The definitions below apply to all of WAC 480-100-600 through 480-100-665.

"Allocation of electricity" means, for the purposes of setting electricity rates, the costs and benefits associated with the resources used to provide electricity to an electric utility's retail electricity consumers that are located in this state.

"Alternative lowest reasonable cost and reasonably available portfolio" means, for purposes of calculating the incremental cost of compliance in RCW 19.405.060(3), the portfolio of investments the utility would have made and the expenses the utility would have incurred if not for the requirement to comply with RCW 19.405.040 and 19.405.050. The alternative lowest reasonable cost and reasonably available portfolio must include the social cost of greenhouse gases in the resource acquisition decision in accordance with RCW 19.280.030 (3)(a).

"Biomass energy" includes: Organic by-products of pulping and the wood manufacturing process; animal manure; solid organic fuels from wood; forest or field residues; untreated wooden demolition or construction debris; food waste and food processing residuals; liquors derived from algae; dedicated energy crops; and yard waste.

Biomass energy does not include:

• Wood pieces that have been treated with chemical preservatives such as creosote, pentachlorophenol, or copper-chrome-arsenic;

• Wood from old growth forests; or

• Municipal solid waste.

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

"CEAP" means the clean energy action plan.

"CEIP" means the clean energy implementation plan.

"Coal-fired resource" means a facility that uses coal-fired generating units, or that uses units fired in whole or in part by coal as feedstock, to generate electricity. Coal-fired resource does not include:

• An electric generating facility that is included as part of a limited duration wholesale power purchase, not to exceed one month, made by an electric utility for delivery to retail electric customers that are located in this state for which the source of the power is not known at the time of entry into the transaction to procure the electricity; or

• An electric generating facility that is subject to an obligation to meet the standards contained in RCW 80.80.040 (3)(c).

"Commission" means the Washington utilities and transportation commission.

"Conservation and efficiency resources" means any reduction in electric power consumption that results from increases in the efficiency of energy use, production, transmission, or distribution.

"Cost-effective" means that a project or resource is forecast: (a) To be reliable and available within the time it is needed; and (b) to meet or reduce the electric power demand of the intended consumers at an estimated incremental system cost no greater than that of the least-cost similarly reliable and available alternative project or resource, or any combination thereof.

"Customer benefit indicator" means an attribute, either quantitative or qualitative, of resources or related distribution investments associated with customer benefits described in RCW 19.405.040(8).

"Demand response" means changes in electric usage by demand-side resources from their normal consumption patterns in response to changes in the price of electricity, or to incentive payments designed to induce lower electricity use, at times of high wholesale market prices or when system reliability is jeopardized. Demand response may include measures to increase or decrease electricity production on the customer's side of the meter in response to incentive payments.

"Distributed energy resource" means a nonemitting electric generation or renewable resource or program that reduces electric demand, manages the level or timing of electricity consumption, or provides storage, electric energy, capacity, or ancillary services to an electric utility and that is located on the distribution system, any subsystem of the distribution system, or behind the customer meter, including conservation and energy efficiency.

"Energy assistance" means a program undertaken by a utility to reduce the household energy burden of its customers.

• Energy assistance includes, but is not limited to, weatherization, conservation and efficiency services, and monetary assistance, such as a grant program or discounts for lower income households, intended to lower a household's energy burden.

• Energy assistance may include direct customer ownership in distributed energy resources or other strategies if such strategies achieve a reduction in energy burden for the customer above other available conservation and demand-side measures.

"Energy assistance need" means the amount of assistance necessary to achieve an energy burden equal to six percent for utility customers.

"Energy burden" means the share of annual household income used to pay annual home energy bills.

"Equitable distribution" means a fair and just, but not necessarily equal, allocation of benefits and burdens from the utility's transition to clean energy. Equitable distribution is based on disparities in current conditions. Current conditions are informed by, among other things, the assessment described in RCW 19.280.030 (1)(k) from the most recent integrated resource plan.

"Fossil fuel" means natural gas, petroleum, coal, or any form of solid, liquid, or gaseous fuel derived from such a material.

"Greenhouse gas" includes carbon dioxide, methane, nitrous oxide, hydrofluorocarbons, perfluorocarbons, sulfur hexafluoride, and any other gas or gases designated by the department of ecology by rule under RCW 70A.45.010.

"Highly impacted community" means a community designated by the department of health based on the cumulative impact analysis required by RCW 19.405.140 or a community located in census tracts that are fully or partially on "Indian country," as defined in 18 U.S.C. Sec. 1151.

"Implementation period" means the four years after the filing of each clean energy implementation plan through 2045. The first implementation period will begin January 1, 2022, and will end December 31, 2025, and the second implementation period will begin on January 1, 2026, and will end on December 31, 2029.

"Integrated resource plan" or "IRP" means an analysis describing the mix of generating resources, conservation, methods, technologies, and resources to integrate renewable resources and, where applicable, address overgeneration events, and efficiency resources that will meet current and projected needs at the lowest reasonable cost to the utility and its ratepayers and that complies with the requirements specified in RCW 19.280.030(1).

"Lowest reasonable cost" means the lowest cost mix of generating resources and conservation and efficiency resources determined through a detailed and consistent analysis of a wide range of commercially available resources. At a minimum, this analysis must consider resource cost, market-volatility risks, demand-side resource uncertainties, resource dispatchability, resource effect on system operation, the risks imposed on the utility and its customers, public policies regarding resource preference adopted by Washington or the federal government, and the cost of risks associated with environmental effects, including emissions of carbon dioxide. The analysis of the lowest reasonable cost must describe the utility's combination of planned resources and related delivery system infrastructure and show consistency with chapters 19.280, 19.285, and 19.405 RCW.

"Natural gas" means naturally occurring mixtures of hydrocarbon gases and vapors consisting principally of methane, whether in gaseous or liquid form, including methane clathrate. Natural gas does not include renewable natural gas or the portion of renewable natural gas when blended into other fuels.

"Nonemitting electric generation" means electricity from a generating facility or a resource that provides electric energy, capacity, or ancillary services to an electric utility and that does not emit greenhouse gases as a by-product of energy generation. Nonemitting electric generation does not include renewable resources.

"Nonpower attributes" means all environmentally related characteristics, exclusive of energy, capacity reliability, and other electrical power service attributes, that are associated with the generation of electricity including, but not limited to, the facility's fuel type, geographic location, vintage, qualification as a renewable resource, and avoided emissions of pollutants to the air, soil, or water, and avoided emissions of carbon dioxide and other greenhouse gases. Nonpower attributes does not include any aspects, claims, characteristics, and benefits associated with the on-site capture and destruction of methane or other greenhouse gases at a facility through a digester system, landfill gas collection system, or other mechanism, which may be separately marketable as greenhouse gas emission reduction credits, offsets, or similar tradable commodities. However, these separate avoided emissions may not result in or otherwise have the effect of attributing greenhouse gas emissions to the electricity.

"Primary compliance" means the portion of the compliance obligation under RCW 19.405.040(1) that cannot be met through the alternative compliance options outlined in RCW 19.405.040 (1)(b).

"Renewable energy credit" or "REC" means a tradable certificate of proof of one megawatt-hour of a renewable resource. The certificate includes all of the nonpower attributes associated with that one megawatt-hour of electricity and the certificate is verified by a renewable energy credit tracking system selected by the department of commerce.

"Renewable resource" means water; wind; solar energy; geothermal energy; renewable natural gas; renewable hydrogen; wave, ocean, or tidal power; biodiesel fuel that is not derived from crops raised on land cleared from old growth or first growth forests; or biomass energy.

"Resource" includes, but is not limited to, generation, conservation, distributed generation, demand response, efficiency, and storage.

"Resource need" means any current or projected deficit to reliably meet electricity demands created by changes in demand, changes to system resources, or their operation to comply with state or federal requirements. Such demands or requirements may include, but are not limited to, capacity and associated energy, capacity needed to meet peak demand in any season, fossil-fuel generation retirements, equitable distribution of benefits or reduction of burdens, cost-effective conservation and efficiency resources, demand response, and renewable and nonemitting resources.

"Retail electric load" means the amount of megawatt-hours of electricity delivered in a given calendar year by an electric utility to its Washington retail electric customers. "Retail electric load" does not include:

(a) Megawatt-hours delivered from qualifying facilities under the federal Public Utility Regulatory Policies Act of 1978, P.L. 95-617, in operation prior to May 7, 2019, provided that no entity other than the electric utility can make a claim on delivery of the megawatt-hours from those resources; or

(b) Megawatt-hours delivered to an electric utility's system from a renewable resource through a voluntary renewable energy purchase by a retail electric customer of the utility in which the renewable energy credits associated with the megawatt-hours delivered are retired on behalf of the retail electric customer.

"Retained nonpower attribute" or "retained NPA" means the nonpower attributes of renewable electricity (represented by RECs) or the nonpower attributes of nonemitting electricity, from electricity owned or controlled by a utility where the associated electricity was sold by that utility in a wholesale sale without its associated nonpower attributes (NPA).

"Social cost of greenhouse gas emissions" or "SCGHG" is the inflation-adjusted costs of greenhouse gas emissions resulting from the generation of electricity, as required by RCW 80.28.405, the updated calculation of which is published on the commission's website.

"Unbundled renewable energy credit" or "unbundled REC" means a renewable energy credit that is sold, delivered, or purchased separately from the underlying electricity. All thermal renewable energy credits are considered unbundled renewable energy credits.

"Unspecified electricity" means an electricity source for which the fuel attribute is unknown or has been separated from the energy delivered to retail electric customers.

"Vulnerable populations" means communities that experience a disproportionate cumulative risk from environmental burdens due to: (a) Adverse socioeconomic factors, including unemployment, high housing and transportation costs relative to income, access to food and health care, and linguistic isolation; and (b) sensitivity factors, such as low birth weight and higher rates of hospitalization.

(1) Purpose. Consistent with chapters 80.28, 19.280, and 19.405 RCW, each electric utility has the responsibility to identify and meet its resource needs with the lowest reasonable cost mix of conservation and efficiency, generation, distributed energy resources, and delivery system investments to ensure the utility provides energy to its customers that is clean, affordable, reliable, and equitably distributed. At a minimum, integrated resource plans must include the components listed in this rule. Unless otherwise stated, the assessments, evaluations, and forecasts should be over an appropriate planning horizon.

(2) Load forecast. The IRP must include a range of forecasts of projected customer demand that reflect the effect of economic forces on the consumption of electricity and address changes in the number, type, and efficiency of end uses of electricity.

(3) Distributed energy resources.

(a) The IRP must include assessments of a variety of distributed energy resources. These assessments must incorporate nonenergy costs and benefits not fully valued elsewhere within any integrated resource plan model. Utilities must assess the effect of distributed energy resources on the utility's load and operations under RCW 19.280.030 (1)(h). The commission strongly encourages utilities to engage in a distributed energy resource planning process as described in RCW 19.280.100. If the utility elects to use a distributed energy resource planning process, the IRP should include a summary of the results.

(b) The required distributed energy resource assessments must include the following:

(i) Energy efficiency and conservation potential assessment – The IRP must assess currently employed and potential policies and programs needed to obtain all cost-effective conservation, efficiency, and load management improvements, including the ((ten-year))10-year conservation potential used in calculating a biennial conservation target under chapter 480-109 WAC;

(ii) Demand response potential assessment – The IRP must assess currently employed and new policies and programs needed to obtain all cost-effective demand response;

(iii) Energy assistance potential assessment – The IRP must include distributed energy programs and mechanisms identified pursuant to RCW 19.405.120, which pertains to energy assistance and progress toward meeting energy assistance need; and

(iv) Other distributed energy resource potential assessments – The IRP must assess other distributed energy resources that may be installed by the utility or the utility's customers including, but not limited to, energy storage, electric vehicles, and photovoltaics. Any such assessment must include the effect of distributed energy resources on the utility's load and operations.

(4) Supply-side resources. The IRP must include an assessment of a wide range of commercially available generating and nonconventional resources, including ancillary service technologies.

(5) Renewable resource integration. An assessment of methods, commercially available technologies, or facilities for integrating renewable resources including, but not limited to, battery storage and pumped storage, and addressing overgeneration events, if applicable to the utility's resource portfolio. The assessment may address ancillary services.

(6) Regional generation and transmission. The IRP must include an assessment of the availability of regional generation and transmission capacity on which the utility may rely to provide and deliver electricity to its customers.

(a) The assessment must include the utility's existing transmission capabilities((,)) and future resource needs during the planning horizon, including identification of facilities necessary to meet future transmission needs.

(b) The assessment must also identify the general location and extent of transfer capability limitations on its transmission network that may affect the future siting of resources.

(7) Resource evaluation. The IRP must include a comparative evaluation of all identified resources and potential changes to existing resources for achieving the clean energy transformation standards in WAC 480-100-610 at the lowest reasonable cost.

(8) Resource adequacy. The IRP must include an assessment and determination of resource adequacy metrics. It must also identify an appropriate resource adequacy requirement and measurement metrics consistent with RCW 19.405.030 through 19.405.050.

(9) Economic, health, and environmental burdens and benefits. The IRP must include an assessment of energy and nonenergy benefits and reductions of burdens to vulnerable populations and highly impacted communities; long-term and short-term public health and environmental benefits, costs, and risks; and energy security risk. The assessment should be informed by the cumulative impact analysis conducted by the department of health.

(10) Scenarios and sensitivities. The IRP must include a range of possible future scenarios and input sensitivities for the purpose of testing the robustness of the utility's resource portfolio under various parameters. The IRP must also provide a narrative description of scenarios and sensitivities the utility used, including those informed by the advisory group process.

(a) At least one scenario must describe the alternative lowest reasonable cost and reasonably available portfolio that the utility would have implemented if not for the requirement to comply with RCW 19.405.040 and 19.405.050, as described in WAC 480-100-660(1). This scenario's conditions and inputs should be the same as the preferred portfolio except for those conditions and inputs that must change to account for the impact of RCW 19.405.040 and 19.405.050.

(b) At least one scenario must be a future climate change scenario. This scenario should incorporate the best science available to analyze impacts including, but not limited to, changes in snowpack, streamflow, rainfall, heating and cooling degree days, and load changes resulting from climate change.

(c) At least one sensitivity must be a maximum customer benefit scenario. This sensitivity should model the maximum amount of customer benefits described in RCW 19.405.040(8) prior to balancing against other goals.

(11) Portfolio analysis and preferred portfolio. The utility must integrate the demand forecasts and resource evaluations into a long-range integrated resource plan solution describing the mix of resources that meet current and projected resource needs. The utility may not include retained NPAs for primary compliance in its long-range integrated resource plan solution, consistent with WAC 480-100-650 (1)(a). The utility may not include retained NPAs in any way in its long-range integrated resource plan solution, consistent with WAC 480-100-650(2). Each utility must provide a narrative explanation of the decisions it has made, including how the utility's long-range integrated resource plan expects to:

(a) Achieve the clean energy transformation standards in WAC 480-100-610 (1) through (3) at the lowest reasonable cost;

(b) Serve utility load, based on hourly data, with the output of the utility's owned resources, market purchases, and power purchase agreements, net of any off-system sales of such resources;

(d) Include all cost-effective, reliable, and feasible conservation and efficiency resources, using the methodology established in RCW 19.285.040, and demand response;

(((d)))(e) Consider acquisition of existing renewable resources;

(((e)))(f) In the acquisition of new resources constructed after May 7, 2019, rely on renewable resources and energy storage, insofar as doing so is at the lowest reasonable cost;

(((f)))(g) Maintain and protect the safety, reliable operation, and balancing of the utility's electric system, including mitigating over-generation events and achieving the identified resource adequacy requirement;

(((g)))(h) Achieve the requirements in WAC 480-100-610 (4)(c); the description should include, but is not limited to:

(i) The long-term strategy and interim steps the utility will take to equitably distribute benefits and reduce burdens for highly impacted communities and vulnerable populations; and

(ii) The estimated degree to which benefits will be equitably distributed and burdens reduced over the planning horizon((.));

(((h)))(i) Assess the environmental health impacts to highly impacted communities;

(((i)))(j) Analyze and consider combinations of distributed energy resource costs, benefits, and operational characteristics including ancillary services((,)) to meet system needs; and

(((j)))(k) Incorporate the social cost of greenhouse gas emissions as a cost adder as specified in RCW 19.280.030(3).

(12) Clean energy action plan (CEAP). The utility must develop a ((ten-year))10-year clean energy action plan for implementing RCW 19.405.030 through 19.405.050. The CEAP must:

(a) Be at the lowest reasonable cost;

(b) Identify and be informed by the utility's ((ten-year))10-year cost-effective conservation potential assessment as determined under RCW 19.285.040;

(i) Describing the specific actions the utility will take to equitably distribute benefits and reduce burdens for highly impacted communities and vulnerable populations;

(ii) Estimating the degree to which such benefits will be equitably distributed and burdens reduced over the CEAP's ((ten-year))10-year horizon; and

(iii) Describing how the specific actions are consistent with the long-term strategy described in ((WAC 480-100-620 (11)(g).))subsection (11)(h) of this section;

(d) Establish a resource adequacy requirement;

(e) Identify the potential cost-effective demand response and load management programs that may be acquired;

(f) Identify renewable resources, nonemitting electric generation, and distributed energy resources that may be acquired and evaluate how each identified resource may reasonably be expected to contribute to meeting the utility's resource adequacy requirement;

(g) Identify any need to develop new, or to expand or upgrade existing, bulk transmission and distribution facilities;

(h) Identify the nature and possible extent to which the utility may need to rely on an alternative compliance option identified under RCW 19.405.040 (1)(b), if appropriate; and

(i) Incorporate the social cost of greenhouse gas emissions as a cost adder as specified in RCW 19.280.030(3).

(13) Avoided cost and nonenergy impacts. The IRP must include an analysis and summary of the avoided cost estimate for energy, capacity, transmission, distribution, and greenhouse gas emissions costs. The utility must list nonenergy costs and benefits addressed in the IRP and should specify if they accrue to the utility, customers, participants, vulnerable populations, highly impacted communities, or the general public. The utility may provide this content as an appendix.

(14) Data disclosure. The utility must include the data input files made available to the commission in native format per RCW 19.280.030 (10)(a) and (b) and in an easily accessible format as an appendix to the IRP. For filing confidential information, the utility may designate information within the data input files as confidential, provided that the information and designation meet the requirements of WAC 480-07-160.

(15) Information relating to purchases of electricity from qualifying facilities. Each utility must provide information and analysis that it will use to inform its annual filings required under chapter 480-106 WAC. The detailed analysis must include, but is not limited to, the following components:

(a) A description of the methodology used to calculate estimates of the avoided cost of energy, capacity, transmission, distribution, and emissions averaged across the utility; and

(b) Resource assumptions and market forecasts used in the utility's schedule of estimated avoided cost required in WAC 480-106-040 including, but not limited to, cost assumptions, production estimates, peak capacity contribution estimates and annual capacity factor estimates.

(16) Report of substantive changes. The IRP must include a summary of substantive changes to modeling methodologies or inputs that result in changes to the utility's resource need, as compared to the utility's previous IRP.

(17) Summary of public comments. The utility must provide a summary of public comments received during the development of its IRP and the utility's responses, including whether issues raised in the comments were addressed and incorporated into the final IRP as well as documentation of the reasons for rejecting any public input. The utility may include the summary as an appendix to the final IRP. Comments with similar content or input may be consolidated with a single utility response.

(1) Timing. Unless otherwise ordered by the commission, each electric utility must file an integrated resource plan (IRP) with the commission by January 1, 2021, and every four years thereafter.

(2) IRP work plan. No later than ((fifteen))15 months prior to the due date of its IRP, the utility must file a work plan that includes advisory group input and outlines the content of the IRP and expectations for the subsequent two-year progress report. The utility must include the following in its work plan:

(a) The methods for assessing potential resources;

(b) A proposed schedule of meetings for the utility's resource planning advisory group and equity advisory group, as established in WAC 480-100-655 (1)(b), for the IRP;

(c) A list of significant topics, consistent with WAC 480-100-620, that will be discussed at each advisory group meeting for the IRP;

(d) The date the draft IRP will be filed with the commission;

(e) The date the final IRP will be filed;

(f) A link to the utility's website, updated in a timely manner, to which the utility posts and makes publicly available information related to the IRP, including information outlined in subsection (5) of this section;

(g) If the utility anticipates significant changes in the workplan, it must file an updated workplan.

(3) Draft IRP. No later than four months prior to the due date of the final IRP, the utility must file its draft IRP with the commission. At minimum, the draft IRP must include the preferred portfolio, CEAP, and supporting analysis, and to the extent practicable all scenarios, sensitivities, appendices, and attachments.

(a) The commission will hear public comment on the draft IRP at an open meeting scheduled after the utility files its draft IRP. The commission will accept public comments electronically and in any other available formats, as outlined in the commission's notice for the open public meeting and opportunity to comment.

(b) The utility must file with the commission completed presentation materials concerning the draft IRP at least five business days prior to the open meeting.

(4) Two-year progress report. At least every two years after the utility files its IRP, beginning January 1, 2023, the utility must file a two-year progress report.

(a) In this report, the utility must update its:

(i) Load forecast;

(ii) Demand-side resource assessment, including a new conservation potential assessment;

(iii) Resource costs; and

(iv) The portfolio analysis and preferred portfolio.

(b) The progress report must include other updates that are necessary due to changing state or federal requirements, or significant changes to economic or market forces.

(c) The progress report must also update for any elements found in the utility's current clean energy implementation plan, as described in WAC 480-100-640.

(5) Publicly available information. The utility must make the following information publicly available on its website:

(a) Meeting summaries and materials for advisory group meetings, including materials for future meetings;

(b) A current schedule of advisory group meetings and significant topics to be covered, actively updated by the company and changes highlighted;

(d) Advisory group comments about the IRP and its development received to date, including responses communicating how the subject of the input was considered or used. Comments with similar content or input may be consolidated with a single utility response.

(1) Filing requirements – General. Unless otherwise ordered by the commission, each electric utility must file with the commission a CEIP by October 1, 2021, and every four years thereafter. The CEIP describes the utility's plan for making progress toward meeting the clean energy transformation standards((,)) and is informed by the utility's clean energy action plan. The utility may not rely on retained NPAs toward primary compliance in its CEIP, consistent with WAC 480-100-650 (1)(a). The utility may not rely on retained NPAs in any way in its CEIP, consistent with WAC 480-100-650(2). The information and documents described in each subsection below must be included in each CEIP.

(2) Interim targets.

(a) Each utility must propose a series of interim targets that:

(i) Demonstrate how the utility will make reasonable progress toward meeting the standards identified in WAC 480-100-610 (2) and (3); and

(ii) Are consistent with WAC 480-100-610(4)((; and)).

(((iii)))(b) Each utility must propose interim targets in the form of the percent of forecasted retail sales of electricity supplied by nonemitting and renewable resources prior to 2030 and from 2030 through 2045.

(((b)))(c) The utility must include the utility's percentage of retail sales of electricity supplied by nonemitting and renewable resources in 2020 in the first CEIP it files.

(((c)))(d) Each interim target must be informed by the utility's historic performance under median water conditions.

(3) Specific targets.

(a) Each utility must propose specific targets for energy efficiency, demand response, and renewable energy.

(i) The energy efficiency target must encompass all other energy efficiency and conservation targets and goals the commission requires the utility to meet. The specific energy efficiency target must be described in the utility's biennial conservation plan required in chapter 480-109 WAC. The utility must provide forecasted distribution of energy and nonenergy costs and benefits.

(ii) The utility must provide proposed program details, program budgets, measurement and verification protocols, target calculations, and forecasted distribution of energy and nonenergy costs and benefits for the utility's demand response target.

(iii) The utility must propose the renewable energy target as the percent of retail sales of electricity supplied by renewable resources and must provide details of renewable energy projects or programs, program budgets as applicable, and forecasted distribution of energy and nonenergy costs and benefits.

(b) The utility must provide a description of the technologies, data collection, processes, procedures, and assumptions the utility used to develop the targets in this subsection. The utility must make data input files that are used to determine relevant targets available in native format and in an easily accessible format as an appendix.

(4) Customer benefit data. Each CEIP must:

(a) Identify highly impacted communities using the cumulative impact analysis pursuant to RCW 19.405.140 combined with census tracts at least partially in Indian country;

(b) Identify vulnerable populations based on adverse socioeconomic factors and sensitivity factors developed through the advisory group process and public participation plan described in WAC 480-100-655, describing and explaining any changes from the utility's most recently approved CEIP; and

(c) Include proposed or updated customer benefit indicators and associated weighting factors related to WAC 480-100-610 (4)(c) including, at a minimum, one or more customer benefit indicators associated with energy benefits, nonenergy benefits, reduction of burdens, public health, environment, reduction in cost, reduction in risk, energy security, and resiliency. Customer benefit indicators and weighting factors must be developed consistent with the advisory group process and public participation plan described in WAC 480-100-655. The utility should describe and explain any changes in customer benefit indicators or weighting factors from its most recently approved CEIP.

(5) Specific actions. Each CEIP must include the specific actions the utility will take over the implementation period. The specific actions must meet and be consistent with the clean energy transformation standards and be based on the utility's clean energy action plan and interim and specific targets. Each CEIP must present the specific actions in a tabular format that provides the following information for each specific action:

(a) The general location, if applicable, proposed timing, and estimated cost of each specific action or remaining resource need, including whether the resource will be located in highly impacted communities, will be governed by, serve, or otherwise benefit highly impacted communities or vulnerable populations in part or in whole;

(b) Metrics related to resource adequacy including contributions to capacity or energy needs; and

(c) Customer benefit indicator values, or a designation as nonapplicable, for every customer benefit indicator described in subsection (4)(c) of this section.

(6) Narrative description of specific actions. The CEIP must describe how the specific actions:

(a) Demonstrate progress toward meeting the standards identified in WAC 480-100-610 (2) and (3)((;)).

(b) Demonstrate consistency with the standards identified in WAC 480-100-610(4) including, but not limited to:

(i) An assessment of current benefits and burdens on customers, by location and population, and the projected impact of specific actions on the distribution of customer benefits and burdens during the implementation period((;)).

(ii) A description of how the specific actions in the CEIP mitigate risks to highly impacted communities and vulnerable populations and are consistent with the longer-term strategies and actions described in the utilities most recent IRP and CEAP as required by WAC 480-100-620 (11)(((g)))(h) and (12)(c).

(d) Are consistent with the utility's integrated resource plan((;)).

(e) Are consistent with the utility's resource adequacy requirements, including a narrative description of how the resources identified in the most recent resource adequacy assessment conducted or adopted by the utility demonstrates that the utility will meet its resource adequacy standard((; and)).

(f) Demonstrate how the utility is planning to meet the clean energy transformation standards at the lowest reasonable cost including, but not limited to:

(i) A description of the utility's approach to identifying the lowest reasonable cost portfolio of specific actions that meet the requirements of (a) through (e) of this subsection, including a description of its methodology for weighing considerations in WAC 480-100-610(4);

(ii) A description of the utility's methodology for selecting the investments and expenses it plans to make over the next four years that are directly related to the utility's compliance with the clean energy transformation standards, consistent with RCW 19.405.050 (3)(a), and a demonstration that its planned investments represent a portfolio approach to investment plan optimization; and

(iii) Supporting documentation justifying each specific action identified in the CEIP.

(7) Projected incremental cost. Each CEIP must include a projected incremental cost as outlined in WAC 480-100-660(4).

(8) Public participation. Each CEIP must detail the extent of advisory group and other public participation in the development of the CEIP as described in WAC 480-100-655 including, but not limited to, ((the))a summary of advisory group member comments described in WAC 480-100-655 (1)(i).

(9) Alternative compliance. The utility must describe any plans it has to rely on alternative compliance mechanisms as described in RCW 19.405.040 (1)(b).

(10) Early action coal credit. If the utility proposes to take the early action compliance credit authorized in RCW 19.405.040(11), the utility must satisfy the requirements in that statutory provision and demonstrate that the proposed action constitutes early action by presenting the analysis in subsection (6) of this section both with and without the proposed early action. The utility must compare both the proposed early action and the alternative against the same proposed interim and specific targets.

(11) Biennial CEIP update. The utility must make a biennial CEIP update filing on or before November 1st of each odd-numbered year that the utility does not file a CEIP. The CEIP update may be limited to the biennial conservation plan requirements under chapter 480-109 WAC. The utility must file its biennial CEIP update in the same docket as its most recently filed CEIP and include an explanation of how the update will modify targets in its CEIP. In addition to its proposed biennial conservation plan, the utility may file in the update other proposed changes to the CEIP as a result of the integrated resource plan progress report.

(1) Greenhouse gas neutrality resource portfolio performance standards and compliance. A utility must demonstrate how its resource acquisition, resource retirement, and continued investment in and operation of existing resources serve a minimum of 80 percent of its retail electric load, or other minimum percentage established by the commission, with renewable or nonemitting electricity in each compliance period beginning January 1, 2030. Using electricity for compliance under RCW 19.405.040(1) means that a utility:

(a) May not account for the ability to apply retained NPAs toward primary compliance under (c) of this subsection when developing its long-range integrated resource plan solution under WAC 480-100-620 and its CEIP under WAC 480-100-640 and must have models, scenarios, projections, and other information and analysis within the utility's IRP and CEIP that are consistent with this requirement.

(b) May not account for the ability to apply retained NPAs toward primary compliance under (c) of this subsection or with its interim or other targets in making decisions to acquire or invest in resources with a contract term or useful life greater than two years.

(c) May report retained NPAs toward primary compliance with interim or other targets under this section or WAC 480-100-665, but only if the utility has complied with (a) and (b) of this subsection and subsection (6) of this section, and if applicable subsection (2) of this section during the period under review.

(2) One hundred percent renewable and nonemitting resource portfolio performance standards and compliance. A utility must demonstrate that it is supplying all its retail electric service obligations with renewable and nonemitting resources. To meet this requirement, the utility must demonstrate that it has secured transmission rights or assets to provide feasible transmission for renewable or nonemitting resources to serve its retail electric service obligations. A utility may not rely on retained NPAs for planning, acquisition, reporting or in any other way under RCW 19.405.050(1). A utility's demonstration of compliance with RCW 19.405.050(1) must include at a minimum an analysis of its retail electric service obligations on an hourly basis.

(3)Clean energy compliance report. Unless otherwise ordered by the commission, each electric utility must file a clean energy compliance report with the commission by July 1, 2026, and at least every four years thereafter. The report must ((demonstrate whether and how)):

(a) Demonstrate whether and how the utility met its interim targets((;)).

(b) Demonstrate whether and how the utility met its specific targets((;)).

(c) Demonstrate whether and how the specific actions the utility took made progress toward meeting the clean energy transformation standards at the lowest reasonable cost((;)).

(d) Demonstrate whether and how the utility met its statutory obligations under RCW 19.405.040(1) and 19.405.050(1) through the acquisition of the electricity and associated RECs or nonpower attributes. This requires the utility to demonstrate that the electricity the utility reports for compliance is:

(i) From a generating facility located within the utility's service area or balancing authority area; or

(ii) Acquired by the utility at one of the following points of delivery:

(A) The transmission or distribution system of an electric utility;

(B) The transmission system of the Bonneville Power Administration;

(C) The transmission system of any entity that is a participant in a centralized organized market located in the Western Interconnection in which the electric utility is a participant; or

(D) Another point of delivery designated by the electric utility for the purpose of subsequent delivery to the electric utility.

(e) Demonstrate whether and how the specific actions the utility took are consistent with the requirements in WAC 480-100-610 (4)(c) including, but not limited to:

(i) Providing updated customer benefit indicator values;

(ii) An analysis that the distribution of benefits and reductions of burdens have accrued or will reasonably accrue to intended customers, including highly impacted communities and vulnerable populations.

(((e)))(f) Provide a description of the utility's equity advisory group process, customer engagement and outcomes, and how the utility's efforts are consistent with the requirements in WAC 480-100-655 for the development or update of customer benefit indicators related to WAC 480-100-610 (4)(c)((;)).

(((f)))(g) Include the actual incremental cost of compliance as required in WAC 480-100-660(5)((;)).

(((g)))(h) Include all of the information found in the annual progress report as described in subsection (((3)))(4) of this section for the fourth year of the CEIP((;)).

(((h)))(i) Include a summary of the data in the annual progress reports described in subsection (((3)))(4) of this section((;)).

(((i)))(j) Document the use of any alternative compliance options as described in RCW 19.405.040 (1)(b), or any request for a temporary exemption per RCW 19.405.090(3)((;)).

(((j)))(k) Include a description of the public participation opportunities the utility provided and the feedback the utility received during the implementation period, including whether and how public participation influenced the utility's decisions and actions((; and)).

(((k)))(l) Include the data input files made available to the commission in native format and in an easily accessible format as an appendix.

(((2)))(4)Clean energy compliance report review process.

(a) Interested persons may file written comments with the commission regarding the utility's clean energy compliance report within ((sixty))60 days of the utility's filing unless the commission states otherwise.

(b) The commission may review clean energy compliance reports through the commission's open public meeting process, as described in chapter 480-07 WAC.

(c) After completing its review of the utility's clean energy compliance report, the commission will determine whether the utility met its specific and interim targets, and whether the utility made sufficient progress toward meeting the clean energy transformation standards.

(((3)))(5)Annual clean energy progress reports. On or before July 1st of each year beginning in 2023, other than in a year in which the utility files a clean energy compliance report, the utility must file with the commission, in the same docket as its most recently filed CEIP, an informational annual clean energy progress report regarding its progress in meeting its targets during the preceding year. The annual clean energy progress report must include, but is not limited to:

(a) Beginning July 1, 2027, and each year thereafter, an attestation for the previous calendar year that the utility did not use any coal-fired resource as defined in this chapter to serve Washington retail electric customer load((;)).

(b) Conservation achievement in megawatts, first-year megawatt-hour savings, and projected cumulative lifetime megawatt-hour savings((;)).

(d) Renewable resource capacity in megawatts, and renewable energy usage in megawatt hours and as a percentage of electricity supplied by renewable resources((;)).

(e) All renewable energy credits and the program or obligation for which they were used (e.g., voluntary renewable programs, renewable portfolio standard, clean energy transformation standards)((;)).

(f) Verification and documentation of the retirement of renewable energy credits for all electricity from renewable resources used to comply with the requirements of RCW 19.405.040, 19.405.050, a specific target, or an interim target((;)), except for electricity purchased from Bonneville Power Administration, which may be used to comply with these requirements without a renewable energy credit until January 1, 2029, as long as the nonpower attributes of the renewable energy are tracked through contract language((;)).

(g) Nonemitting resource capacity in megawatts, and nonemitting energy usage in megawatt hours and as a percentage of total electricity supplied by nonemitting energy((;)).

(h) The utility's greenhouse gas content calculation pursuant to RCW 19.405.070((;)).

(i) An electronic link to the utility's most recently filed fuel mix disclosure report as required by RCW 19.29A.140((;)).

(j) Total greenhouse gas emissions in metric tons of CO2e((;)).

(k) Demonstration of ownership of nonpower attributes for nonemitting generation using attestations of ownership and transfer by properly authorized representatives of the generating facility, all intermediate owners of the nonemitting electric generation, and an appropriate company executive of the utility; the utility may not transfer ownership of the nonpower attributes after claiming them in any compliance report((; and)).

(l) Other information the company agreed to or was ordered to report in the most recently approved CEIP or biennial CEIP update.

(6) Data and contract reporting. Each utility must file its annual clean energy progress report based on an analysis that identifies and considers the source and characteristics of the electricity a utility claims to meet compliance obligations under WAC 480-100-610, including electricity that is produced, purchased, sold, or exchanged.

(a) Unless otherwise ordered by the commission, the analysis and supporting data provided in the filing must include data in an hourly format for:

(i) Total Washington retail sales.

(ii) Retail sales for customers participating in a voluntary renewable energy purchase program in alignment with RCW 19.405.020 (36)(b).

(iii) Total electricity production for all renewable and nonemitting generation owned, contracted, or controlled by the utility.

(iv) Generation from qualifying facilities as described in RCW 19.405.020 (36)(a).

(v) All electricity sold or transferred for all bundled sales of electricity from renewable and nonemitting sources. For the purposes of this subsection, bundled electricity is electricity that is sold with all its nonpower attributes in the same transaction.

(vi) All electricity sales in which the electricity was sold by that utility in a wholesale market sale without its associated nonpower attributes.

(b) Unless otherwise ordered by the commission, the utility must include in its filing the following:

(i) Total monthly megawatt-hours of sales, purchases, and exchanges by counter party of electricity sales in which the electricity was sold by that utility in a wholesale market sale without its associated nonpower attributes. Any contract in which the utility sells electricity in a wholesale market sale without its associated nonpower attributes must include terms stating the seller is not transferring any of the nonpower attributes and the buyer may not represent in any form that the electricity has any nonpower attributes associated with it and that the buyer must include such provision in any sale of the electricity in any subsequent sale it makes.

(ii) Total monthly megawatt-hours of sales, purchases, and exchanges of bundled electricity from renewable or nonemitting generation. For the purposes of this subsection, bundled electricity is electricity that is sold with all of its nonpower attributes in the same transaction.

(iii) All purchase contracts longer than one month that source the electricity delivered from coal fueled generation.

(iv) Total monthly purchases and sales of unbundled RECs and other nonpower attributes. Based on the statutory definition of unbundled REC under RCW 19.405.020(38), a REC that meets the definition of a retained NPA under WAC 480-100-605 that is subsequently sold becomes an unbundled REC. Any unbundled REC reported for compliance must meet the requirements under (c) of this subsection.

(v) Beginning January 1, 2026, all existing or new purchase contracts longer than one month with documentation that none of the electricity delivered is sourced from coal fueled generation.

(vi) Any data provided to the Western power pool's resource adequacy program or its successor.

(c) A utility may use an unbundled REC as an alternative compliance option, as provided in RCW 19.405.040 (1)(b), only if the utility demonstrates that there is no double counting of any nonpower attribute associated with that REC. This subsection sets only the minimum requirements necessary to demonstrate that no double counting has occurred. The commission may require the utility to produce other evidence or take specific actions as the commission determines necessary to ensure that there is no double counting of nonpower attributes.

(i) Except as provided in (c)(iii) of this subsection, a utility may use an unbundled REC for alternative compliance only if the utility demonstrates:

(A) The associated electricity was sold, delivered, or transferred without fuel sources or nonpower attributes and under a contract or transaction term expressly stating the fuel source or nonpower attributes are not included; and

(B) The associated electricity was not delivered, reported, or claimed as a zero-emission specified source or assigned the emissions rate of the renewable generating facility under a greenhouse gas (GHG) program.

(ii) A utility's demonstration under this section may be met by documentation that the entity providing the unbundled REC:

(A) Provides contract, confirmation, or other transaction terms that comply with the requirements of (c)(i)(A) and (B) of this subsection;

(B) Was a party to or otherwise has knowledge of the transaction in which the associated electricity was sold or transferred and attests to (c)(i)(A) and (B) of this subsection; or

(C) Obtained the unbundled REC from an entity that attests that it and all previous owners of the REC transferred the REC using transaction terms complying with the requirements of (c)(ii)(A) or (B) of this subsection.

(iii) To claim and retire an unbundled REC for alternative compliance where the Washington-eligible RECs were created by renewable electricity marketed by the Bonneville Power Administration a utility must demonstrate the REC was not associated with electricity from a system sale from the Bonneville Power Administration directly into a state with a GHG program and to an entity regulated by the state greenhouse gas program. The RECs are calculated based on the same vintage year as the year in which the electricity was imported to the state with the greenhouse gas program.

(iv) For the purposes of (c) of this subsection, "greenhouse gas program" includes any governmental program outside of Washington that caps or limits greenhouse gas emissions or requires the purchase, surrender, or retirement of greenhouse gas allowances if the scope of the greenhouse gas program includes electricity imported from outside the governmental jurisdiction and does not require the retirement of RECs for such imported electricity.

(d) For the purposes of reporting and compliance, the storage of electricity has the following impacts:

(i) The eligibility of renewable or nonemitting electricity is not affected by the use of storage resources.

(ii) Except for storage resources located on the customer side of a retail meter, any electrical consumption or loss resulting from the charging, holding, and discharging of storage resources is not considered retail electric load as defined in RCW 19.405.020(36).

(iii) For reporting and compliance with subsections (1)(a), (b), and (2) of this section, any electrical consumption or loss resulting from the charging, holding, and discharging of storage resources located on the customer side of a retail meter is considered retail electric load for the purpose of compliance with chapter 19.405 RCW.

(7) Commission staff information requests. Nothing in this rule affects the utility's obligation to provide any additional information or data requested by commission staff.

(1) Advisory groups. The utility must demonstrate and document how it considered input from advisory group members in the development of its CEIP and biennial CEIP update. Examples of how the utility may incorporate advisory group input include: Using modeling scenarios, sensitivities, and assumptions advisory group members proposed and using data and information supplied by advisory group members as inputs to plan development. As part of this process and consistent with (i) of this subsection, the utility must communicate to advisory group members about whether and how the utility used their input in its analysis and decision-making, including explanations for why the utility did not use an advisory group member's input.

(a) The utility must involve all advisory groups in the development of its CEIP and its biennial CEIP update, including the equity advisory group identified in (b) of this subsection((;)).

(b) The utility must maintain and regularly engage an external equity advisory group to advise the utility on equity issues including, but not limited to, vulnerable population designation, equity customer benefit indicator development, data support and development, and recommended approaches for the utility's compliance with WAC 480-100-610 (4)(c)(i). The utility must encourage and include the participation of environmental justice and public health advocates, tribes, and representatives from highly impacted communities and vulnerable populations in addition to other relevant groups((;)).

(c) The utility must convene advisory groups, with reasonable advance notice, at regular meetings open to the public during the planning process. A utility must notify advisory groups of company and commission public meetings scheduled to address its CEIP and biennial CEIP update((;)).

(d) Engaging with advisory groups for the purposes of developing the CEIP does not relieve the utility of the obligation to continue to convene and engage these groups for their individual topical duties. This section does not supersede existing rules related to those groups((;)).

(e) Nothing in this section limits the utility from convening and engaging public advisory groups on other topics((;)).

(f) Participation in an advisory group does not restrict groups and individuals from commenting on CEIP filings before the commission((;)).

(g) The utility must make available completed presentation materials for each advisory group meeting at least three business days prior to the meeting. The utility may update materials as needed;

(h) The utility must make all ((of)) its data inputs and files used to develop its CEIP available to the commission in native file format and in an easily accessible format. The utility may make confidential information available by providing it to the commission pursuant to WAC 480-07-160. The utility should minimize its designation of information in the CEIP as confidential. Nonconfidential contents of the CEIP, biennial update, and supporting documentation as well as nonconfidential data inputs and files must be available for advisory group review in an easily accessible format upon request. Nothing in this subsection limits the protection of records containing commercial information under RCW 80.04.095((;)).

(i) As part of the filing of its CEIP and biennial update with the commission, the utility must provide a summary of advisory group comments received during the development of its CEIP and biennial update and the utility's responses, including whether issues raised in the comments were addressed and incorporated into the final CEIP as well as documentation of the reasons for rejecting public input. The utility must include the summary as an appendix to the final CEIP. Comments with similar content or input may be consolidated with a single utility response.

(2) Participation plan and education. The utility must involve advisory groups in developing the timing and extent of meaningful and inclusive public participation throughout the development and duration of the CEIP, including outreach and education serving vulnerable populations and highly impacted communities. On or before May 1st of each odd-numbered year, the utility must file with the commission a plan that outlines its schedule, methods, and goals for public participation and education both during the development of its CEIP and throughout the implementation of the plan. The utility must include the following in its participation plan:

(a) Timing, methods, and language considerations for seeking and considering input from:

(i) Vulnerable populations and highly impacted communities for the creation of or updates to customer benefit indicators and weighting factors for the utility's compliance with WAC 480-100-610 (4)(c)(i); and

(ii) All customers, including vulnerable populations and highly impacted communities, for the creation of, or updates to, customer benefit indicators and weighting factors for the utility's compliance with WAC 480-100-610 (4)(c)(ii) and (iii).

(b) Identification of barriers to public participation including, but not limited to, language, cultural, economic, or other factors, and strategies for reducing barriers to public participation((;)).

(d) A proposed schedule of public meetings or engagement, including advisory group meetings((;)).

(e) A proposed list of significant topics that will be discussed((;)).

(f) The date the utility will file the final CEIP with the commission((; and)).

(g) A link to a website accessible to the public and managed by the utility, to which the utility posts and makes publicly available the following information:

(i) Meeting summaries and materials for all relevant meetings, including materials for future meetings;

(ii) A current schedule of advisory group meetings and significant topics to be covered;

(iii) Information on how the public may participate in CEIP development; and

(iv) Final plans and biennial CEIP updates posted within ((thirty))30 days of final commission action.

(3) Customer notices. Within ((thirty))30 days of filing the utility's CEIP, the utility must inform customers of the filing and requirements under chapter 19.405 RCW, briefly summarize the utility's CEIP, and inform customers of how they may comment on the utility's filing. The notice must include:

(a) The date the notice is issued;

(b) The utility's name and address;

(d) A statement that the commission has the authority to approve the CEIP, with or without conditions, or reject the CEIP;

(e) A description of how customers may contact the utility if they have specific questions or need additional information about the CEIP; and

(f) Public involvement language pursuant to WAC 480-100-194 (4)(j).

(1) Incremental cost methodology. To determine the incremental cost of the actions a utility takes to comply with RCW 19.405.040 and 19.405.050, the utility must compare its lowest reasonable cost portfolio to the alternative lowest reasonable cost and reasonably available portfolio. The utility should use a portfolio optimization model, such as the one used in its most recent ((integrated resource plan))IRP, as the basis for calculating the alternative lowest reasonable cost and reasonably available portfolio to show the difference in portfolio choices and investment needs between the two portfolios, and demonstrate which investments and expenses are directly attributable costs to meet the requirements of RCW 19.405.040 and 19.405.050.

(a) The utility may include in its documentation of both portfolios those investments and expenses that are not reflected in the portfolio optimization if the utility demonstrates that the investment or expense could not reasonably have been reflected in the portfolio optimization model.

(b) If the portfolios provided are the result of a model, the utility must provide a fully linked and electronically functional copy of that model as part of its workpapers.

(c) The utility may propose an alternative incremental cost methodology if it can demonstrate that it meets the requirements of a methodology as described in RCW 19.405.060 (3) and (5), and that it will comply with RCW 19.405.040 and 19.405.050 at the lowest reasonable cost.

(2) Incremental cost calculation. The utility must calculate the average annual threshold amount for determining eligibility for reliance on RCW 19.405.060(3) as a means of compliance. The average annual threshold amount is equal to a two percent increase over the utility's weather-adjusted sales revenue to customers from each previous year, divided by the number of years in the period. For a period consisting of four years, the mathematical formula for the annual threshold amount is:

Annual Threshold Amount	=	(WASR0 × 2% × 4) + (WASR1 × 2% × 3) + (WASR2 × 2% × 2) + (WASR3 × 2%)
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(3) Directly attributable costs. An investment or expense is directly attributable only if all ((of)) the following conditions are satisfied:

(a) The utility made the investment or incurred the expense during the implementation period((;)).

(b) The investment or expense is part of the lowest reasonable cost portfolio that results in compliance with RCW 19.405.040 and 19.405.050((;)).

(c) The investment or expense is additional to the costs that the utility would incur for the alternative lowest reasonable cost and reasonably available portfolio((; and)).

(d) The investment or expense is not required to meet any statutory, regulatory, or contractual requirement or any provision of chapter 19.405 RCW other than RCW 19.405.040 or 19.405.050.

(4) Projected incremental cost. The utility must file projected incremental cost estimates in each CEIP using the methodology described in subsection (1) of this section and using projected weather-adjusted sales revenue in the calculation in subsection (2) of this section to estimate the average annual threshold amount for the implementation period. The utility must support the projections with workpapers, models, and associated calculations, and must ((provide the following information)):

(a) ((Identification of))Identify all investments and expenses that the utility plans to make during the period in order to comply with the requirements of RCW 19.405.040 and 19.405.050((;)).

(b) ((Demonstration))Demonstrate that the investments and expenses identified in (a) of this subsection are directly attributable to actions necessary to comply with, or make progress towards, the requirements of RCW 19.405.040 and 19.405.050((; and)).

(c) Provide the expected cost of the utility's planned activities and the expected cost of the alternative lowest reasonable cost and reasonably available portfolio.

(5) Reported actual incremental costs. In each CEIP compliance report as described in WAC 480-100-650, the utility must file the actual incremental costs using the methodology described in subsection (1) of this section and the calculation in subsection (2) of this section. The utility must support its filing by providing the following information:

(a) The actual costs the utility incurred during the implementation period((;)). Presentation of capital and expense accounts should be reported by Federal Energy Regulatory Commission (FERC) account by year((;)).

(b) A demonstration that the reported incremental cost is directly attributable to specific actions the utility has taken that were necessary to comply with RCW 19.405.040 and 19.405.050, per subsection (2) of this section((;)).

(c) Documentation of the cost of the alternative lowest reasonable cost and reasonably available portfolio; the utility must update verifiable and material inputs of this portfolio with the most recent information available((;)).

(d) If the utility uses the incremental cost compliance option as described in this subsection, a demonstration that during the implementation period the average annual incremental cost of meeting the standards or the interim targets equals or exceeds a two percent annual increase of the investor-owned utility's weather-adjusted electric retail sales revenue to customers for electric operations above the previous year((;)).

(e) An explanation for the variance between the projected incremental cost in subsection (3) of this section and the actual incremental costs reported in subsection (4) of this section((; and)).

(f) Workpapers and calculations supporting the incremental cost calculations.

(6) Determination of incremental cost of compliance option.

(a) For any implementation period in which the utility relies on RCW 19.405.060(3) as the basis for compliance with the standard under RCW 19.405.040(1) or 19.405.050(1), the utility must request a determination from the commission when filing its clean energy compliance report, per WAC 480-100-650.

(b) The utility must also provide evidence that, if the utility relied on alternative compliance options allowed under RCW 19.405.040 (1)(b) during the applicable period, the utility has maximized investments in renewable resources and nonemitting electric generation before relying on these alternative compliance options.

(1) General. The commission may take enforcement action in response to a utility's failure to comply with the provisions of chapter 19.405 RCW, this chapter of the commission's rules, or a commission order implementing those requirements.

(2) Procedure. The commission may take enforcement action in the following types of proceedings:

(a) Complaint. The commission may bring a complaint against the utility pursuant to RCW 80.04.380 and WAC 480-07-300, et seq.

(b) Penalty assessment. The commission may assess penalties as provided in RCW 80.04.405 and WAC 480-07-915.

(c) Other. The commission may take enforcement action in any proceeding in which the utility's compliance with the provisions of chapter 19.405 RCW, this chapter of the commission's rules, or a commission order implementing those requirements is at issue including, but not limited to, the utility's general rate case.

(3) Remedies. The commission may impose any one or a combination of the following remedies for a utility's failure to comply with the provisions of chapter 19.405 RCW, this chapter of the commission's rules, or a commission order implementing those requirements.

(a) RCW 19.405.090. For all violations subject to the compliance, enforcement, and penalty provisions of RCW 19.405.090, the commission may require the utility to pay an administrative penalty of ((one hundred dollars))$100 multiplied by the applicable megawatt-hour of electric generation used to meet load that is not electricity from a renewable resource or nonemitting electric generation.

(b) For violations of rule or order not subject to RCW 19.405.090, the commission may pursue the following remedies:

(i) RCW 80.04.380. The commission may assess penalties of up to ((one thousand dollars))$1,000 for each violation. Violation of the same requirement in statute, rule, or commission order are separate and distinct violations, and each day the utility is not in compliance with these requirements is a separate and distinct violation.

(ii) RCW 80.04.405. The commission may assess penalties of ((one hundred dollars))$100 for each violation. Violation of the same requirement in statute, rule, or commission order are separate and distinct violations, and each day the utility is not in compliance with these requirements is a separate and distinct violation.

(c) Specific performance. The commission may order a utility to take specific actions necessary to comply with chapter 19.405 RCW, this chapter of the commission's rules, and commission orders implementing those requirements.

(d) Customer notification. If the commission finds a utility in violation of chapter 19.405 RCW, this chapter of the commission's rules, or commission orders implementing those requirements, the commission may order the utility to notify its retail electric customers of the violation in a published form.

(4) Mitigation. A utility may request mitigation of, and the commission may mitigate, any administrative penalty as described in RCW 19.405.090(3) or penalty assessment as provided in WAC 480-07-915. Any mitigation the commission grants does not relieve the utility of its obligation to comply with applicable legal requirements or to take specific actions the commission orders.