxide associated with the complete combustion or oxidation of the applicable fuels. Include all CO2 emissions from the combustion of biomass fuels.

(3)))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. 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 ten thousand 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.

(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 ((either)) subsection (1) ((or)), (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) ((or)), (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 ((facility or supplier))reporter to meet the applicability requirements of subsection (1) ((or)), (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.

(((4)))(5)Voluntary reporting. A person may choose to voluntarily report to ecology GHG emissions that are not required to be reported under subsection (1) ((or)), (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 ((173-441-130))173-441-124 (1)(c) to calculate any voluntarily reported GHG emissions.

(((5)))(6)Reporting requirements when emissions of greenhouse gases fall below reporting thresholds. Except as provided in this subsection, once a ((facility or supplier))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 ((facility or supplier))reporter does not meet the applicability requirements in subsection (1) ((or)), (2), or (3) of this section in a future year. Reporters with a compliance obligation under chapter 316, Laws of 2021, 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 ten thousand 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 ten thousand 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 ((three))ten 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 five thousand 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 ((three))ten 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 ((facility or supplier))reporter are changed such that all applicable GHG-emitting processes and operations listed in WAC 173-441-120, 173-441-122, and ((173-441-130))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.

Table A-1:

Global Warming Potentials (100-Year Time Horizon)

Name	CAS No.	Chemical Formula	GWP (100 yr.)1,2
Name	CAS No.	Chemical Formula	2012-2013	≥ 20143,4
Carbon dioxide	124-38-9	CO2	1	1
Methane	74-82-8	CH4	21	25
Nitrous oxide	10024-97-2	N2O	310	298
Fully Fluorinated GHGs
Sulfur hexafluoride	2551-62-4	SF6	23,900	22,800
Trifluoromethyl sulphur pentafluoride	373-80-8	SF5CF3	17,700	17,700
Nitrogen trifluoride	7783-54-2	NF3	17,200	17,200
PFC-14 (Perfluoromethane)	75-73-0	CF4	6,500	7,390
PFC-116 (Perfluoroethane)	76-16-4	C2F6	9,200	12,200
PFC-218 (Perfluoropropane)	76-19-7	C3F8	7,000	8,830
Perfluorocyclopropane	931-91-9	C-C3F6	17,340	17,340
PFC-3-1-10 (Perfluorobutane)	355-25-9	C4F10	7,000	8,860
PFC-318 (Perfluorocyclobutane)	115-25-3	C-C4F8	8,700	10,300
PFC-4-1-12 (Perfluoropentane)	678-26-2	C5F12	7,500	9,160
PFC-5-1-14 (Perfluorohexane, FC-72)	355-42-0	C6F14	7,400	9,300
PFC-6-1-12 (Hexadecafluoroheptane)	335-57-9	C7F16; CF3(CF2)5CF3	7,820	7,820
PFC-7-1-18 (Octadecafluorooctane)	307-34-6	C8F18; CF3(CF2)6CF3	7,620	7,620
PFC-9-1-18	306-94-5	C10F18	7,500	7,500
PFPMIE (HT-70)	NA	CF3OCF(CF3)CF2OCF2OCF3	10,300	10,300
Perfluorodecalin (cis)	60433-11-6	Z-C10F18	7,236	7,236
Perfluorodecalin (trans)	60433-12-7	E-C10F18	6,288	6,288
Saturated Hydrofluorocarbons (HFCs) with Two or Fewer Carbon-Hydrogen Bonds
HFC-23	75-46-7	CHF3	11,700	14,800
HFC-32	75-10-5	CH2F2	650	675
HFC-125	354-33-6	C2HF5	2,800	3,500
HFC-134	359-35-3	C2H2F4	1,000	1,100
HFC-134a	811-97-2	CH2FCF3	1,300	1,430
HFC-227ca (1,1,1,2,2,3,3-Heptafluoropropane)	2252-84-8	CF3CF2CHF2	2,640	2,640
HFC-227ea	431-89-0	C3HF7	2,900	3,220
HFC-236cb	677-56-5	CH2FCF2CF3	1,340	1,340
HFC-236ea	431-63-0	CHF2CHFCF3	1,370	1,370
HFC-236fa	690-39-1	C3H2F6	6,300	9,810
HFC-329p (1,1,1,2,2,3,3,4,4-Nonafluorobutane)	375-17-7	CHF2CF2CF2CF3	2,360	2,360
HFC-43-10mee	138495-42-8	CF3CFHCFHCF2CF3	1,300	1,640
Saturated Hydrofluorocarbons (HFCs) with Three or More Carbon-Hydrogen Bonds
HFC-41	593-53-3	CH3F	150	92
HFC-143	430-66-0	C2H3F3	300	353
HFC-143a	420-46-2	C2H3F3	3,800	4,470
HFC-152	624-72-6	CH2FCH2F	53	53
HFC-152a	75-37-6	CH3CHF2	140	124
HFC-161	353-36-6	CH3CH2F	12	12
HFC-245ca	679-86-7	C3H3F5	560	693
HFC-245cb (1,1,1,2,2-Pentafluoropropane)	1814-88-6	CF3CF2CH3	4,620	4,620
HFC-245ea (1,1,2,3,3-Pentafluoropropane)	24270-66-4	CHF2CHFCHF2	235	235
HFC-245eb (1,1,1,2,3-Pentafluoropropane)	431-31-2	CH2FCHFCF3	290	290
HFC-245fa	460-73-1	CHF2CH2CF3	1,030	1,030
HFC-263fb (1,1,1-Trifluoropropane)	421-07-8	CH3CH2CF3	76	76
HFC-272ca (2,2-Difluoropropane)	420-45-1	CH3CF2CH3	144	144
HFC-365mfc	406-58-6	CH3CF2CH2CF3	794	794
Saturated Hydrofluoroethers (HFEs) and Hydrochlorofluoroethers (HCFEs) with One Carbon-Hydrogen Bond
HFE-125	3822-68-2	CHF2OCF3	14,900	14,900
HFE-227ea	2356-62-9	CF3CHFOCF3	1,540	1,540
HFE-329mcc2	134769-21-4	CF3CF2OCF2CHF2	919	919
HFE-329me3 (1,1,1,2,3,3-Hexafluoro-3- (trifluoromethoxy)propane)	428454-68-6	CF3CFHCF2OCF3	NA	4,550*
1,1,1,2,2,3,3-Heptafluoro-3-(1,2,2,2-tetrafluoroethoxy)-propane	3330-15-2	CF3CF2CF2OCHFCF3	NA	6,490*
Saturated HFEs and HCFEs with Two Carbon-Hydrogen Bonds
HFE-134 (HG-00)	1691-17-4	CHF2OCHF2	6,320	6,320
HFE-236ca (1-(Difluoromethoxy)- 1,1,2,2-tetrafluoroethane)	32778-11-3	CHF2OCF2CHF2	NA	4,240*
HFE-236ca12 (HG-10)	78522-47-1	CHF2OCF2OCHF2	2,800	2,800
HFE-236ea2 (Desflurane)	57041-67-5	CHF2OCHFCF3	989	989
HFE-236fa	20193-67-3	CF3CH2OCF3	487	487
HFE-338mcf2	156053-88-2	CF3CF2OCH2CF3	552	552
HFE-338mmz1	26103-08-2	CHF2OCH(CF3)2	380	380
HFE-338pcc13 (HG-01)	188690-78-0	CHF2OCF2CF2OCHF2	1,500	1,500
HFE-43-10pccc (H-Galden 1040x, HG-11)	E1730133	CHF2OCF2OC2F4OCHF2	1,870	1,870
HCFE-235ca2 (Enflurane) (2-Chloro-1-(difluoromethoxy)- 1,1,2-trifluoroethane)	13838-16-9	CHF2OCF2CHFCl	NA	583*
HCFE-235da2 (Isoflurane)	26675-46-7	CHF2OCHClCF3	350	350
HG-02 (1-(Difluoromethoxy)-2- (2-(difluoromethoxy)-1,1,2,2- tetrafluoroethoxy)-1,1,2,2- tetrafluoroethane)	205367-61-9	HF2C-(OCF2CF2)2-OCF2H	NA	3,825*
HG-03 (1,1,3,3,4,4,6,6,7,7,9,9,10,10,12,12-Hexadecafluoro-2,5,8,11-tetraoxadodecane)	173350-37-3	HF2C-(OCF2CF2)3-OCF2H	NA	3,670*
HG-20 ((Difluoromethoxy) ((difluoromethoxy) difluoromethoxy) difluoromethane)	249932-25-0	HF2C-(OCF2)2-OCF2H	NA	5,300*
HG-21 (1,1,3,3,5,5,7,7,8,8,10,10-Dodecafluoro-2,4,6,9-tetraoxadecane)	249932-26-1	HF2C-OCF2CF2OCF2OCF2O-CF2H	NA	3,890*
HG-30 (1,1,3,3,5,5,7,7,9,9-Decafluoro-2,4,6,8-tetraoxanonane)	188690-77-9	HF2C-(OCF2)3-OCF2H	NA	7,330*
1,1,3,3,4,4,6,6,7,7,9,9,10,10,12,12,13,13,15,15-eicosafluoro-2,5,8,11,14-Pentaoxapentadecane	173350-38-4	HCF2O(CF2CF2O)4CF2H	NA	3,630*
1,1,2-Trifluoro-2- (trifluoromethoxy)-ethane	84011-06-3	CHF2CHFOCF3	NA	1,240*
Trifluoro (fluoromethoxy) methane	2261-01-0	CH2FOCF3	NA	751*
Saturated HFEs and HCFEs with Three or More Carbon-Hydrogen Bonds
HFE-143a	421-14-7	CH3OCF3	756	756
HFE-245cb2	22410-44-2	CH3OCF2CF3	708	708
HFE-245fa1	84011-15-4	CHF2CH2OCF3	286	286
HFE-245fa2	1885-48-9	CHF2OCH2CF3	659	659
HFE-254cb2	425-88-7	CH3OCF2CHF2	359	359
HFE-263fb2	460-43-5	CF3CH2OCH3	11	11
HFE-263m1; R-E-143a (1,1,2,2-Tetrafluoro-1- (trifluoromethoxy)ethane)	690-22-2	CF3OCH2CH3	NA	29*
HFE-347mcc3 (HFE-7000)	375-03-1	CH3OCF2CF2CF3	575	575
HFE-347mcf2	171182-95-9	CF3CF2OCH2CHF2	374	374
HFE-347mmy1	22052-84-2	CH3OCF(CF3)2	343	343
HFE-347mmz1; Sevoflurane (2-(Difluoromethoxy)- 1,1,1,3,3,3-hexafluoropropane)	28523-86-6	(CF3)2CHOCHF2	NA	216*
HFE-347pcf2	406-78-0	CHF2CF2OCH2CF3	580	580
HFE-356mec3	382-34-3	CH3OCF2CHFCF3	101	101
HFE-356mff2 (bis(2,2,2-trifluoroethyl) ether)	333-36-8	CF3CH2OCH2CF3	NA	17*
HFE-356mmz1	13171-18-1	(CF3)2CHOCH3	27	27
HFE-356pcc3	160620-20-2	CH3OCF2CF2CHF2	110	110
HFE-356pcf2	50807-77-7	CHF2CH2OCF2CHF2	265	265
HFE-356pcf3	35042-99-0	CHF2OCH2CF2CHF2	502	502
HFE-365mcf2 (1-Ethoxy-1,1,2,2,2-pentafluoroethane)	22052-81-9	CF3CF2OCH2CH3	NA	58*
HFE-365mcf3	378-16-5	CF3CF2CH2OCH3	11	11
HFE-374pc2	512-51-6	CH3CH2OCF2CHF2	557	557
HFE-449sl (HFE-7100) Chemical blend	163702-07-6 163702-08-7	C4F9OCH3 (CF3)2CFCF2OCH3	297	297
HFE-569sf2 (HFE-7200) Chemical blend	163702-05-4 163702-06-5	C4F9OC2H5 (CF3)2CFCF2OC2H5	59	59
HG'-01 (1,1,2,2-Tetrafluoro-1,2-dimethoxyethane)	73287-23-7	CH3OCF2CF2OCH3	NA	222*
HG'-02 (1,1,2,2-Tetrafluoro-1-methoxy-2-(1,1,2,2-tetrafluoro-2-methoxyethoxy)ethane)	485399-46-0	CH3O(CF2CF2O)2CH3	NA	236*
HG'-03 (3,3,4,4,6,6,7,7,9,9,10,10-Dodecafluoro-2,5,8,11-tetraoxadodecane)	485399-48-2	CH3O(CF2CF2O)3CH3	NA	221*
Difluoro(methoxy)methane	359-15-9	CH3OCHF2	NA	144*
2-Chloro-1,1,2-trifluoro-1-methoxyethane	425-87-6	CH3OCF2CHFCl	NA	122*
1-Ethoxy-1,1,2,2,3,3,3-heptafluoropropane	22052-86-4	CF3CF2CF2OCH2CH3	NA	61*
2-Ethoxy-3,3,4,4,5- pentafluorotetrahydro-2,5-bis [1,2,2,2-tetrafluoro-1- (trifluoromethyl)ethyl]-furan	920979-28-8	C12H5F19O2	NA	56*
1-Ethoxy-1,1,2,3,3,3-hexafluoropropane	380-34-7	CF3CHFCF2OCH2CH3	NA	23*
Fluoro(methoxy)methane	460-22-0	CH3OCH2F	NA	13*
1,1,2,2-Tetrafluoro-3-methoxy-propane; Methyl 2,2,3,3-tetrafluoropropyl ether	60598-17-6	CHF2CF2CH2OCH3	NA	0.5*
1,1,2,2-Tetrafluoro-1- (fluoromethoxy) ethane	37031-31-5	CH2FOCF2CF2H	NA	871*
Difluoro (fluoromethoxy) methane	461-63-2	CH2FOCHF2	NA	617*
Fluoro (fluoromethoxy) methane	462-51-1	CH2FOCH2F	NA	130*
Fluorinated Formates
Trifluoromethyl formate	85358-65-2	HCOOCF3	NA	588*
Perfluoroethyl formate	313064-40-3	HCOOCF2CF3	NA	580*
1,2,2,2-Tetrafluoroethyl formate	481631-19-0	HCOOCHFCF3	NA	470*
Perfluorobutyl formate	197218-56-7	HCOOCF2CF2CF2CF3	NA	392*
Perfluoropropyl formate	271257-42-2	HCOOCF2CF2CF3	NA	376*
1,1,1,3,3,3-Hexafluoropropan-2-yl formate	856766-70-6	HCOOCH(CF3)2	NA	333*
2,2,2-Trifluoroethyl formate	32042-38-9	HCOOCH2CF3	NA	33*
3,3,3-Trifluoropropyl formate	1344118-09-7	HCOOCH2CH2CF3	NA	17*
Fluorinated Acetates
Methyl 2,2,2-trifluoroacetate	431-47-0	CF3COOCH3	NA	52*
1,1-Difluoroethyl 2,2,2-trifluoroacetate	1344118-13-3	CF3COOCF2CH3	NA	31*
Difluoromethyl 2,2,2-trifluoroacetate	2024-86-4	CF3COOCHF2	NA	27*
2,2,2-Trifluoroethyl 2,2,2-trifluoroacetate	407-38-5	CF3COOCH2CF3	NA	7*
Methyl 2,2-difluoroacetate	433-53-4	HCF2COOCH3	NA	3*
Perfluoroethyl acetate	343269-97-6	CH3COOCF2CF3	NA	2.1*
Trifluoromethyl acetate	74123-20-9	CH3COOCF3	NA	2.0*
Perfluoropropyl acetate	1344118-10-0	CH3COOCF2CF2CF3	NA	1.8*
Perfluorobutyl acetate	209597-28-4	CH3COOCF2CF2CF2CF3	NA	1.6*
Ethyl 2,2,2-trifluoroacetate	383-63-1	CF3COOCH2CH3	NA	1.3*
Carbonofluoridates
Methyl carbonofluoridate	1538-06-3	FCOOCH3	NA	95*
1,1-Difluoroethyl carbonofluoridate	1344118-11-1	FCOOCF2CH3	NA	27*
Fluorinated Alcohols other than Fluorotelomer Alcohols
Bis(trifluoromethyl)-methanol	920-66-1	(CF3)2CHOH	195	195
(Octafluorotetramethy-lene) hydroxymethyl group	NA	X-(CF2)4CH(OH)-X	73	73
2,2,3,3,3-pentafluoropropanol	422-05-9	CF3CF2CH2OH	42	42
2,2,3,3,4,4,4-Heptafluorobutan-1-ol	375-01-9	C3F7CH2OH	NA	25*
2,2,2-Trifluoroethanol	75-89-8	CF3CH2OH	NA	20*
2,2,3,4,4,4-Hexafluoro-1-butanol	382-31-0	CF3CHFCF2CH2OH	NA	17*
2,2,3,3-Tetrafluoro-1-propanol	76-37-9	CHF2CF2CH2OH	NA	13*
2,2-Difluoroethanol	359-13-7	CHF2CH2OH	NA	3*
2-Fluoroethanol	371-62-0	CH2FCH2OH	NA	1.1*
4,4,4-Trifluorobutan-1-ol	461-18-7	CF3(CH2)2CH2OH	NA	0.05*
Unsaturated Perfluorocarbons (PFCs)
PFC-1114; TFE (tetrafluoroethylene (TFE); Perfluoroethene)	116-14-3	CF2=CF2; C2F4	0.04	0.004
PFC-1216; Dyneon HFP (hexafluoropropylene (HFP); Perfluoropropene)	116-15-4	C3F6; CF3CF=CF2	0.05	0.05
PFC C-1418 (Perfluorocyclopentene; Octafluorocyclopentene)	559-40-0	c-C5F8	1.97	1.97
Perfluorobut-2-ene	360-89-4	CF3CF=CFCF3	1.82	1.82
Perfluorobut-1-ene	357-26-6	CF3CF2CF=CF2	0.10	0.10
Perfluorobuta-1,3-diene	685-63-2	CF2=CFCF=CF2	0	0.003
Unsaturated Hydrofluorocarbons (HFCs) and Hydrochlorofluorocarbons (HCFCs)
HFC-1132a; VF2 (vinylidiene fluoride)	75-38-7	C2H2F2, CF2=CH2	0.04	0.04
HFC-1141; VF (vinyl fluoride)	75-02-5	C2H3F, CH2=CHF	0.02	0.02
(E)-HFC-1225ye ((E)-1,2,3,3,3- Pentafluoroprop-1-ene)	5595-10-8	CF3CF=CHF(E)	0.06	0.06
(Z)-HFC-1225ye ((Z)-1,2,3,3,3- Pentafluoroprop-1-ene)	5528-43-8	CF3CF=CHF(Z)	0.22	0.22
Solstice 1233zd(E) (trans-1-chloro-3,3,3-trifluoroprop-1-ene)	102687-65-0	C3H2ClF3; CHCl=CHCF3	NA	1.34*
HFC-1234yf; HFO-1234yf (2,3,3,3-Tetrafluoroprop-1-ene)	754-12-1	C3H2F4; CF3CF=CH2	0.31	0.31
HFC-1234ze(E) ((E)-1,3,3,3- Tetrafluoroprop-1-ene)	1645-83-6	C3H2F4; trans-CF3CH=CHF	0.97	0.97
HFC-1234ze(Z) ((Z)-1,3,3,3- Tetrafluoroprop-1-ene)	29118-25-0	C3H2F4; cis-CF3CH=CHF; CF3CH=CHF	0.29	0.29
HFC-1243zf; TFP (trifluoro propene (TFP); 3,3,3-Trifluoroprop-1-ene)	677-21-4	C3H3F3,CF3CH=CH2	0.12	0.12
(Z)-HFC-1336 ((Z)-1,1,1,4,4,4- Hexafluorobut-2-ene)	692-49-9	CF3CH=CHCF3(Z)	1.58	1.58
HFC-1345zfc (3,3,4,4,4-Pentafluorobut-1-ene)	374-27-6	C2F5CH=CH2	0.09	0.09
Capstone 42-U (perfluorobutyl ethene (42-U); 3,3,4,4,5,5,6,6,6- Nonafluorohex-1-ene)	19430-93-4	C6H3F9,CF3(CF2)3CH=CH2	0.16	0.16
Capstone 62-U (perfluorohexyl ethene (62-U); 3,3,4,4,5,5,6,6,7,7,8,8,8-Tridecafluorooct-1-ene)	25291-17-2	C8H3F13,CF3(CF2)5CH=CH2	0.11	0.11
Capstone 82-U (perfluorooctyl ethene (82-U); 3,3,4,4,5,5,6,6,7,7,8,8,9,9,10,10,10-Heptadecafluorodec-1-ene)	21652-58-4	C10H3F17,CF3(CF2)7CH=CH2	0.09	0.09
Unsaturated Halogenated Ethers
PMVE; HFE-216 (perfluoromethyl vinyl ether (PMVE))	1187-93-5	CF3OCF=CF2	NA	0.17*
Fluoroxene ((2,2,2-Trifluoroethoxy) ethene)	406-90-6	CF3CH2OCH=CH2	NA	0.05*
Fluorinated Aldehydes
3,3,3-Trifluoro-propanal	460-40-2	CF3CH2CHO	NA	0.01*
Fluorinated Ketones
Novec 1230 (FK-5-1-12 Perfluoroketone; FK-5-1-12myy2; perfluoro (2-methyl-3-pentanone))	756-13-8	CF3CF2C(O)CF (CF3)2	NA	0.1*
Fluorotelomer Alcohols
3,3,4,4,5,5,6,6,7,7,7-Undecafluoroheptan-1-ol	185689-57-0	CF3(CF2)4CH2CH2OH	NA	0.43*
3,3,3-Trifluoropropan-1-ol	2240-88-2	CF3CH2CH2OH	NA	0.35*
3,3,4,4,5,5,6,6,7,7,8,8,9,9,9-Pentadecafluorononan-1-ol	755-02-2	CF3(CF2)6CH2CH2OH	NA	0.33*
3,3,4,4,5,5,6,6,7,7,8,8,9,9,10,10,11,11,11-Nonadecafluoroundecan-1-ol	87017-97-8	CF3(CF2)8CH2CH2OH	NA	0.19*
Fluorinated GHGs with Carbon-Iodine Bond(s)
Trifluoroiodomethane	2314-97-8	CF3I	NA	0.4*
Other Fluorinated Compounds
Dibromodifluoromethane (Halon 1202)	75-61-6	CBr2F2	NA	231*
2-Bromo-2-chloro-1,1,1-trifluoroethane (Halon-2311/Halothane)	151-67-7	CHBrClCF3	NA	41*
Default GWPs for which Chemical-Specific GWPs are not Listed Above
Saturated PFCs			10,000	10,000
Saturated HFCs with 2 or fewer carbon-hydrogen bonds			3,700	3,700
Saturated HFCs with 3 or more carbon-hydrogen bonds			930	930
Unsaturated PFCs and unsaturated HFCs			1	1

	NA = not available.
	1 = Determining applicability for emissions years 2013 and 2014. For emissions year 2013 (reported in 2014) and emissions year 2014 (reported in 2015), facilities may use the GWPs in either column when calculating GHG emissions for comparison to the reporting threshold under WAC 173-441-030(((1))).
	2 = Calculating annual GHG emissions for emissions year 2013. For emissions year 2013 (reported in 2014), facilities may use the GWPs in either column when calculating GHG emissions for the annual GHG report.
	3 = Determining applicability for emissions year 2015+. For emissions year 2015 (reported in 2016) and subsequent years, facilities must use the GWPs in this column when calculating GHG emissions for comparison to the reporting threshold under WAC 173-441-030(((1))).
	4 = Calculating annual GHG emissions for emissions year 2014+. For emissions year 2014 (reported in 2015) and subsequent years, facilities must use the GWPs in this column when calculating GHG emissions for the annual GHG report.
	* = Requirements to include emissions of this compound when calculating GHG emissions for comparison to the reporting threshold under WAC 173-441-030(((1))) and when calculating GHG emissions for the annual GHG report become effective beginning with emissions year 2016 (reported in 2017).

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 ((facility or supplier))reporter required to report under this chapter and covered under any applicable source category listed in WAC 173-441-120, 173-441-122, or ((173-441-130))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 ((to the United States Environmental Protection Agency under 40 C.F.R. Part 98))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) ((A person not required to report GHG emissions to the United States Environmental Protection Agency under 40 C.F.R. Part 98 must submit the report required under this chapter to ecology no later than October 31st of each calendar year for GHG emissions in the previous calendar year.

(iii))) 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 ((facility or supplier))reporter that began operation before January 1, 2012, report emissions for calendar year 2012 and each subsequent calendar year.

(ii) For a new ((facility or supplier))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 ((facility or supplier))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) ((Facilities))Reporters begin reporting with the first month of the change and ending on December 31st of that year. For a ((facility))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 ((facility or supplier))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 ((both facilities and suppliers))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) ((Facility name or supplier))Reporter name (((as appropriate), facility or supplier)), reporter ID number, and physical street address of the ((facility or supplier))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.

(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 subsections (3)(d)(iii)(A) through (F) of this section.

(A) Biogenic CO2.

(B) CO2 (including biogenic CO2).

(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 subsection (3)(d)(i) of this section 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 ((the following information:

(i) Annual emissions of CO2, expressed in metric tons of CO2, as required in subsections (3)(e)(i)(A) and (B) of this section that would be emitted from the complete combustion or oxidation of the fuels reported to DOL as sold in Washington state during the calendar year.

(A) Aggregate biogenic CO2.

(B) Aggregate CO2 (including nonbiogenic and biogenic CO2).

(ii) All contact information reported to DOL not included in (a) of this subsection.))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).

(D) N2O.

(E) Each fluorinated GHG.

(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 ((facility or supplier))reporter. NAICS codes are subject to approval by ecology.

(i) Primary NAICS code. Report the NAICS code that most accurately describes the ((facility or supplier's))reporter's primary product/activity/service. The primary product/activity/service is the principal source of revenue for the ((facility or supplier))reporter. A ((facility or supplier))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 ((facility or supplier))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 ((facility or supplier))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((:)). Also describe any direct or indirect affiliation with other reporters.

(i) If the ((facility or supplier))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 one hundred percent ownership.

(ii) If the ((facility or supplier))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 one hundred percent ownership.

(iii) If the ((facility or supplier))reporter is owned by more than one United States company (e.g., company A owns forty percent, company B owns thirty-five percent, and company C owns twenty-five 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 ((facility or supplier))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 one hundred percent ownership by the joint venture or cooperative.

(v) If the ((facility or supplier))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 one hundred percent ownership.

(vi) If the ((facility or supplier))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 ((facility or supplier))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, report 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. Self-generated electricity should be itemized separately.

(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. 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".

Table 050-1: Total Annual Facility Product Data Requirements by Primary NAICS Code.

Primary NAICS Code and Sector Definition	Activity	Production Metric
112112: Cattle Feedlots	Cattle feedlots	Cattle head days
211130: Natural Gas Extraction	Natural gas extraction	Million standard cubic feet of natural gas extracted
212399: All Other Nonmetallic Mineral Mining	Freshwater diatomite filter aids manufacturing	Metric tons of mineral product produced
2211XX: Electric Power Generation, Transmission and Distribution	Electric power generation, transmission and distribution	Net megawatt hours
221210: Natural Gas Distribution	Natural gas distribution	Million standard cubic feet of natural gas distributed
221330: Steam and Air-conditioning Supply	Steam supply	Kilograms steam produced
311213: Malt Manufacturing	Malt manufacturing	Metric tons of malt produced
3114XX: Fruit and Vegetable Preserving and Specialty Food Manufacturing	Fruit and vegetable preserving and specialty food manufacturing	Metric tons of food product produced
3115XX: Dairy Product Manufacturing	Dairy product manufacturing	Metric tons of dairy product produced
311611: Animal (except poultry) Slaughtering	Animal (except poultry) slaughtering	Metric tons of meat product processed
311613: Rendering and Meat By-product Processing	Rendering and meat by-product processing	Metric tons of meat by-product processed
311919: Other Snack Food Manufacturing	Other snack food manufacturing	Metric tons of snack food produced
311920: Coffee and Tea Manufacturing	Coffee and tea manufacturing	Metric tons of coffee and tea produced
321XXX: Wood Product Manufacturing	Wood product manufacturing	Air dried metric tons of wood product produced
3221XX: Pulp, Paper, and Paperboard Mills	Pulp, paper, and paperboard mills	Air dried metric tons of pulp produced
322299: All Other Converted Paper Product Manufacturing	All other converted paper product manufacturing	Metric tons of converted paper product produced
324110: Petroleum Refineries	Petroleum refineries	Complexity weighted barrel as described in CARB MRR section 95113 (l)(3) as adopted by 7/1/2021. Supporting data must also be submitted to Ecology as described in CARB MRR section 95113 (l)(3).
324121: Asphalt Paving Mixture and Block Manufacturing	Asphalt paving mixture and block manufacturing	Metric tons of asphalt paving mixture and block produced
3251XX: Basic Chemical Manufacturing	Basic chemical manufacturing	Metric tons of chemical produced
325311: Nitrogenous Fertilizer Manufacturing	Nitric acid production	Metric tons of nitric acid produced
32721X: Glass and Glass Product Manufacturing	Glass and glass product manufacturing	Metric tons of glass produced
327310: Cement Manufacturing	Cement manufacturing	Metric tons of adjusted clinker and mineral additives produced
327390: Other Concrete Product Manufacturing	Other concrete product manufacturing	Metric tons of concrete product produced
327410: Lime Manufacturing	Lime manufacturing	Metric tons of lime produced
327420: Gypsum Product Manufacturing	Gypsum product manufacturing	Metric tons of gypsum product produced
331110: Iron and Steel Mills and Ferroalloy Manufacturing	Steel production using an electric arc furnace (EAF)	Metric tons of steel produced
33131X: Alumina and Aluminum Production and Processing	Alumina and aluminum production and processing	Metric tons of aluminum produced
331410: Nonferrous Metal (except aluminum) Smelting and Refining	Granular polysilicon production	Metric tons of granular polysilicon produced
332111: Iron and Steel Forging	Iron forging	Metric tons of iron produced
334413: Semiconductor and Related Device Manufacturing	Semiconductor and related device manufacturing	Square meters of wafer produced
335991: Carbon and Graphite Product Manufacturing	Carbon and graphite product manufacturing	Metric tons of carbon and graphite product produced
3364XX: Aerospace Product and Parts Manufacturing	Aerospace product and parts manufacturing	Metric tons of aircraft product and parts produced
486210: Pipeline Transportation of Natural Gas	Pipeline transportation of natural gas	Million standard cubic feet of natural gas transported
488119: Other Airport Operations	Other airport operations	Passenger kilometers serviced
562111: Solid Waste Collection	Solid waste collection	Metric tons of total solid waste collected
562212: Solid Waste Landfill	Solid waste landfill	Metric tons of total waste entered into landfill
562213: Solid Waste Combustors and Incinerators	Solid waste combustors and incinerators	Net megawatt hours
611310: Colleges, Universities, and Professional Schools	Colleges, universities, and professional schools	Students serviced
928110: National Security	Military bases	Troops stationed

(ii) Facilities without a primary NAICS code listed in Table 050-1 of this section must contact ecology no later than forty-five 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:

Product data

Sconsumed + Fconsumed - esold

(Eq. 050-1)

Where:
	"SConsumed" is the annual amount of steam consumed, measured in MMBtu, at the facility for any process, including heating or cooling applications. This value shall exclude any steam used to produce electricity. This value shall exclude steam produced from an on-site cogeneration unit;
	"FConsumed" is the annual amount of energy produced due to fuel combustion at the facility, measured in MMBtu. This value shall be calculated based on measured higher heating values or the default higher heating value of the applicable fuel in Table C-1 of 40 C.F.R. Part 98. This value shall include any energy from fuel combusted in an on-site electricity generation or cogeneration unit. This value shall exclude energy to generate the steam accounted for in the "SConsumed" term;
	"eSold" is the annual amount of electricity sold or provided for off-site use, measured in MWh and converted to MMBtu using the reporting year U.S. Energy Information Administration conversion factor;

(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 forty-five 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.

(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 ((unless you)), 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 ((three))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 ((must be made available to ecology))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.

(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(((1))) 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. 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 ((173-441-130(5)))173-441-122 and 173-441-124.

(7) Annual GHG report revisions.

(a) A person must submit a revised annual GHG report within forty-five 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 forty-five 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 forty-five 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 forty-five day period, by email ((to ghgreporting@ecy.wa.gov)), at least ((two))five business days prior to the expiration of the forty-five 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 ((thirty))15 more calendar days. During the automatic ((thirty-day))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 three 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. ((Suppliers subject to the requirements of this chapter must meet the calibration accuracy requirements in chapters 308-72, 308-77, and 308-78 WAC.))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 ((facilities and suppliers))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.

Where:
	CE	=	Calibration error	(%)
	R	=	Reference value
	A	=	Flow meter response to 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.

Where:
	CE	=	Calibration error	(%)
	R	=	Reference value
	A	=	Transmitter response to the reference value
	FS	=	Full-scale value of the transmitter

(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((s)) (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 unless specified in (h) of this subsection.

(h) Missing data substitution procedures. Persons must comply with 40 C.F.R. Part 98 when substituting for missing data, except as otherwise provided in this subsection.

(i) Substitute missing data used for emissions calculations under Subparts C, H, P, Y, and AA of 40 C.F.R. Part 98 using the following methods:

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

(B) If the analytical data capture rate is at least 80 percent but not at least 90 percent for the data year, the person 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.

(C) If the analytical data capture rate is less than 80 percent for the data year, the person must substitute for each missing value with the highest quality assured value recorded for the parameter in all records kept.

(ii) Substitute missing data used for product data required under subsection (3)(n) of this section 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) ((as adopted by September 1, 2016,)) are adopted by reference as modified in WAC 173-441-120(2).

(1) General. Except as provided under subsection (6) of this section, each ((facility, and each supplier,))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 ((facility and supplier))reporter respectively to ecology under this chapter. If the ((facility))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 ((facility or supplier))reporter must be an individual selected by an agreement binding on the owners and operators of such ((facility or supplier))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 ((facility or supplier))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 ((facility or supplier))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 ((facility or supplier))reporter will be accepted until ecology has received a complete certificate of representation under this section for a designated representative of the ((facility or supplier))reporter. Such certificate of representation must be submitted at least sixty calendar days before the deadline for submission of the ((facility's or supplier's))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 ((facility or supplier))reporter must be certified, signed, and submitted by the designated representative or any alternate designated representative of the ((facility or supplier))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 ((facility or supplier))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 ((facility or supplier))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 ((facility or supplier))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 ((facility or supplier))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 ((facility or supplier))reporter identifying an alternate designated representative:

(i) The alternate designated representative may act on behalf of the designated representative for such ((facility or supplier))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 ((facility or supplier))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 ((facility or supplier))reporter. Notwithstanding any such change, all representations, actions, inactions, and submissions by the previous designated representative or the previous alternate designated representative of the ((facility or supplier))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 ((facility or supplier))reporter.

(8) Changes in owners and operators. In the event an owner or operator of the ((facility or supplier))reporter is not included in the list of owners and operators in the certificate of representation under this section for the ((facility or supplier))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 ((facility or supplier))reporter, as if the owner or operator were included in such list. Within ninety calendar days after any change in the owners and operators of the ((facility or supplier))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 ((facility or supplier))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 ninety 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 ((facility or supplier))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 ((facility or supplier))reporter identified in (a) of this subsection, provided that, if the list includes the operators of the ((facility or supplier))reporter and the owners with control of the ((facility or supplier))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 ((or binding on the)), 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 ((and on behalf of)), supplier((s)), 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 ((supplier or)) 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 ((facility or supplier))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 ((facility or supplier))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 ((facility or supplier))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 ((facility or supplier))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 ((facility or supplier))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 owner or operator of a facility that exceeds the compliance threshold under WAC 173-442-030 or voluntarily participating under WAC 173-442-030(6)))Beginning with the 2023 emissions year, 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 316, Laws of 2021, as described in chapter 173-446 WAC must have the ((facility's))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 ((facility has a GHG emission reduction pathway under WAC 173-442-060))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 ((facility is voluntarily participating under WAC 173-442-030(6)))reporter has a mandatory or voluntary compliance obligation under chapter 316, Laws of 2021, as described in chapter 173-446 WAC;

(c) Is part of a baseline calculation ((for a new entrant after 2020 under WAC 173-442-050 (1)(b)))or otherwise covered under chapter 316, Laws of 2021, 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 ((facility))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) ((Emissions))Information subject to third-party verification. All ((covered)) GHG emissions and other information reported under this chapter ((173-442 WAC)) 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 ((covered)) 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 ((covered)) product data in the annual GHG report.

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

(ii) "Omissions" means any ((covered)) emissions or ((covered)) 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 ((covered)) 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 ((covered)) emissions or ((covered)) product data" means the total annual ((reporting entity covered))reporter's emissions or total ((reported covered))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 ((facility))reporter subject to third-party verification under subsection (1)(b) through (d) of this section must be full verification. ((An owner or operator))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 ((facility))reporter; and

(v) There has not been a significant change in sources or emissions. A difference in emissions of greater than twenty-five 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 ((facility))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;

(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 ((facility))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 ((facility))reporter is a supplier ((of petroleum products or supplier of natural gas and natural gas liquids))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 ((facility))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 ((covered)) emissions((, noncovered emissions,)) or ((covered)) 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 ((covered)) emissions((, noncovered emissions,)) or ((covered)) 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 ten years.

(6) ((Timing.))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 ((one hundred fifty days after the report submission due date for the facility, specified in WAC 173-441-050(2)))August 10th for GHG emissions occurring in the previous calendar year.

((Any corrections to the annual GHG report or verification report must be submitted to ecology no later than forty-five days after discovery of the error.))(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.

(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 ((at least one of the following GHG programs:

(A))) California ARB's Mandatory Reporting of Greenhouse Gas Emissions program((;

(B) The Climate Registry;

(D) American National Standards Institute (ANSI);

(E) Accredited ISO 14064 registrars; or

(F) Other GHG verification standard approved by ecology)).

(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 ((facility))reporter share any management staff or board of directors membership, or any of the senior management staff of the ((facility))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 ((facility))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 ((facility))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

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 ((chapter))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 ((173-441-050(3)))173-441-010 through ((173-441-080))173-441-110 and 173-441-140 through 173-441-170 and any applicable provision of this section, the requirements of ((this))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.

Table 120-1:

Source Categories and Calculation Methods

Incorporated by Reference from 40 C.F.R. Part 98 for Facilities

((Note:

All source categories in Table 120-1 are considered facilities even if the source category name includes the word "supplier."))

Source Category	40 C.F.R. Part 98 Subpart*	Exceptions to Calculation Method or Applicability Criteria+#
General Stationary Fuel Combustion Sources	C
Electricity Generation	D
Adipic Acid Production	E
Aluminum Production	F
Ammonia Manufacturing	G
Cement Production	H
Electronics Manufacturing	I	In § 98.91, replace "To calculate total annual GHG emissions for comparison to the 25,000 metric ton CO2e per year emission threshold in paragraph § 98.2 (a)(2), follow the requirements of § 98.2(b), with one exception" with "To calculate GHG emissions for comparison to the emission threshold in WAC 173-441-030(1), follow the requirements of WAC 173-441-030 (1)(b), with one exception."
Ferroalloy Production	K
Fluorinated Gas Production	L	In § 98.121, replace "To calculate GHG emissions for comparison to the 25,000 metric ton CO2e per year emission threshold in § 98.2 (a)(2)" with "To calculate GHG emissions for comparison to the emission threshold in WAC 173-441-030(1)."
Glass Production	N
HCFC-22 Production and HFC-23 Destruction	O
Hydrogen Production	P
Iron and Steel Production	Q
Lead Production	R
Lime Manufacturing	S
Magnesium Production	T
Miscellaneous Uses of Carbonate	U
Nitric Acid Production	V
Petroleum and Natural Gas Systems	W	§ 98.231(a) should read: "You must report GHG emissions under this subpart if your facility contains petroleum and natural gas systems and the facility meets the requirements of WAC 173-441-030(1)."
Petrochemical Production	X
Petroleum Refineries	Y
Phosphoric Acid Production	Z
Pulp and Paper Manufacturing	AA
Silicon Carbide Production	BB
Soda Ash Manufacturing	CC
Electrical Transmission and Distribution Equipment Use	DD	§ 98.301 should read: "You must report GHG emissions under this subpart if your facility contains any electrical transmission and distribution equipment use process and the facility meets the requirements of WAC 173-441-030(1)." See subsection (2)(f) of this section.
Titanium Dioxide Production	EE
Underground Coal Mines	FF
Zinc Production	GG
Municipal Solid Waste Landfills	HH	CO2 from combustion of landfill gas must also be included in calculating emissions for reporting and determining if the reporting threshold is met. § 98.346 (i)(13) should read: "Methane emissions for the landfill (i.e., the subpart HH total methane emissions). If the quantity of recovered CH4 from Equation HH-4 of this subpart is used as the value of GCH4 in Equation HH-6, use the methane emissions calculated using Equation HH-8 as the methane emissions for the landfill." Otherwise use the higher methane emissions value from Equation HH-6 or Equation HH-8 of this subpart unless otherwise instructed by ecology.
Industrial Wastewater Treatment	II	CO2 from combustion of wastewater biogas must also be included in calculating emissions for reporting and determining if the reporting threshold is met.
((Manure Management	JJ	See subsection (2)(e) of this section.
Suppliers of Coal-Based Liquid Fuels	LL	§ 98.380(b) should read: "An importer or exporter shall have the same meaning given in WAC 173-441-120 (2)(h)." § 98.381 should include: "Reporting of exports is voluntary."
Suppliers of Petroleum Products	MM	§ 98.391 should read: "Any refiner or importer that meets the requirements of WAC 173-441-030(1) must report GHG emissions. Any exporter of petroleum products and natural gas liquids may report GHG emissions associated with exported petroleum products using the methods established in this subpart." See subsection (2)(h) of this section.
Suppliers of Natural Gas and Natural Gas Liquids	NN	§ 98.401 should read: "Any supplier of natural gas and natural gas liquids that meets the requirements of WAC 173-441-030(1) must report GHG emissions."
Suppliers of Industrial Greenhouse Gases	OO	§ 98.411 should include: "Reporting of exports is voluntary."
Suppliers of Carbon Dioxide	PP	§ 98.421 should read: "Any supplier of CO2 who meets the requirements of WAC 173-441-030(1) must report the mass of CO2 captured, extracted, or imported. The mass of CO2 exported may be reported using the methods established in this subpart."
Importers and Exporters of Fluorinated Greenhouse Gases Contained in Pre-Charged Equipment or Closed-Cell Foams	QQ	§ 98.431 should read: "Any importer of fluorinated GHGs contained in pre-charged equipment or closed-cell foams who meets the requirements of WAC 173-441-030(1) must report each fluorinated GHG contained in the imported pre-charged equipment or closed-cell foams. Any exporter of fluorinated GHGs contained in pre-charged equipment or closed-cell foams may report GHG emissions associated with exported products using the methods established in this subpart."))
Geologic Sequestration of Carbon Dioxide	RR	§ 98.441(a) should read: "You must report GHG emissions under this subpart if any well or group of wells within your facility injects any amount of CO2 for long-term containment in subsurface geologic formations and the facility meets the requirements of WAC 173-441-030(1)."
Electrical Equipment Manufacture or Refurbishment	SS	§ 98.451 should read: "You must report GHG emissions under this subpart if your facility contains an electrical equipment manufacturing or refurbishing process and the facility meets the requirements of WAC 173-441-030(1)."
Industrial Waste Landfills	TT	CO2 from combustion of landfill gas must also be included in calculating emissions for reporting and determining if the reporting threshold is met.
Injection of Carbon Dioxide	UU	§ 98.471 should read: "(a) You must report GHG emissions under this subpart if your facility contains an injection of carbon dioxide process and the facility meets the requirements of WAC 173-441-030(1). For purposes of this subpart, any reference to CO2 emissions in WAC 173-441-030 means CO2 received."

*	Unless otherwise noted, all calculation methods are from 40 C.F.R. Part 98((, as adopted by September 1, 2016)).
+	Modifications and exceptions in subsection (2) of this section and WAC 173-441-010 through ((173-441-050(2)))173-441-110 and 173-441-140 through 173-441-170 also apply.
#	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.

(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) ((For manure management, use the following subsections instead of the corresponding subsections in 40 C.F.R. § 98.360 as adopted by September 1, 2016.

(i) 40 C.F.R. § 98.360(a): This source category consists of livestock facilities with manure management systems.

(A) § 98.360 (a)(1) is not adopted by reference.

(B) § 98.360 (a)(2) is not adopted by reference.

(ii) 40 C.F.R. § 98.360(b): A manure management system (MMS) is a system that stabilizes and/or stores livestock manure, litter, or manure wastewater in one or more of the following system components: Uncovered anaerobic lagoons, liquid/slurry systems with and without crust covers (including, but not limited to, ponds and tanks), storage pits, digesters, solid manure storage, dry lots (including feedlots), high-rise houses for poultry production (poultry without litter), poultry production with litter, deep bedding systems for cattle and swine, manure composting, and aerobic treatment.

(iii) 40 C.F.R. § 98.360(c): This source category does not include system components at a livestock facility that are unrelated to the stabilization and/or storage of manure such as daily spread or pasture/range/paddock systems or land application activities or any method of manure utilization that is not listed in § 98.360(b) as modified in WAC 173-441-120 (2)(e)(ii).

(iv) 40 C.F.R. § 98.360(d): This source category does not include manure management activities located off-site from a livestock facility or off-site manure composting operations.

(v) 40 C.F.R. § 98.361: Livestock facilities must report GHG emissions under this subpart if the facility contains a manure management system as defined in 98.360(b) as modified in WAC 173-441-120 (2)(e)(ii), and meets the requirements of WAC 173-441-030(1).

(vi) 40 C.F.R. § 98.362 (b) and (c) are not adopted by reference.

(vii) 40 C.F.R. § 98.362(a), 40 C.F.R. § 98.363 through 40 C.F.R. § 98.368, Equations JJ-2 through JJ-15, and Tables JJ-2 through JJ-7 as adopted by September 1, 2016, remain unchanged unless otherwise modified in this chapter.

(viii) CO2 from combustion of gas from manure management must also be included in calculating emissions for reporting and determining if the reporting threshold is met.))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.

(((g) 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.

(h) For suppliers of petroleum products or coal-based liquid fuels, use the following subsections instead of the corresponding subsections in 40 C.F.R. § 98.390 as adopted by September 1, 2016.

(i) 40 C.F.R. § 98.390: Definition of the source category.

This source category consists of petroleum refineries and importers and exporters of petroleum products and natural gas liquids as listed in Table MM-1 of this subpart.

(A) A petroleum refinery for the purpose of this subpart is any facility engaged in producing petroleum products through the distillation of crude oil.

(B) A refiner is the owner or operator of a petroleum refinery.

(C) Importer has the same meaning given in subsection (2)(h)(ii) of this section and includes any entity that imports petroleum products, natural gas liquids, or coal-based liquid fuels as listed in Table MM-1 of this subpart. Any blender or refiner of refined or semi-refined petroleum products shall be considered an importer if it otherwise satisfies the aforementioned definition.

(D) Exporter has the same meaning given in subsection (2)(h)(ii) of this section and includes any entity that exports petroleum products, natural gas liquids, or coal-based liquid fuels as listed in Table MM-1 of this subpart. Any blender or refiner of refined or semi-refined petroleum products shall be considered an exporter if it otherwise satisfies the aforementioned definition.

(ii) Definitions specific to imports and exports:

(A) Export means to transport a product from inside Washington state to persons outside Washington state, excluding any such transport on behalf of the United States military including foreign military sales under the Arms Export Control Act. The final destination of the product must occur outside of Washington state.

(B) Exporter means any person, company or organization of record that transfers for sale or for other benefit, products from Washington state to another state, country, or to an affiliate in another country, excluding any such transfers on behalf of the United States military or military purposes including foreign military sales under the Arms Export Control Act. The final destination of the product must occur outside of Washington state. An exporter is not the entity merely transporting the domestic products, rather an exporter is the entity deriving the principal benefit from the transaction.

(D) Importer means any person, company, or organization of record that for any reason brings a product into Washington state from a different state or foreign country, excluding introduction into Washington state jurisdiction exclusively for United States military purposes. The term includes, as appropriate:

(I) The consignee.

(II) The importer of record.

(III) The actual owner.

(IV) The transferee, if the right to draw merchandise in a bonded warehouse has been transferred.

(iii) Each importer shall report all information at the state level.

(iv) Each exporter choosing to report emissions associated with exported products to ecology under these subparts shall report all information at the state level:

(v) Exporters choosing to report emissions associated with exported products to ecology under these subparts and refineries and importers must report information for each product where emissions were calculated.))

Table 120-2:

Corresponding References in 40 C.F.R. Part 98 and

Chapter 173-441 WAC

Reference in 40 C.F.R. Part 98		Corresponding Reference in Chapter 173-441 WAC
Section	Topic	Section	Topic
40 C.F.R. Part 98 or "part"	Mandatory Greenhouse Gas Reporting	Chapter 173-441 WAC	Reporting of Emissions of Greenhouse Gases
Subpart A	General Provision	WAC 173-441-010 through 173-441-100	General Provisions
§ 98.1	Purpose and scope	WAC 173-441-010	Scope
§ 98.2	Who must report?	WAC 173-441-030	Applicability
§ 98.2(a)	Applicability: Facility reporting	WAC 173-441-030(1)	Applicability: Facility reporting
§ 98.2 (a)(1)	Applicability: Facility reporting Table A-3	WAC 173-441-030(1)	Applicability: Facility reporting
§ 98.2 (a)(2)	Applicability: Facility reporting Table A-4	WAC 173-441-030(1)	Applicability: Facility reporting
§ 98.2 (a)(3)	Applicability: Facility reporting source categories that meet all three of the conditions listed in this paragraph (a)(3)	WAC 173-441-030(1)	Applicability: Facility reporting
§ 98.2 (a)(4)	Applicability: Facility reporting Table A-5 source categories	WAC 173-441-030(1)	Applicability: Facility reporting
§ 98.2(b)	Calculating emissions for comparison to the threshold	WAC 173-441-030 (1)(b)	Calculating facility emissions for comparison to the threshold
§ 98.2(i)	Reporting requirements when emissions of greenhouse gases fall below reporting thresholds	WAC 173-441-030(5)	Reporting requirements when emissions of greenhouse gases fall below reporting thresholds
§ 98.3	What are the general monitoring, reporting, recordkeeping and verification requirements of this part?	WAC 173-441-050	General monitoring, reporting, recordkeeping and verification requirements
§ 98.3(c)	Content of the annual report	WAC 173-441-050(3)	Content of the annual report
§ 98.3(g)	Recordkeeping	WAC 173-441-050(6)	Recordkeeping
§ 98.3 (g)(5)	A written GHG monitoring plan	WAC 173-441-050 (6)(e)	A written GHG monitoring plan
§ 98.3(i)	Calibration accuracy requirements	WAC 173-441-050(8)	Calibration and accuracy requirements
§ 98.3 (i)(6)	Calibration accuracy requirements: Initial calibration	WAC 173-441-050 (8)(f)	Calibration accuracy requirements: Initial calibration
§ 98.4	Authorization and responsibilities of the designated representative	WAC 173-441-060	Authorization and responsibilities of the designated representative
§ 98.5	How is the report submitted?	WAC 173-441-070	Report submittal
§ 98.5(b)	Verification software	WAC 173-441-070(1)	Facility report submittal
§ 98.6	Definitions	WAC 173-441-020	Definitions
§ 98.7	What standardized methods are incorporated by reference into this part?	WAC 173-441-080	Standardized methods and conversion factors incorporated by reference
§ 98.8	What are the compliance and enforcement provisions of this part?	WAC 173-441-090	Compliance and enforcement
§ 98.9	Addresses	WAC 173-441-100	Addresses
Table A-1 to Subpart A of Part 98—Global Warming Potentials, Table A-1 of this part, or Table A-1 of this subpart	Global Warming Potentials	Table A-1 of WAC 173-441-040	Global Warming Potentials
Table A-2 to Subpart A of Part 98—Units of Measure Conversions	Units of Measure Conversions	Table A-2 of WAC 173-441-080	Units of Measure Conversions

(3) Calculation methods for voluntary reporting. GHG emissions reported voluntarily under WAC 173-441-030(((4)))(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 ((173-441-130))173-441-122 or 173-441-124, use the methods specified in WAC ((173-441-130))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 ((173-441-130))173-441-122 or 173-441-124, contact ecology for an appropriate calculation method no later than one hundred eighty 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 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 the following regardless of the amount of GHG emissions. The following emissions do not count towards the reporting threshold in WAC 173-441-030(1).

(a) Owners and operators of facilities that supply CO2 as described in WAC 173-441-122 (3)(b) must include those emissions as part of their facility report as described in that section.

(b) Owners and operators of petroleum refineries and biofuel production facilities as described in WAC 173-441-122 (5)(d)(x) must include those emissions as part of their facility report as described in that section.

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.

(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. For purposes of this chapter, 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, 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, natural gas liquids, liquefied petroleum gas, compressed natural gas, and liquefied natural gas. Any supplier of natural gas or natural gas liquids 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:

MMBtuTotal

MMBturedelivery - MMBtureceipts

(Eq. 122-1)

Where:
	MMBtuTotal	=	Total annual MMBtu used in Equation NN-3
	MMBturedelivery	=	Total annual MMBtu of natural gas delivered to other companies as specified above
	MMBtureceipts	=	Total annual MMBtu of natural gas received from other companies as specified above

(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 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:

CO2

∑CO2i - ∑CO2j - ∑CO2l + ∑CO2n - ∑CO2k

(Eq. 122-2)

Where:
	CO2	=	Total emissions.
	CO2i	=	Emissions from natural gas received at the state border or city gate, calculated pursuant to subsection (4)(b)(ii) of this section.
	CO2j	=	Emissions from natural gas received for redistribution to or received from other natural gas transmission companies, calculated pursuant to subsection (4)(b)(iii) of this section.
	CO2l	=	Emissions from storage and direct deliveries from producers calculated pursuant to subsection (4)(b)(iv) of this section.
	CO2k	=	Emissions from natural gas delivered to each large end user as calculated pursuant to subsection (4)(b)(vi) of this section.
	CO2n	=	Emissions from natural gas received by the LDC directly from sources bypassing the city gate, and is not otherwise accounted for, as calculated pursuant to subsection (4)(b)(v) of this section.

(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;

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) Suppliers of petroleum products, biomass-derived fuels, and coal-based liquid fuels. 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.

Table 122-1. Fuel Product CH4 and N2O Emission Factors

Fuel	CH4 (g/bbl)	N2O (g/bbl)
Blendstocks or finished gasoline	20	20
Distillate and diesel-other	2	1
Ethanol	37	27
Biodiesel and renewable diesel	2	1
Oxygenates	13	3
Residuum	18	4
Waxes	17	3
Still gas	19	4
Miscellaneous products	17	3

(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 source categories listed in (a) of this subsection using the methods in this section.

(a) Electric power entity source categories:

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

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

(iii) Bonneville Power Administration (BPA).

(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) "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 energy imbalance market purchaser;

(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 (a)(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 the program, 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 (a)(vi) of this subsection has not voluntarily elected to comply with the program, then the electricity importer is the public body or cooperative customer or direct service industrial customer; or

(viii) 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.

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

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

(ii) Multijurisdictional retail providers;

(iii) Multijurisdictional consumer-owned utilities.

(d) "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.

(e) "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.

(f) "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.

(g) "Multijurisdictional retail provider" means a:

(i) Multijurisdictional electric company; or

(ii) Multijurisdictional consumer-owned utility.

(h) "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.

(i) "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.

(j) "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.

(k) "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.

(i) "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.

(ii) "Electricity generation provider" means a provider of the energy or generation component of electricity services, as distinguished from the provider of transmission and/or distribution service that provides the wires for the transport of electricity. Electricity generation providers may include cogeneration facilities and other entities in addition to electrical distribution utilities that may provide both generation and transmission/distribution service.

(iii) "Energy imbalance market purchaser" or "EIM purchaser" means, for a given data year an electrical distribution utility or EPE that directly or indirectly purchases any electricity through the EIM to serve Washington state load in the data year.

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

(v) "Electricity wheeled through Washington" or "wheeled electricity" means electricity that is generated outside Washington state and delivered into Washington state with the final point of delivery outside Washington state. Electricity wheeled through Washington state is documented on a single e-tag showing the first point of receipt located outside Washington state, an intermediate point of delivery located inside Washington state, and the final point of delivery located outside Washington state.

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

(vii) "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.

(viii) "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.

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

(x) "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. Imported electricity and wheeled electricity are disaggregated by the first point of receipt on the e-tag.

(xi) "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.

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

(xiii) "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.

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

(xv) "Particular end user" means a final purchaser of an energy product (e.g., electricity or thermal energy) for whom the energy product is delivered for final consumption and not for the purposes of retransmission or resale.

(xvi) "Point of receipt" or "POR" means the point on an electricity transmission or distribution system where an electricity receiver receives electricity from a first jurisdictional 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.

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

(xviii) "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.

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

(xx) "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.

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

(xxii) "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.

(xxiii) "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.

(xxiv) "Substitute power" or "substitute electricity" means electricity that is provided to meet the terms of a power purchase contract with a specified facility or unit when that facility or unit is not generating electricity.

(xxv) "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, exported, and wheeled 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, including the energy imbalance market, and from each specified source. Substitute electricity must be separately reported for each specified source, as applicable. 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 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) Imported 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. A GPE must report imported electricity as from a specified source when the importer 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 316, Laws of 2021, 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) Tagging ACS power. To claim power from an asset-controlling supplier, the asset-controlling supplier must be identified 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.

(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.

(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) Electricity wheeled through Washington state. The electric power entity who is the PSE on the last physical path segment that crosses the border of Washington state on the e-tag must separately report electricity wheeled through Washington state, aggregated by first point of receipt, and must exclude wheeled power transactions from reported imports and exports. When reporting electricity wheeled through Washington state, the electric power entity must include the quantities of electricity wheeled through Washington state as measured at the first point of delivery inside Washington state. Only an electric power entity must report wheeled electricity through Washington state.

(x) 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.

(xi) 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.

(xii) 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:

CO2e

MWh × TL × EFsp

(Eq. 124-1)

Where:
	CO2e	=	Annual CO2 equivalent mass emissions from the specified electricity deliveries from each facility or unit claimed (MT of CO2e).
	MWh	=	Megawatt-hours of specified electricity deliveries from each facility or unit claimed.
	EFsp	=	Facility-specific or unit-specific emission factor published on the ecology website and calculated using total emissions and transactions data as described below. The emission factor is based on data from the year prior to the reporting year.
	TL	=	Transmission loss correction factor.
	TL	=	1.02 to account for transmission losses associated with generation outside of a Washington state balancing authority.
	TL	=	1.0 if the reporting entity provides documentation that demonstrates to the satisfaction of a verifier and ecology that transmission losses have been accounted for, or are compensated by using electricity sourced from within Washington state.

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

EFsp

Esp/EG

(Eq. 124-2)

Where:
	Esp	=	CO2e emissions for a specified facility or unit for the report year (MT of CO2e).
	EG	=	Net generation from a specified facility or unit for the report year shall be based on data reported to the Energy Information Administration (EIA).

(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.

Esp

0.001 × Σ(Q x EF)

(Eq. 124-3)

Where:
	0.001	=	Conversion factor kg to MT
	Q	=	Heat of combustion for each specified fuel type from the specified facility or unit for the report year (MMBtu). For cogeneration, Q is the quantity of fuel allocated to electricity generation consistent with EIA reporting. For geothermal electricity, Q is the steam data reported to EIA (MMBtu).
	EF	=	CO2e emission factor for the specified fuel type as required by this chapter (kg CO2e/MMBtu). For geothermal electricity, EF is the estimated CO2 emission factor published by EIA.

(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.

A lesser of analysis is applicable to imports from specified sources, including imported electricity under EIM, 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:

Sum of Lesser of MWh

ΣHMsp min (MGsp*Ssp, TGsp)

(Eq. 124-4)

Where:
	ΣHMsp	=	Sum of the Hourly Minimum of MGsp and TGsp (MWh).
	MGsp	=	Metered facility or unit net generation (MWh).
	Ssp	=	Entity's share of metered output, if applicable.
	TGsp	=	Tagged or transmitted energy at the transmission or subtransmission level imported to Washington (MWh).

(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:

CO2e

MWh × TL × EFacs

(Eq. 124-5)

Where:
	CO2	=	Annual CO2 equivalent mass emissions from the specified electricity deliveries from ecology-recognized asset-controlling suppliers (MT of CO2e).
	MWh	=	Megawatt-hours of specified electricity deliveries.
	EFACS	=	Asset-Controlling Supplier system emission factor published on the ecology website (MT CO2e/MWh). Ecology will assign the system emission factors for all asset-controlling suppliers based on a previously verified GHG report submitted to ecology pursuant to WAC 173-441-070(3). The supplier-specific system emission factor is calculated annually by ecology. The calculation is derived from data contained in annual reports submitted that have received a positive or qualified positive verification statement. The emission factor is based on data from two years prior to the reporting year.
	TL	=	Transmission loss correction factor.
	TL	=	1.02 when deliveries are not reported as measured at a first point of receipt located within the balancing authority area of the asset-controlling supplier.
	TL	=	1.0 when deliveries are reported as measured at a first point of receipt located within the balancing authority area of the asset-controlling supplier.

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

EFACS

Sum of System Emissions MT of CO2e/Sum of System MWh

(Eq. 124-6)

Sum of System Emissions,

MT of CO2e

ΣEasp + Σ(PEsp * EFsp) + Σ(PEunsp * EFunsp) - Σ(SEsp * EFsp)

(Eq. 124-7)

Sum of System MWh

ΣEGasp + ΣPEsp + ΣPEunsp - ΣSEsp

(Eq. 124-8)

Where:
	ΣEasp	=	Emissions from owned facilities. Sum of CO2e emissions from each specified facility/unit in the asset-controlling supplier's fleet (MT of CO2e).
	ΣEGasp	=	Net generation from owned facilities. Sum of net generation for each specified facility/unit in the asset-controlling supplier's fleet for the data year as reported to ecology under this chapter (MWh).
	PEsp	=	Electricity purchased from specified sources. Amount of electricity purchased wholesale and taken from specified sources by the asset-controlling supplier for the data year as reported to ecology under this chapter (MWh).
	PEunsp	=	Electricity purchased from unspecified sources. Amount of electricity purchased wholesale from unspecified sources by the asset-controlling supplier for the data year as reported to ecology under this chapter (MWh).
	SEsp	=	Electricity sold from specified sources. Amount of wholesale electricity sold from specified sources by the asset-controlling supplier for the data year as reported to ecology under this chapter (MWh).
	EFsp	=	CO2e emission factor as defined for each specified facility or unit calculated consistent with (b)(ii) of this subsection (MT CO2e/MWh).
	EFunsp	=	Default emission factor for unspecified sources calculated consistent with (b)(i) of this subsection (MT CO2e/MWh).

(iv) Calculating GHG emissions of imported electricity for multijurisdictional retail providers. Multijurisdictional retail providers must include emissions and megawatt-hours in the terms below from facilities or units that contribute to a common system power pool. Multijurisdictional retail providers do not include emissions or megawatt-hours in the terms below from facilities or units allocated to serve retail loads in designated states pursuant to 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. For multijurisdictional consumer-owned utilities, the cost allocation methodology must be approved by its governing board. Multijurisdictional retail providers must calculate emissions that have a compliance obligation using the following equation:

CO2e

(MWhR x TLR - MWhWSP-WA - EGWA) x EFMJRP + MWWSP-notWA x TLWSP x EFunsp - CO2e linked

(Eq. 124-9)

Where:
	CO2e	=	Annual CO2e mass emissions of imported electricity (MT of CO2e).
	MWhR	=	Total electricity procured by multijurisdictional retail provider to serve its retail customers in Washington, reported as retail sales for Washington state service territory, MWh.
	MWhWSP-WA	=	Wholesale electricity procured in Washington state by multijurisdictional retail provider to serve its retail customers in Washington state, as determined by the first point of receipt on a e-tag and pursuant to a cost allocation methodology approved by the Washington state utilities and transportation commission (UTC) and the utility regulatory commission of at least one additional state in which the multijurisdictional retail provider provides retail electric service, MWh. For multijurisdictional consumer-owned utilities, the cost allocation methodology must be approved by its governing board.
	MWhWSP-not WA	=	Wholesale electricity imported into Washington state by multijurisdictional retail provider with a final point of delivery in Washington state and not used to serve its Washington state retail customers, MWh.
	EFMJRP	=	Multijurisdictional retail provider system emission factor calculated by ecology and 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. For multijurisdictional consumer-owned utilities, the cost allocation methodology must be approved by its governing board.
	EFunsp	=	Default emission factor for unspecified sources calculated consistent with this section (MT CO2e/MWh).
	EGWA	=	Net generation measured at the busbar of facilities and units located in Washington state that are allocated to serve its retail customers in Washington state pursuant to 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, MWh. For multijurisdictional consumer-owned utilities, the cost allocation methodology must be approved by its governing board.
	TL	=	Transmission loss correction factor.
	TL WSP	=	1.02 for transmission losses applied to wholesale power.
	TL R	=	Estimate of transmission losses from busbar to end user reported by multijurisdictional retail provider.
	CO2e linked	=	Annual CO2e mass emissions recognized by ecology pursuant to linkage under chapter 316, Laws of 2021, as described in chapter 173-446 WAC (MT of CO2e).

(c) Additional requirements for retail providers, excluding multijurisdictional retail providers. Retail providers must include the following information in the GHG emissions data report for each report year, in addition to the information identified in (a)(i), (ii), and (vii) of this subsection.

(i) Retail providers must report Washington state retail sales. A retail provider who is required only to report retail sales may choose not to apply the verification requirements specified in WAC 173-441-085, if the retail provider deems the emissions data report nonconfidential.

(ii) Retail providers may elect to report the subset of retail sales attributed to the electrification of shipping ports, truck stops, and motor vehicles if metering is available to separately track these sales from other retail sales.

(d) Retail providers that report as electricity importers or exporters also must separately report electricity imported from specified and unspecified sources by other electric power entities to serve their load, designating the electricity importer. In addition, all imported electricity transactions documented by e-tags where the retail provider is the PSE at the sink must be reported.

(e) Additional requirements for multijurisdictional retail providers. Multijurisdictional retail providers that provide electricity into Washington state at the distribution level must include the following information in the GHG emissions data report for each report year, in addition to the information identified elsewhere in this section.

(i) A report of the electricity transactions and GHG emissions associated with the common power system or contiguous service territory that includes consumers in Washington state. This includes the requirements in this section as applicable for each generating facility or unit in the multijurisdictional retail provider's fleet;

(ii) The multijurisdictional retail provider must include in its emissions data report wholesale power purchased and taken (MWh) from specified and unspecified sources and wholesale power sold from specified sources according to the specifications in this section, and as required for ecology to calculate a supplier-specific emission factor;

(iii) Total retail sales (MWh) by the multijurisdictional retail provider in the contiguous service territory or power system that includes consumers in Washington state;

(iv) Retail sales (MWh) to Washington state customers served in Washington state's portion of the service territory;

(v) Retail sales derived from the energy imbalance market;

(vi) GHG emissions associated with the imported electricity, including both Washington state retail sales and wholesale power imported into Washington state from the retail provider's system, according to the specifications in this section;

(vii) Multijurisdictional retail providers that serve Washington state load must claim as specified power all power purchased or taken from facilities or units in which they have operational control or an ownership share or written power contract;

(viii) Multijurisdictional retail providers that serve Washington state load may elect to exclude information listed in this section when registering claims to specified power from facilities located outside Washington state and participating in the Federal Energy Regulatory Commission's PURPA Qualifying Facility program.

(f) Additional requirements for asset-controlling suppliers. Owners or operators of electricity generating facilities or exclusive marketers for certain generating facilities may apply for an asset-controlling supplier designation from ecology. Approved asset-controlling suppliers may request that ecology calculate or adopt a supplier-specific emission factor pursuant to this section. To apply for asset-controlling supplier designation, the applicant must:

(i) Meet the requirements in this chapter, including reporting pursuant as applicable for each generating facility or unit in the supplier's fleet;

(ii) Include in its emissions data report wholesale power purchased and taken (MWh) from specified and unspecified sources and wholesale power sold from specified sources according to the specifications in this section, and as required for ecology to calculate a supplier-specific emission factor;

(iii) Retain for verification purposes documentation that the power sold by the supplier originated from the supplier's fleet of facilities and either that the fleet is under the supplier's operational control or that the supplier serves as the fleet's exclusive marketer;

(iv) Provide the supplier-specific ecology identification number to electric power entities who purchase electricity from the supplier's system.

(v) To apply for and maintain asset-controlling supplier status, the entity shall submit as part of its emissions data report the following information, annually:

(A) General business information, including entity name and contact information;

(B) List of officer names and titles;

(D) A list and description of electricity generating facilities for which the reporting entity is a first jurisdiction deliverer; and

(E) An attestation, in writing and signed by an authorized officer of the applicant, as follows:

(I) "I certify under penalty of perjury under the laws of the State of Washington that I am duly authorized by (name of entity) to sign this attestation on behalf of (name of entity), that (name of entity) meets the definition of an asset-controlling supplier as specified in this section and that the information submitted herein is true, accurate, and complete."

(II) Asset-controlling suppliers must annually adhere to all reporting and verification requirements of this chapter, or be removed from asset-controlling supplier designation. Asset-controlling suppliers will also lose their designation if they receive an adverse verification statement, but may reapply in the following year for redesignation.

(g) Requirements for claims of specified sources of electricity. Each reporting entity claiming specified facilities or units for imported or exported electricity must register its anticipated specified sources with ecology by the registration due date in WAC 173-441-060(4) to obtain associated emission factors calculated by ecology for use in the emissions data report required to be submitted by the report submission due date in WAC 173-441-050 (2)(a). If an operator fails to register a specified source by the registration due date in WAC 173-441-060(4), the operator must use the emission factor provided by ecology for a specified facility or unit in the emissions data report required to be submitted by the report submission due date in WAC 173-441-050 (2)(a). Each reporting entity claiming specified facilities or units for imported or exported electricity must also meet requirements in the emissions data report.

(i) Registration information for specified sources. The following information is required:

(A) The facility names and, for specification to the unit level, the facility and unit names.

(B) For sources with a previously assigned ecology identification number, the ecology facility or unit identification number or supplier number published on ecology's website. For newly specified sources, ecology will assign a unique identification number.

(C) If applicable, the facility and unit identification numbers as used for reporting to the U.S. EPA Acid Rain Program, U.S. EPA pursuant to 40 C.F.R. Part 98, U.S. Energy Information Administration, Federal Energy Regulatory Commission's PURPA Qualifying Facility program, as applicable.

(D) The physical address of each facility, including jurisdiction.

(E) Provide names of facility owner and operator.

(F) The percent ownership share and whether the facility or unit is under the electricity importer's operational control.

(G) Total facility or unit gross and net nameplate capacity when the electricity importer is a GPE.

(H) Total facility or unit gross and net generation when the electricity importer is a GPE.

(I) Start date of commercial operation and, when applicable, date of repowering.

(J) GPEs claiming additional capacity at an existing facility must include the implementation date, the expected increase in net generation (MWh), and a description of the actions taken to increase capacity.

(K) Designate whether the facility or unit is a newly specified source, a continuing specified source, or was a specified source in the previous report year that will not be specified in the current report year.

(L) Provide the primary technology or fuel type as listed below:

(I) Variable renewable resources by type, defined for purposes of this chapter as pure solar, pure wind, and run-of-river hydroelectricity;

(II) Hybrid facilities such as solar thermal;

(III) Hydroelectric facilities ≤ 30 MW, not run-of-river;

(IV) Hydroelectric facilities > 30 MW;

(V) Geothermal binary cycle plant or closed loop system;

(VI) Geothermal steam plant or open loop system;

(VII) Units combusting biomass-derived fuel, by primary fuel type;

(VIII) Nuclear facilities;

(IX) Cogeneration by primary fuel type;

(X) Fossil sources by primary fuel type;

(XI) Co-fired fuels;

(XII) Municipal solid waste combustion;

(XIII) Other.

(ii) Emission factors. The emission factor published on the ecology website, calculated by ecology according to the methods in this section, must be used when reporting GHG emissions for a specified source of electricity.

(iii) Delivery tracking conditions required for specified electricity imports. Electricity importers must claim a specified source when the electricity delivery meets any of the criteria for direct delivery of electricity, and one of the following sets of conditions:

(A) The electricity importer is a GPE; or

(B) The electricity importer has a written power contract for electricity generated by the facility or unit, subject to meeting all other specified source requirements.

(iv) Additional information for specified sources. For each claim to a specified source of electricity, the electricity importer must indicate whether one or more of the following descriptions applies:

(A) Deliveries from existing federally owned hydroelectricity facilities by exclusive marketers. Electricity from specified federally owned hydroelectricity facility delivered by exclusive marketers;

(B) Deliveries from new facilities. Specified source of electricity is first registered pursuant to this section and delivered by an electricity importer within 12 months of the start date of commercial operation and the electricity importer making a claim in the current data year is either a GPE or purchaser of electricity under a written power contract;

(C) Deliveries from existing facilities with additional capacity. Specified source of electricity is first registered pursuant to this section and delivered by a GPE within 12 months of the start date of an increase in the facility's generating capacity due to increased efficiencies or other capacity increasing actions.

(v) Substitute electricity. Report substitute electricity received from specified and unspecified sources pursuant to the requirements of this section.

(4) Recordkeeping. GHG inventory program for electric power entities that import or export electricity. In lieu of a GHG monitoring plan, electric power entities that import or export electricity must prepare GHG inventory program documentation that is maintained and available for verifier review and ecology audit pursuant to the recordkeeping requirements of this section. The following information is required:

(a) Information to allow the verification team to develop a general understanding of entity boundaries, operations, and electricity transactions;

(b) Reference to management policies or practices applicable to reporting pursuant to this section;

(d) Training practices for personnel involved in reporting delivered electricity and responsible for data report certification, including documented training procedures;

(e) Query of e-tag source data to determine the quantity of electricity (MWh) imported, exported, and wheeled for transactions in which they are the purchasing-selling entity on the last physical path segment that crosses the border of Washington state, access to review the raw e-tag data, a tabulated summary, and query description;

(f) Reference to other independent or internal data management systems and records, including written power contracts and associated verbal or electronic records, full or partial ownership, invoices, and settlements data used to document whether reported transactions are specified or unspecified and whether the requirements for adjustments to covered emissions of chapter 316, Laws of 2021, as described in chapter 173-446 WAC are met;

(g) Description of steps taken and calculations made to aggregate data into reporting categories required pursuant to this section;

(h) Records of preventive and corrective actions taken to address verifier and ecology findings of past nonconformances and material misstatements;

(i) Log of emissions data report modifications made after initial certification; and

(j) A written description of an internal audit program that includes emissions data report review and documents ongoing efforts to improve the GHG inventory program.

AMENDATORY SECTION(Amending WSR 15-04-051, filed 1/29/15, effective 3/1/15)

WAC 173-441-140Petitioning 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. ((Alternative calculation methodologies are not available for GHG emissions covered by a source category adopted by reference in WAC 173-441-130.)) 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 one hundred eighty 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 ((70.94.151))70A.15.2200. Ecology will notify the owner or operator within thirty 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 sixty 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 ((facilities))reporters required to report under WAC 173-441-030(((1))) 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(((4)))(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 ((173-441-130))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 ((International))Intergovernmental Panel on Climate Change;

(((IV) The Western Climate Initiative;

(V) The Climate Registry;))

(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 ((70.94.151))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 ((70.94.151))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 ((70.94.151))70A.15.2200 and for which calculation methods have been established in WAC 173-441-120, 173-441-122, or ((173-441-130))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, ((173-441-130))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).

AMENDATORY SECTION(Amending WSR 10-24-108, filed 12/1/10, effective 1/1/11)

WAC 173-441-150Confidentiality.

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

(2) ((Any proprietary or confidential information exempt from disclosure when reported to DOL that ecology obtains directly from DOL remains exempt from disclosure.

(3))) Information considered confidential by EPA or other jurisdictions is not considered confidential by ecology unless it also meets the conditions established in subsection (((2) or (4)))(3) of this section.

(((4)))(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 ((70.94.205))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 ((70.94.205))70A.15.2510.

(((5)))(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.

REPEALER

The following section of the Washington Administrative Code is repealed:

WAC 173-441-130

Calculation methods for suppliers.

Reporter Type	Low Count	High Count
Existing facilities	159	159
New facilities	0	0
Existing suppliers	42	42
New suppliers	16	26
New electric power entities	50	60
Ceasing reporting (statutory change)	5	5
Total	272	292

Reporter Type	Median Cost per Employee Small Businesses	Median Cost per Employee Largest 10 Percent of Businesses
Electric power entities	$2,188	$44
Facilities	$208	$1
Suppliers	$2,334	$23

Industry	Initial Jobs Impact	Jobs Impact in Year 20
All industries	-19 to -21	-18 to -20
Construction	-4 to -5	-2
Retail trade	-2 to -3	-1
Manufacturing	-2	-2
Health care and social assistance	-1 to -2	-1 to -2

To convert from	To	Multiply by
Kilograms (kg)	Pounds (lbs)	2.20462
Pounds (lbs)	Kilograms (kg)	0.45359
Pounds (lbs)	Metric tons	4.53592 x 10-4
Short tons	Pounds (lbs)	2,000
Short tons	Metric tons	0.90718
Metric tons	Short tons	1.10231
Metric tons	Kilograms (kg)	1,000
Cubic meters (m3)	Cubic feet (ft3)	35.31467
Cubic feet (ft3)	Cubic meters (m3)	0.028317
Gallons (liquid, US)	Liters (l)	3.78541
Liters (l)	Gallons (liquid, US)	0.26417
Barrels of liquid fuel (bbl)	Cubic meters (m3)	0.15891
Cubic meters (m3)	Barrels of liquid fuel (bbl)	6.289
Barrels of liquid fuel (bbl)	Gallons (liquid, US)	42
Gallons (liquid, US)	Barrels of liquid fuel (bbl)	0.023810
Gallons (liquid, US)	Cubic meters (m3)	0.0037854
Liters (l)	Cubic meters (m3)	0.001
Feet (ft)	Meters (m)	0.3048
Meters (m)	Feet (ft)	3.28084
Miles (mi)	Kilometers (km)	1.60934
Kilometers (km)	Miles (mi)	0.62137
Square feet (ft2)	Acres	2.29568 x 10-5
Square meters (m2)	Acres	2.47105 x 10-4
Square miles (mi2)	Square kilometers (km2)	2.58999
Degrees Celsius (°C)	Degrees Fahrenheit (°F)	°C = (5/9) x (°F - 32)
Degrees Fahrenheit (°F)	Degrees Celsius (°C)	°F = (9/5) x (°C + 32)
Degrees Celsius (°C)	Kelvin (K)	K = °C + 273.15
Kelvin (K)	Degrees Rankine (°R)	1.8
Joules	Btu	9.47817 x 10-4
Btu	MMBtu	1 x 10-6
Pascals (Pa)	Inches of Mercury (in Hg)	2.95334 x 10-4
Inches of Mercury (in Hg)	Pounds per square inch (psi)	0.49110
Pounds per square inch (psi)	Inches of Mercury (in Hg)	2.03625

Verification Type	Low Count	High Count
Third party required	201	221
Third party NOT required	71	71
Total	272	292