UTILITIES AND TRANSPORTATION

COMMISSION

(c) Upon conclusion of the commission review, the commission will determine whether to approve, approve with conditions, or reject the utility's ten-year achievable conservation potential and biennial conservation target.)) The purpose of this chapter is to establish rules that electric utilities will use to comply with the requirements of the Energy Independence Act, chapter 19.285 RCW.

(4) A renewable resource within the Pacific Northwest may receive integration, shaping, storage or other services from sources outside of the Pacific Northwest and remain eligible to count towards a utility's renewable resource target.)) (1) The rules in this chapter apply to any electric utility that is subject to the commission's jurisdiction under RCW 80.04.010 and chapter 80.28 RCW.

(c) It invested at least one percent of its total annual retail revenue requirement that year on eligible renewable resources, renewable energy credits, or a combination of both.)) The commission may grant an exemption from the provisions of any rule in this chapter in the same manner and consistent with the standards and according to the procedures set forth in WAC 480-07-110 (Exemptions from and modifications to commission rules; conflicts involving rules).

(5) Each utility must provide a summary of this report to its customers by bill insert or other suitable method. This summary must be provided within ninety days of final action by the commission on this report.)) (1) These rules do not relieve any utility from any of its duties and obligations under the laws of the state of Washington.

(4) A utility may request an accounting order from the commission authorizing the deferral of the cost of any administrative penalty assessed under this section. The approval of an accounting order to defer penalties does not constitute approval of recovery of penalties in rates. A utility may seek to recover deferred administrative penalties in a general rate case or power cost only type rate proceeding. If a utility seeks to recover deferred administrative penalties in rates, the utility must demonstrate the prudence of its decisions and actions when it failed to meet the renewable resource targets or one of the compliance alternatives provided in WAC 480-109-030, or the energy conservation targets. When assessing a request for recovery of deferred administrative penalties, the commission will consider the intent of the Energy Independence Act, other laws governing commission actions, policies and precedents of the commission, and the commission's responsibility to act in the public interest.)) If any provision of this chapter or its application to any person or circumstance is held invalid, the remainder of the chapter or the application of the provision to other persons or circumstances is not affected.

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

(1) "Annual retail revenue requirement" means the total revenue the commission authorizes a utility an opportunity to recover in Washington rates pursuant to a general rate proceeding or other general rate revision.

(2) "Biomass energy" means:

(a) The electrical energy produced by a generation facility powered by:

(i) Organic by-products of pulping and the wood manufacturing process;

(ii) Animal manure;

(iii) Solid organic fuels from wood;

(iv) Forest or field residues;

(v) Untreated wooden demolition or construction debris;

(vi) Food waste and food processing residuals;

(vii) Liquors derived from algae;

(viii) Dedicated energy crops; and

(ix) Yard waste.

(b) Biomass energy does not include:

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

(ii) Wood from old growth forests; or

(iii) Municipal solid waste.

(3) "Coal transition power" means the output of a coal-fired electric generation facility that is subject to an obligation to meet the standards contained in RCW 80.80.040 (3)(c).

(4) "Commission" means the Washington utilities and transportation commission.

(5) "Conservation" means any reduction in electric power consumption resulting from increases in the efficiency of energy use, production, or distribution.

(6) "Cost-effective" means, consistent with RCW 80.52.030, 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.

(7) "Council" means the Northwest Power and Conservation Council.

(8) "Customer" means a person or entity that purchases electricity for ultimate consumption and not for resale.

(9) "Department" means the department of commerce or its successor.

(10) "Distributed generation" means an eligible renewable resource where the generation facility or any integrated cluster of such facilities has a nameplate capacity of not more than five megawatts alternating current. An integrated cluster is a grouping of generating facilities located on the same or contiguous property having any of the following elements in common: Ownership, operational control, or point of common coupling.

(11) "Eligible renewable resource" means:

(a) Electricity from a generation facility powered by a renewable resource other than fresh water that commences operation after March 31, 1999, where:

(i) The facility is located in the Pacific Northwest; or

(ii) The electricity from the facility is delivered into Washington state on a real-time basis without shaping, storage, or integration services.

(b) Incremental electricity produced as a result of efficiency improvements completed after March 31, 1999, to hydroelectric generation projects owned by a qualifying utility and located in the Pacific Northwest, where the additional generation does not result in new water diversions or impoundments;

(c) Hydroelectric generation from a project completed after March 31, 1999, where the generation facility is located in irrigation pipes, irrigation canals, water pipes whose primary purpose is for conveyance of water for municipal use, and wastewater pipes located in Washington, where the generation does not result in new water diversion or impoundments;

(d) Qualified biomass energy; or

(e) For a qualifying utility that serves customers in other states, electricity from a generation facility powered by a renewable resource other than freshwater that commenced operation after March 31, 1999, where:

(i) The facility is located within a state in which the qualifying utility serves retail electrical customers; and

(ii) The qualifying utility owns the facility in whole or in part or has a long-term contract with the facility of at least twelve months.

(12) "High-efficiency cogeneration" means the sequential production of electricity and useful thermal energy from a common fuel source resulting in a reduction in customer load where under normal operating conditions the useful thermal energy output is no less than thirty-three percent of the total energy output. The reduction in customer load is determined by multiplying the annual electricity output of the cogeneration facility by a fraction equal to one minus the ratio of:

(a) The heat rate (in British thermal units per megawatt hour) of the cogeneration facility. The heat rate of the cogeneration facility must be based on the additional fuel requirements attributable to electricity production and excluding the fuel that would be required to produce all other useful energy outputs of the project without cogeneration, divided by the heat rate (in British thermal units per megawatt hour) of a combined cycle natural gas-fired combustion turbine. The heat rate of the combustion turbine must be based on a facility using best commercially available technology on a new and clean basis.

(b) Calculation of the reduction in customer load is made with the following formula:

(13) "Incremental cost" means the difference between the levelized delivered cost of an eligible renewable resource, regardless of ownership, compared to the levelized delivered cost of an equivalent amount of reasonably available substitute resources that do not qualify as eligible renewable resources, where the resources being compared have the same contract length or facility life.

(14) "Integrated resource plan" or "IRP" means the filing made every two years by an electric utility in accordance with WAC 480-100-238, integrated resource planning.

(15) "Load" means the amount of kilowatt-hours of electricity delivered in the most recently completed year by a qualifying utility to its Washington retail customers. Load does not include off-system sales or electricity delivered to transmission-only customers.

(16)(a) "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 from a renewable resource including, but not limited to, the facility's fuel type, geographic location, vintage, qualification as an eligible renewable resource, and avoided emissions of pollutants to the air, soil, or water, and avoided emissions of carbon dioxide and other greenhouse gases.

(b) "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.

(17) "Pacific Northwest" has the same meaning as defined for the Bonneville Power Administration in section 3 of the Pacific Northwest Electric Power Planning and Conservation Act (94 Stat. 2698; 16 U.S.C. Sec. 839a).

(18) "Pro rata" means the calculation dividing the utility's projected ten-year conservation potential into five equal proportions to establish the minimum biennial conservation target.

(19) "Production efficiency" means investments and actions that save electric energy from power consuming equipment and fixtures at an electric generating facility. The installation of electric power production equipment that increases the amount of power generated for the same energy input is not production efficiency in this chapter or conservation under RCW 19.285.030(4) because no reduction in electric power consumption occurs.

(20) "Pursue all" means an ongoing process of researching and evaluating the range of possible conservation technologies and programs, and implementing all programs which are cost-effective, reliable and feasible.

(21) "Qualified biomass energy" means electricity produced from a biomass energy facility that:

(a) Commenced operation before March 31, 1999;

(b) Contributes to the qualifying utility's load; and

(c) Is owned either by:

(i) A qualifying utility; or

(ii) An industrial facility that is directly interconnected with electricity facilities that are owned by a qualifying utility and capable of carrying electricity at transmission voltage.

(22) "Regional technical forum" means the advisory committee established by the council.

(23) "Renewable energy credit" means a tradable certificate of proof of at least one megawatt-hour of an eligible renewable resource where the generation facility is not powered by fresh water, 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.

(24) "Renewable resource" means:

(a) Water;

(b) Wind;

(c) Solar energy;

(d) Geothermal energy;

(e) Landfill gas;

(f) Wave, ocean, or tidal power;

(g) Gas from sewage treatment facilities;

(h) Biodiesel fuel as defined in RCW 82.29A.135 that is not derived from crops raised on land cleared from old growth or first-growth forests where the clearing occurred after December 7, 2006;

(i) Generation facilities in which fossil and combustible renewable resources are cofired in one generating unit that is located in the Pacific Northwest and in which the cofiring commenced after March 31, 1999. These facilities produce eligible renewable resources in direct proportion to the percentage of the total heat value represented by the heat value of the renewable resources; or

(j) Biomass energy, where the eligible renewable energy produced by biomass facilities is based on the portion of the fuel supply that is made up of eligible biomass fuels.

(25) "Request for proposal" or "RFP" means the documents describing an electric utility's solicitation of bids for delivering electric capacity, energy, capacity and energy, or conservation.

(26) "River discharge" means the total volume of water passing through, over and around all structural components of a hydroelectric facility over a given time.

(27) "Single large facility conservation savings" means cost-effective conservation savings achieved in a single biennial period at the premises of a single customer of a utility whose recent annual electricity consumption prior to the conservation savings exceeded five average megawatts.

(28) "System cost" means, consistent with RCW 80.52.030, an estimate of all direct costs of a project or resource over its effective life including, if applicable, the costs of distribution to the consumer and among other factors, waste disposal costs, end-of-cycle costs, and fuel costs (including projected increases), and such quantifiable environmental costs and benefits as are directly attributable to the project or resource.

(29) "Target year" means the twelve-month period commencing January 1st and ending December 31st used for compliance with the renewable portfolio standard requirement in WAC 480-109-200(1).

(30) "Transmission voltage" means an electric line normally operated at or above 100,000 volts.

(31) "Utility" means an electrical company that is subject to the commission's jurisdiction under RCW 80.04.010 and chapter 80.28 RCW.

(32) "WREGIS" means the Western Renewable Energy Generation Information System. WREGIS is the renewable energy credit tracking system designated by the department according to RCW 19.285.030(20).

(33) "Year" means the twelve-month period commencing January 1st and ending December 31st.

(1) A utility that fails to achieve either its conservation target or its renewable resource target must pay an administrative penalty for each megawatt-hour of shortfall in the amount of fifty dollars adjusted annually, beginning in 2007, to reflect changes in the gross domestic product-implicit price deflator, as published by the Bureau of Economic Analysis of the United States Department of Commerce or its successor.

(2) Administrative penalties are due within fifteen days of a commission determination, pursuant to WAC 480-109-210(2), that a utility failed to achieve its conservation or renewable resource target.

(3) A utility that pays an administrative penalty under subsection (2) of this section, must notify its retail electric customers within three months of incurring a penalty stating the size of the penalty, the reason it was incurred and whether the utility expects to seek recovery of the penalty amounts in rates. The utility must provide this notification in a bill insert, a written publication mailed to all retail electricity customers, or another approach approved by the commission.

(4) A utility may request an accounting order from the commission authorizing the deferral of the cost of any administrative penalty assessed under this section. The approval of an accounting order to defer penalties does not constitute approval of recovery of penalties in rates. A utility may seek to recover deferred administrative penalties in a general rate case or power cost only type rate proceeding. If a utility seeks to recover deferred administrative penalties in rates, the utility must demonstrate the prudence of its decisions and actions when it failed to meet the renewable resource targets or one of the compliance alternatives provided in WAC 480-109-220, or the energy conservation targets. When assessing a request for recovery of deferred administrative penalties, the commission will consider the intent of the Energy Independence Act, other laws governing commission actions, policies and precedents of the commission, and the commission's responsibility to act in the public interest.

(1) Process for pursuing all conservation.

(a) A utility's obligation to pursue all available conservation that is cost-effective, reliable, and feasible includes the following process:

(i) Identify potential. Identify the cost-effective, reliable, and feasible potential of possible technologies and conservation programs and measures in the utility's service territory.

(ii) Develop portfolio. Develop a conservation portfolio that includes all available, cost-effective, reliable, and feasible potential. A utility must develop programs to acquire available conservation from all of the types of conservation identified in subsection (b) of this section. If no cost-effective, reliable and feasible conservation is available from one of the types of conservation, a utility is not obligated to acquire such a resource.

(iii) Implement programs. Implement conservation programs identified in the portfolio to the extent the portfolio remains cost-effective, reliable, and feasible. Implementation methods shall not unnecessarily limit the acquisition of all available conservation that is cost-effective, reliable and feasible.

(iv) Adaptively manage. Continuously review and update as appropriate the conservation portfolio to adapt to changing market conditions and developing technologies. A utility must research emerging conservation technologies, and assess the potential of such technologies for implementation in its service territory.

(b) Types of conservation include, but are not limited to:

(i) End-use efficiency;

(ii) Behavioral programs;

(iii) High-efficiency cogeneration;

(iv) Production efficiency;

(v) Distribution efficiency; and

(vi) Market transformation.

(c) Pilots. A utility must implement pilot projects when appropriate and expected to produce cost-effective savings, as long as the overall portfolio remains cost-effective.

(2) Conservation potential. By January 1, 2010, and every two years thereafter, a utility must project its cumulative ten-year conservation potential.

(a) This projection must consider all conservation resources that are cost-effective, reliable, and feasible.

(b) This projection must be derived from the utility's most recent IRP, including any information learned in its subsequent resource acquisition process, or the utility must document the reasons for any differences. When developing this projection, utilities must use methodologies that are consistent with those used in the Northwest Conservation and Electric Power Plan.

(c) The projection must include a list of each measure used in the potential, its unit energy savings value, and the source of that value.

(3) Biennial conservation target. Beginning January 2010, and every two years thereafter, a utility must establish a biennial conservation target.

(a) The biennial conservation target must identify, and quantify in megawatt-hours, all achievable conservation opportunities.

(b) The biennial conservation target must be no lower than a pro rata share of the utility's ten-year cumulative achievable conservation potential.

(c) Excess conservation. No more than twenty-five percent of any biennial target may be met with excess conservation savings allowed by this subsection. Excess conservation may only be used to mitigate shortfalls in future biennium and may not be used to adjust a utility's ten-year conservation potential or biennial target. The presence of excess conservation does not relieve a utility of its obligation to pursue the level of conservation in its biennial target.

(i) Cost-effective conservation achieved in excess of the biennial conservation target may be used to meet up to twenty percent of each of the subsequent two biennial targets.

(ii) A utility may use single large facility conservation savings in excess of its biennial target to meet up to five percent of each of the immediate two subsequent biennial conservation targets.

(iii) Until December 31, 2017, a utility with an industrial facility located in a county with a population between ninety-five thousand and one hundred fifteen thousand that is directly interconnected with electricity facilities that are capable of carrying electricity at transmission voltage, may use cost-effective excess conservation savings from that industrial facility to meet the subsequent two biennial conservation targets.

(4) Prudence. A utility retains the responsibility to demonstrate the prudence of all conservation expenditures, as required by RCW 19.285.050(2).

(5) Energy savings. A utility must use unit energy savings values and protocols approved by the regional technical forum or by commission order. The commission will consider a unit energy savings value or protocol that is:

(a) Based on generally accepted impact evaluation data or other reliable and relevant data that includes verified savings levels; and

(b) Presented to its advisory group for review. The commission retains discretion to determine an appropriate value or protocol.

(6) High efficiency cogeneration. A utility may count as conservation savings a portion of the electricity output of a high efficiency cogeneration facility in its service territory that is owned by a retail electric customer and used by that customer to meet its heat and electricity needs. Heat and electricity output provided to anyone other than the facility owner is not available for consideration in determining conservation savings. High efficiency cogeneration savings must be certified by a professional engineer licensed by the Washington department of licensing.

(7) Applicable sectors. A utility must offer a mix of conservation programs to ensure it is serving each customer sector, including programs targeted to the low-income subset of residential customers.

(8) Cost-effectiveness evaluation.

(a) Portfolio. A utility's conservation portfolio must pass a cost-effectiveness test consistent with that used in the Northwest Conservation and Electric Power Plan. A utility must evaluate conservation using cost-effectiveness tests consistent with those used by the council, and as required by the commission, except low-income conservation programs.

(b) Low-income programs.

(i) A utility must evaluate low-income conservation programs for cost-effectiveness using the savings-to-investment ratio, as described in the Weatherization Manual For Managing the Low-Income Weatherization Program. A utility may also evaluate low-income conservation programs using a cost-effectiveness test consistent with that used by the council.

(ii) A utility may exclude low-income conservation programs from portfolio-level cost-effectiveness calculations. However, a utility must count savings from such programs toward meeting its target.

(iii) A utility must require the implementing agency of a low-income conservation program to evaluate each residence with the savings-to-investment ratio, as described in the Weatherization Manual For Managing the Low-Income Weatherization Program.

(9) Incentives. A utility may propose to the commission positive incentives designed to stimulate the utility to exceed its biennial conservation target as identified in RCW 19.285.060(4). Any proposed incentive must be included in the utility's biennial conservation plan.

(1) Scope of issues. A utility must maintain and use an external conservation advisory group of stakeholders to advise the utility on conservation issues including, but not limited to:

(a) Updates to the utility's evaluation, measurement, and verification framework.

(b) Modification of existing, or development of new evaluation, measurement, and verification methods.

(c) Independent third-party evaluation of portfolio-level biennial conservation achievement.

(d) Development of conservation potential assessments, as required by RCW 19.285.040 (1)(a) and WAC 480-109-100(2).

(e) The methodology, inputs, and calculations for cost-effectiveness.

(f) The data sources and values used to develop and update supply curves.

(g) The need for tariff modifications or mid-biennium program corrections.

(h) The appropriate level of and planning for:

(i) Marketing conservation programs;

(ii) Incentives to customers for measures and services; and

(iii) Impact, market, and process evaluations.

(i) Programs for low-income residential customers.

(j) Establishment of the biennial conservation target and program achievement results compared to the target.

(k) Conservation program budgets and actual expenditures compared to budgets.

(2) Advisory group meetings. A utility must meet with its conservation advisory group at least four times per year. Conservation advisory group members may request additional meetings. A utility must provide reasonable advance notice of all conservation advisory group meetings.

(3) Advance notification of filings. A utility must provide its conservation advisory group an electronic copy of all conservation filings that the utility intends to submit to the commission at least thirty days in advance of the filing. The filing cover letter must document the amount of advance notice provided to the conservation advisory group.

(4) Advance notification of meetings. A utility must notify its conservation advisory group of public meetings scheduled to address its conservation programs, its conservation tariffs, or the development of its conservation potential assessment.

(1) Biennial conservation plan.

(a) On or before November 1st of every odd-numbered year, a utility must file with the commission a biennial conservation plan.

(b) The plan must include, but is not limited to:

(i) A request that the commission approve its ten-year achievable conservation potential and biennial conservation target.

(ii) The extent of public participation in the development of the ten-year conservation potential and the biennial conservation target.

(iii) The ten-year conservation potential, the biennial conservation target, biennial program details, biennial program budgets, and cost-effectiveness calculations.

(iv) A description of the technologies, data collection, processes, procedures and assumptions the utility used to develop the figures in (b)(iii) of this subsection.

(v) A description of and support for any changes from the assumptions or methodologies used in the utility's most recent conservation potential assessment.

(vi) An evaluation, measurement, and verification plan for the biennium including, but not limited to:

(A) The evaluation, measurement, and verification framework;

(B) The evaluation, measurement, and verification budget; and

(C) Identification of programs that will be evaluated during the biennium.

(2) Annual conservation plan. On or before November 15th of each even-numbered year, a utility must file with the commission, in the same docket as its current biennial conservation plan, an annual conservation plan containing any changes to program details and annual budget.

(3) Annual conservation report.

(a) On or before June 1st of each year, a utility must file with the commission, in the same docket as its current biennial conservation plan, an annual conservation report regarding its progress in meeting its conservation target during the preceding year.

(b) The annual conservation report must include, but is not limited to:

(i) The biennial conservation target.

(ii) Planned and claimed electricity savings from conservation, including a description of the source of any variance between the planned and actual savings.

(iii) Budgeted and actual expenditures made to acquire conservation through the conservation recovery adjustment clause described in WAC 480-109-130.

(iv) An evaluation of portfolio- and program-level cost-effectiveness of the actual conservation savings.

(v) All program evaluations completed in the preceding year.

(vi) A discussion of the steps taken to adaptively manage conservation programs throughout the preceding year.

(c) A utility must file a conservation report with the department as described in WAC 194-37-060, and file a copy of that report with the commission in the same docket as its current biennial conservation plan.

(4) Biennial conservation report.

(a) On or before June 1st of each even-numbered year, a utility must file with the commission, in the same docket as its current biennial conservation plan, a biennial conservation report regarding its progress in meeting its conservation target during the preceding two years.

(b) The biennial conservation report must include:

(i) The biennial conservation target;

(ii) Planned and claimed electricity savings from conservation;

(iii) Budgeted and actual expenditures made to acquire conservation;

(iv) The portfolio-level cost-effectiveness of the actual electricity savings from conservation;

(v) An independent third-party evaluation of portfolio-level biennial conservation savings achievement;

(vi) A summary of the steps taken to adaptively manage conservation programs throughout the preceding two years; and

(vii) Any other information needed to justify the conservation savings achievement.

(c) A utility must provide a summary of the biennial conservation report to its customers by bill insert or other suitable method within ninety days of the commission's final action on the report.

(d) A utility may file the annual conservation report and the biennial conservation report together as one report, provided that the report includes all of the information required in subsections (3) and (4) of this section and states that it serves as both the annual conservation report and the biennial conservation report.

(5) Plan and report review.

(a) Interested persons may file written comments regarding the biennial conservation plan and biennial conservation report within thirty days of the utility's filing.

(b) Upon conclusion of the commission review of the utility's biennial report or plan, the commission will issue a decision accepting or rejecting the calculation of the utility's conservation target; or determining whether the utility has acquired enough conservation resources to comply with its conservation target. If the utility does not meet its biennial conservation target described in WAC 480-109-100, the commission will determine the amount in megawatt-hours by which the utility was deficient.

(c) If a utility revises its annual or biennial conservation report as a result of the commission review, the utility must submit the revised final report to the department.

(d) Annual plans and reports may be reviewed through the commission's open meeting process, as described in chapter 480-07 WAC.

(6) Publication of reports. All current and historical plans and reports required in this section must be posted and maintained on the utility's web site and a copy of any report must be provided to any person upon request.

(1) Utilities must file with the commission for recovery of expected conservation cost changes and amortization of deferred balances. A utility must include its conservation recovery procedures in its tariff.

(2) A utility must make a conservation recovery filing no later than June 1st of each year, with a requested effective date at least sixty days after the filing. If the utility believes that a filing is unnecessary, then it must file a request for exception and supporting documents no later than May 1st of each year demonstrating why a rate change is not necessary.

(3) A utility may not accrue interest or incur carrying charges on deferred conservation cost balances. Utilities must base conservation recovery rates on budgeted conservation measure costs for the future year with revisions to recover only actual measure costs of the prior year. Utilities must also include the effects of variations in actual sales on the recovery of conservation costs in the prior year.

(1) Annual target. Each utility must meet the following annual targets.

(a) By January 1st of each year beginning in 2012 and continuing through 2015, each utility must use sufficient eligible renewable resources, acquire equivalent renewable energy credits, or a combination of both, to supply at least three percent of its two-year average load for the remainder of each target year.

(b) By January 1st of each year beginning in 2016 and continuing through 2019, each utility must use sufficient eligible renewable resources, acquire equivalent renewable energy credits, or a combination of both, to supply at least nine percent of its two-year average load for the remainder of each target year.

(c) By January 1st of each year beginning in 2020 and continuing each year thereafter, each utility must use sufficient eligible renewable resources, acquire equivalent renewable energy credits, or a combination of both, to supply at least fifteen percent of its two-year average load for the remainder of each target year.

(2) Renewable energy credits produced during the target year, the preceding year or the subsequent year may be used to comply with this annual renewable resource requirement provided that they were acquired by January 1st of the target year.

(3) All eligible renewable resource generation and all renewable energy credits used for utility compliance with the renewable energy standards must be registered in WREGIS, regardless of facility ownership.

(4) Renewable energy credit multipliers. The multipliers described in this subsection do not create additional renewable energy credits. A utility may count renewable energy resources and credits at:

(a) One and two-tenths times the base value where the eligible resource:

(i) Commenced operation after December 31, 2005; and

(ii) The developer of the facility used apprenticeship programs approved by the Washington state apprenticeship and training council.

(b) Two times the base value where the eligible resource was generated by distributed generation and:

(i) The utility owns the distributed generation facility or has purchased the energy output and the associated renewable energy credits; or

(ii) The utility has contracted to purchase the associated renewable energy credits.

(c) A utility that uses a multiplier described in this subsection for compliance must retire the associated base value renewable energy credit at the same time. A utility may not transact the multipliers described in this subsection independent of the associated base value renewable energy credit.

(5) In meeting the annual targets of this section, a utility must calculate its annual target based on the average of the utility's load for the previous two years.

(6) A renewable resource within the Pacific Northwest may receive integration, shaping, storage or other services from sources outside of the Pacific Northwest and remain eligible to count towards a utility's renewable resource target.

(7) Incremental hydropower calculation. A utility must use one of the following methods to calculate the quantity of incremental electricity produced by eligible efficiency upgrades to any hydropower facility, regardless of ownership, that is used to meet the annual targets of this section.

(a) Method one. An annual calculation performed by:

(i) Determining the river discharge for the facility in the target year;

(ii) Measuring the total amount of electricity produced by the upgraded hydropower facility during the target year;

(iii) Using a power curve-based production model to calculate how much energy the pre-upgrade facility would have generated under the same river discharge observed in the target year; and

(iv) Subtracting the model output in (a)(iii) of this subsection from the measurement in (a)(ii) of this subsection to determine the quantity of eligible renewable energy produced by the facility during the target year.

(b) Method two. An annual application of a percentage to total production performed by:

(i) Determining the river discharge for the facility over a historical period of at least five consecutive years;

(ii) Using power curve-based production models to calculate the facility's generation under the river discharge of each year in the historical period for the pre-upgrade state and the post-upgrade state;

(iii) Calculating the arithmetic mean of generation in both the pre-upgrade and post-upgrade states over the historical period;

(iv) Calculate a factor by dividing the arithmetic mean post-upgrade generation by the arithmetic mean pre-upgrade generation and subtracting one; and

(v) Multiply the facility's observed generation in the target year by the factor calculated in (b)(iv) of this subsection to determine the share of the facility's observed generation that may be reported as eligible renewable energy.

(c) Method three. A utility may only use method three to demonstrate compliance for a target year after 2017 by commission order. Method three is a one-time calculation of the quantity of renewable energy performed by:

(i) Determining the river discharge for the facility over a historical period of at least ten consecutive years;

(ii) Using a production model to calculate the facility's generation in megawatt-hours under the river discharge of each year in the historical period for the pre-upgrade state and the post-upgrade state;

(iii) Calculating the arithmetic mean generation of the pre-upgrade and post-upgrade states over the historical period in megawatt hours;

(iv) Subtracting the arithmetic mean pre-upgrade generation from the arithmetic mean post-upgrade generation to determine the amount of eligible renewable generation for the target year; and

(v) In the utility's 2017 renewable portfolio standard report, providing an analysis comparing the amount of incremental hydropower the utility reported in the five previous years using method three to the amount of incremental hydropower the utility would have reported over the same period using one of the other two methods.

(8) Qualified biomass energy. Beginning January 1, 2016, only a utility that owns or is directly interconnected to a qualified biomass energy facility may use qualified biomass energy to meet its annual target obligation.

(a) A utility may no longer use electricity and associated renewable energy credits from a qualified biomass energy facility if the associated industrial pulping or wood manufacturing facility ceases operation other than for purposes of maintenance or upgrade.

(b) A utility may acquire renewable energy credits from a qualified biomass energy resource hosted by an industrial facility only if the facility is directly interconnected to the utility at transmission voltage. The number of renewable energy credits that the utility may acquire from an industrial facility for the utility's target compliance may not be greater than the utility's renewable portfolio standard percentage times the industrial facility load.

(c) A utility that owns a qualified biomass energy facility may not transfer or sell renewable energy credits associated with qualified biomass energy to another person, entity, or utility.

(1) Annual report. On or before every June 1st, each utility must file an annual renewable portfolio standard report with the commission and the department detailing the resources the utility has acquired or contracted to acquire to meet its renewable resource obligation for the target year.

(2) Annual report contents. The annual renewable portfolio standard report must include the utility's annual load for the prior two years, the total number of megawatt-hours from eligible renewable resources and/or renewable resource credits the utility needed to meet its annual renewable energy target by January 1st of the target year, the amount (in megawatt-hours) of each type of eligible renewable resource used, and the amount of renewable energy credits acquired. Additionally, the annual renewable portfolio standard report must include the following:

(a) Incremental cost calculation. To calculate its incremental cost, a utility must:

(i) Make a one-time calculation of incremental cost for eligible resources at time of acquisition:

(A) Eligible resource levelized cost. Determine the levelized cost of each eligible resource, including integration costs, using the utility's commission-approved weighted average cost of capital at the time of the resource's acquisition as the discount rate;

(B) Capacity. Calculate the capacity credit for each eligible resource by modeling the eligible resource's output, in megawatts, at the time of the utility's annual system peak;

(C) Noneligible resource selection. Select and document the lowest-reasonable-cost, noneligible resource available to the utility at the time of the eligible resource's acquisition for each corresponding eligible resource;

(D) Noneligible levelized energy cost. For each noneligible resource selected in (a)(i)(C) of this subsection, determine the cost of acquiring the same amount of energy as expected to be produced by the eligible resource, levelized over a time period equal to the facility life of the eligible resource and at the same discount rate used in (a)(i)(A) of this subsection;

(E) Noneligible levelized capacity cost. Calculate the levelized capital cost of obtaining an equivalent amount of capacity provided by the eligible resource, as determined in (a)(i)(B) of this subsection, from a noneligible resource. This cost must be levelized over a period equal to the facility life of the eligible resource and at the same discount rate used in (a)(i)(A) of this subsection. To make this calculation, a utility must use the lowest-cost, noneligible capacity resource identified in its most recent integrated resource plan acknowledged by the commission.

(F) Incremental cost calculation. Determine the incremental cost of each eligible resource by subtracting the sum of the levelized costs of the noneligible resources calculated in (a)(i)(D) and (E) of this subsection from the levelized cost of the eligible resource determined in (a)(i)(A) of this subsection.

(ii) Annual calculation of revenue requirement ratio. To calculate its revenue requirement ratio, a utility must annually:

(A) Sum the incremental costs of all eligible resources used for target year compliance;

(B) Add the cost of any unbundled renewable energy credits purchased for target year compliance;

(C) Subtract the revenue from the sales of any renewable energy credits and energy from eligible facilities; and

(D) Divide the total obtained in (a)(ii)(A) through (C) of this subsection by the utility's annual revenue requirement, which means the revenue requirement that the commission established in the utility's most recent rate case, and multiply by one hundred.

(iii) Annual reporting. In addition to the revenue requirement ratio calculated in (a)(ii) of this subsection, the utility must:

(A) Report its total incremental cost as a dollar amount and in dollars per megawatt-hour of renewable energy generated by all eligible renewable resources in the calculation in (a)(i) of this subsection; and

(B) Multiply the dollars per megawatt-hour cost calculated in (a)(iii)(A) of this subsection by the number of megawatt-hours needed for target year compliance.

(b) Alternative compliance. State whether the utility is relying upon one of the alternative compliance mechanisms provided in WAC 480-109-220 instead of fully meeting its renewable resource target. A utility using an alternative compliance mechanism must use the incremental cost methodology described in this section and include sufficient data, documentation and other information in its report to demonstrate that it qualifies to use that alternative mechanism.

(c) Compliance plan. Describe the resources that the utility intends to use to meet the renewable resource requirements for the target year.

(d) Eligible resources. A list of each eligible renewable resource that serves Washington customers, for which a utility owns the renewable energy credits or qualifying hydroelectric generation, with an installed capacity greater than twenty-five kilowatts. Resources with an installed capacity of less than twenty-five kilowatts may be reported in terms of aggregate capacity. The list must include:

(i) Each resource's WREGIS registration status and use of renewable energy certificates, whether it be for annual target compliance, a voluntary renewable energy program as provided for in RCW 19.29A.090, or owned by the customer; and

(ii) Eligible resources being included in the report for the first time and documentation of their eligibility.

(e) Multistate allocations.

(i) If a utility serves retail customers in more than one state, the utility must allocate renewable energy credits and qualifying hydroelectric generation consistent with the utility's most recent commission-approved interstate cost allocation methodology. The report must show how the utility applied the allocation methodology to arrive at the amount of renewable energy credits and qualifying hydroelectric generation allocated to Washington ratepayers.

(ii) After documenting the amount of renewable energy credits and qualifying hydroelectric generation allocated to Washington ratepayers, a utility may transfer renewable energy credits or qualifying hydroelectric generation to or from Washington ratepayers. The report must document the compensation provided to each jurisdiction's ratepayers for such transfers.

(f) Sales. If a utility sold renewable energy credits, report the number of credits that it sold, their WREGIS certificate numbers, their source, and the revenues obtained from the sales. If a utility sold eligible hydroelectricity, report the number of megawatt-hours sold, their source, and the revenues obtained from the sales.

(3) Report review.

(a) Interested persons may file written comments regarding a utility's annual renewable portfolio standard report within thirty days of the utility's filing.

(b) Upon conclusion of the commission review of the utility's annual renewable portfolio standard report, the commission will issue a decision accepting or rejecting the calculation of the utility's renewable resource target; determining whether the utility has generated, acquired or arranged to acquire enough renewable energy credits or qualifying generation to comply with its renewable resource target; and determining the eligibility of new renewable resources pursuant to subsection (2)(d) of this section.

(c) If a utility revises its annual renewable portfolio standard report as a result of the commission review, the utility must submit the revised final annual renewable portfolio standard report to the department.

(4) Publication of reports. All current and historical renewable portfolio standard reports required in this section must be posted and maintained on the utility's web site and a copy of any report must be provided to any person upon request.

(5) Customer notification. Each utility must provide a summary of its annual renewable portfolio standard report to its customers by bill insert or other suitable method. This summary must be provided within ninety days of final action by the commission on the report.

(6) Final compliance report. Within two years following submission of its annual renewable portfolio standard report, a utility must submit, in the same docket, a final renewable portfolio standard compliance report that lists the renewable energy credits that it retired in WREGIS for the target year. If a utility does not meet its annual target described in WAC 480-109-200, the commission will determine the amount in megawatt-hours by which the utility was deficient.

Instead of fully meeting its annual renewable resource target in WAC 480-109-200, a utility may make one of three demonstrations.

(1) A utility may invest at least four percent of its total annual retail revenue requirement on the incremental costs of eligible renewable resources, renewable energy credits, or a combination of both.

(2) A utility may demonstrate that events beyond its reasonable control that could not have been reasonably anticipated or ameliorated prevented it from meeting the renewable energy target. Such events may include weather-related damage, mechanical failure, strikes, lockouts, or actions of a governmental authority that adversely affect the generation, transmission, or distribution of an eligible renewable resource owned by or under contract to a qualifying utility.

(3) A utility may demonstrate all of the following:

(a) Its weather-adjusted load for the previous three years prior to the target year on average did not increase.

(b) After December 7, 2006, all new or renewed ownership or purchases of electricity from nonrenewable resources other than coal transition power and daily spot purchases were offset by equivalent renewable energy credits.

(c) It invested at least one percent of its total annual retail revenue requirement that year on eligible renewable resources, renewable energy credits, or a combination of both.

(1) A utility must report metrics of energy and emissions intensity to the commission on or before June 1st of each year. The report must include annual values for each metric for the preceding ten calendar years. Each value reported must be based on the annual energy or emissions from all generating resources providing service to customers in Washington state, regardless of the location of the generating resources. When the metrics are calculated from generators that serve out-of-state and in-state customers, the annual energy and emissions outputs must be prorated to represent the proportion of the resource used by Washington customers.

(2) The energy and emissions intensity report shall include the following metrics:

(a) MWh per residential customer;

(b) MWh per commercial customer;

(c) MWh per capita;

(d) Million tons of CO2 emissions; and

(e) Comparison of annual million tons of CO2 emissions to 1990 emissions.

(3) Unknown generation sources. For resources where the utility purchases energy from unknown generation sources, often called "spot market" purchases, from which the emission rates are unknown, the utility shall report emission metrics using the average electric power CO2 emissions rate described as the net system mix (spot market) in the Washington state electric utility fuel mix disclosure reports compiled by the department pursuant to RCW 19.29A.080. For the resources described in this subsection, a utility must show in the report required in subsection (1) of this section the following:

(a) Tons of CO2 from unknown generation sources;

(b) MWh delivered to its retail customers from unknown generation sources; and

(c) Percentage of total load represented by unknown generation sources.

(4) The energy and emissions intensity report must include narrative text and graphics describing trends and an analysis of the likely causes of changes, or lack of changes, in the metrics.

In this chapter, the commission adopts by reference all, or portions of, the publications identified below. They are available for inspection at the commission branch of the Washington state library. The publications, publication dates, references within this chapter, and availability of the resources are as follows:

(1) Northwest Conservation and Electric Power Plan as published by the Northwest Power and Conservation Council.

(a) The commission adopts the sixth version published in 2010.

(b) This publication is referenced in WAC 480-109-100.

(c) Copies of Sixth Northwest Conservation and Electric Power Plan are available from the Northwest Power and Conservation Council at http://www.nwcouncil.org/energy/powerplan/6/plan/.

(2) Weatherization Manual For Managing the Low-Income Weatherization Program as published by the Washington state department of commerce.

(a) The commission adopts the version published in 2013.

(b) This publication is referenced in WAC 480-109-120.

(c) Copies of Weatherization Manual For Managing the Low-Income Weatherization Program are available from the Washington state department of commerce at http://www.commerce.wa.gov/Programs/services/weatherization/Pages/WeatherizationTechnicalDocuments.aspx.

(3) The unit energy savings values as published by the Northwest Power and Conservation Council's Regional Technical Forum.

(a) The commission adopts the unit energy savings with status of "Active" or "Under Review" on August 1, 2014.

(b) This information is referenced in WAC 480-109-100(5).

(c) The spreadsheets containing the unit energy savings values are available for download at http://rtf.nwcouncil.org/measures/Default.asp.

(4) The energy savings standard protocols as published by the Northwest Power and Conservation Council's Regional Technical Forum.

(a) The commission adopts the energy savings protocols with status of "Active" or "Under Review" on August 1, 2014.

(b) This information is referenced in WAC 480-109-100(5).

(c) The spreadsheets containing the energy savings protocols are available for download at http://rtf.nwcouncil.org/protocols/Default.asp.