The purpose of this chapter is to implement the requirements of the Energy Independence Act, chapter 19.285 RCW.

The provisions of this chapter apply to consumer-owned electric utilities that provide electrical service to more than twenty-five thousand retail customers in the state of Washington.

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 chapter 19.285 RCW apply throughout this chapter.

(1) "Annual revenue requirement" and "total annual revenue requirement" mean that portion of a utility's annual budget approved by its governing body for the target year that is intended to be recovered through retail electricity sales in the state of Washington in the target year, or as otherwise documented by the utility pursuant to WAC 194-37-150.

(2) "Biennial target" means a utility's biennial conservation target.

(3) "BPA" means the Bonneville Power Administration.

(4) "Measurement protocol" means a procedure or method used, consistent with industry standards, to establish with reasonable certainty the amount of energy savings that will result from the installation of a conservation measure. Industry standards include a range of appropriate protocols reflecting a balancing of cost and accuracy, such as the application of a deemed savings value established through industry processes for a measure that has broad application and uniform characteristics and the use of engineering calculations, metering, utility billing analysis, and computer simulation for a measure installed as part of a customer-specific project.

(5) "Multifuel generating facility" means a generating facility that is capable of producing energy from more than one nonrenewable fuel, renewable fuel, or nonfuel energy source, either simultaneously or as alternatives, provided that at least one fuel source (energy source) is a renewable resource and the relative quantities of electricity production can be measured or calculated, and verified.

(6) "NWPCC" means Pacific Northwest Electric Power and Conservation Planning Council also known as the Northwest Power and Conservation Council. Its calculation of avoided costs and publications are available at www.nwcouncil.org.

(7) "REC" means renewable energy credit.

(8) "Regional technical forum" or "RTF" means a voluntary advisory committee that reports to the executive director of the NWPCC and whose members are appointed by the NWPCC's chair.

(9) "Renewable energy target" means the amount, in megawatt-hours or RECs, necessary for a utility to satisfy the requirements of RCW 19.285.040 (2)(a) in a specific target year.

(10) "Substitute resource" means reasonably available electricity or generating facilities, of the same contract length or facility life as the eligible renewable resource the utility invested in to comply with chapter 19.285 RCW requirements, that otherwise would have been used to serve a utility's retail load in the absence of chapter 19.285 RCW requirements to serve that retail load with eligible renewable resources.

(11) "Target year" means a specific year in which a utility must comply with the renewable energy requirements of chapter 19.285 RCW.

(12) "Ten-year potential" means the ten-year cost effective conservation resource potential.

(13) "Utility" means a consumer-owned electric utility, as the term consumer-owned utility is defined in RCW 19.29A.010, that is a qualifying utility.

(14) "Verification protocol" means a procedure or method used, consistent with industry standards, to establish with reasonable certainty that a conservation measure was installed and is in service. Industry standards include a range of appropriate protocols reflecting a balance of cost and accuracy, such as tracking installation of measures through incentive payments and the use of on-site inspection of measures installed as part of a customer-specific project.

(15) "Vintage" means the year in which electricity is generated.

(16) "Weather-adjusted load" means load calculated after variations in peak and average temperatures from year to year are taken into account.

(17) "WREGIS" means the Western Renewable Energy Generation Information System. WREGIS is an independent, renewable energy registry and tracking system for the region covered by the Western Interconnection. WREGIS creates renewable energy certificates, WREGIS certificates, for verifiable renewable generation from units that register in the registry and tracking system.

For the purposes of RCW 19.285.040 (1)(a) and as used in this chapter, "most recently published regional power plan" means the NWPCC's Seventh Northwest Conservation and Electric Power Plan, Council Document 2016-02, dated February 25, 2016. The document is available on the NWPCC's website at this address: www.nwcouncil.org/energy/powerplan/7/plan/.

(1) Each utility must maintain all records necessary to document its compliance with the Energy Independence Act, as described in this chapter. All current and historical reports required by this chapter shall be available to a utility's customers and may be provided in conjunction with the utility's requirements under RCW 19.29A.050.

(2) Each utility that is not under the jurisdiction of the Washington state auditor must be audited for compliance with the Energy Independence Act by an independent auditor at least every twenty-four months and must submit a copy of the audit report to the department.

(3) A consumer-owned utility that becomes subject to this chapter and chapter 19.285 RCW after December 31, 2006, pursuant to RCW 19.285.040(3), must notify the department of its status as a qualifying utility by June 1st of the year after it becomes a qualifying utility and must submit the reports required by WAC 194-37-060 and 194-37-110 starting five years after the notice to the department is due. For the purposes of this requirement, the utility must rely on the number of customers reported by the utility in Form EIA - 861, "Annual Electric Power Industry Report," filed with the Energy Information Administration, United States Department of Energy.

Each utility shall submit an annual conservation report to the department by June 1st using a form provided by the department. The conservation report must show the utility's progress in the preceding year in meeting the conservation targets established in RCW 19.285.040 and must include the following:

(1) The total electricity savings and expenditures for conservation by the following sectors: Residential, commercial, industrial, agricultural, distribution system, and production system. A utility may report results achieved through nonutility programs, as identified in WAC 194-37-080(5), by program, if the results are not included in the reported results by customer sector. Reports submitted in odd-numbered years must include an estimate of savings and expenditures in the prior year. Reports submitted in even-numbered years must include the amount of savings and expenditures in the prior two years. All savings must be documented pursuant to WAC 194-37-080.

(2) A brief description of the methodology used to establish the utility's ten-year potential and biennial target to capture cost-effective conservation.

(3) In even-numbered years the report must include the utility's ten-year conservation potential and biennial targets established pursuant to WAC 194-37-070.

(1) Ten-year potential. By January 1st of each even-numbered year, each utility shall identify its achievable cost-effective conservation potential for the upcoming ten years.

(2) Biennial target. By January 1st of each even-numbered year, each utility shall establish and make public a biennial conservation target. The utility's biennial target shall be no less than its pro rata share of the ten-year potential identified pursuant to subsection (1) of this section.

(3) Each utility must document the methodologies and inputs used in the development of its ten-year potential and biennial target and must document that its ten-year potential and biennial target are consistent with the requirements of RCW 19.285.040(1). Each utility must apply methodologies consistent with the most recently published regional power plan using inputs that reasonably reflect the specific characteristics of the utility and its customers and the general characteristics of the Pacific Northwest power system.

(4) Each utility must establish its ten-year potential and biennial target by action of the utility's governing board, after public notice and opportunity for public comment.

(5) The methodologies used by the NWPCC in its most recently published regional power plan are summarized in this subsection.

(a) Technical potential. Determine the amount of conservation that is technically feasible, considering measures and the number of these measures that could physically be installed or implemented, without regard to achievability or cost.

(b) Achievable technical potential. Determine the amount of the conservation technical potential that is available within the planning period, considering barriers to market penetration and the rate at which savings could be acquired.

(c) Economic achievable potential. Establish the economic achievable potential, which is the conservation potential that is cost-effective, reliable, and feasible, by comparing the total resource cost of conservation measures to the cost of other resources available to meet expected demand for electricity and capacity. A utility may use either of the following approaches to identify economic achievable potential:

(i) Integrated portfolio approach. A utility may analyze, as a part of its integrated resource plan, the cost-effective potential of conservation resources over a range of potential future outcomes for unknown variables, such as future demand, costs, and resource availability. Economic achievable potential will be based on resource plan that achieves a long-run least-cost and least-risk electric power system considering all power system costs and quantifiable nonenergy costs and benefits.

(ii) Benefit-cost ratio approach. A utility may establish economic achievable potential as those conservation measures or programs that pass a total resource cost test, in which the ratio of total benefits to total costs is one or greater. The benefit-cost calculation must use inputs that incorporate the cost of risks that would otherwise be reflected in an integrated portfolio approach.

(d) Total resource cost. In determining economic achievable potential as provided in (c) of this subsection, perform a life-cycle cost analysis of measures or programs to determine the net levelized cost, as described in this subsection:

(i) Conduct a total resource cost analysis that assesses all costs and all benefits of conservation measures regardless of who pays the costs or receives the benefits;

(ii) Include the incremental savings and incremental costs of measures and replacement measures where resources or measures have different measure lifetimes;

(iii) Calculate the value of the energy saved based on when it is saved. In performing this calculation, use time differentiated avoided costs to conduct the analysis that determines the financial value of energy saved through conservation;

(iv) Include the increase or decrease in annual or periodic operations and maintenance costs due to conservation measures;

(v) Include avoided energy costs equal to a forecast of regional market prices, which represents the cost of the next increment of available and reliable power supply available to the utility for the life of the energy efficiency measures to which it is compared;

(vi) Include deferred capacity expansion benefits for transmission and distribution systems;

(vii) Include deferred generation benefits consistent with the contribution to system peak capacity of the conservation measure;

(viii) Include the social cost of carbon emissions from avoided nonconservation resources;

(ix) Include a risk mitigation credit to reflect the additional value of conservation, not otherwise accounted for in other inputs, in reducing risk associated with costs of avoided nonconservation resources;

(x) Include all nonenergy impacts that a resource or measure may provide that can be quantified and monetized;

(xi) Include an estimate of program administrative costs;

(xii) Include the cost of financing measures using the capital costs of the entity that is expected to pay for the measure;

(xiii) Discount future costs and benefits at a discount rate equal to the discount rate used by the utility in evaluating nonconservation resources; and

(xiv) Include a ten percent bonus for the energy and capacity benefits of conservation measures as defined in 16 U.S.C. § 839a of the Pacific Northwest Electric Power Planning and Conservation Act.

(1) Each utility must document its acquisition of conservation savings relative to its biennial target.

(2) Each utility must record conservation savings as the total first-year electricity savings in megawatt-hours or kilowatt-hours.

(3)(a) Each utility must maintain and apply measurement and verification protocols to determine the amount of energy savings resulting from conservation measures and to verify the acquisition or installation of the conservation measures being recorded or claimed.

(b) A utility may comply with this requirement using the measurement and verification protocols adopted by the RTF or by BPA in its energy efficiency implementation manual. If a utility uses other measurement and verification protocols, the measurement and verification protocols must be consistent with recognized industry practices, and the utility must document the methodologies, assumptions, and factual inputs used in its measurement and verification of energy savings.

(4) A utility may count the conservation savings from a conservation measure toward its biennial target if the measure, or a project or program consisting of more than one measure, meets the following criteria:

(a) The utility has established that the measure, or a program or project consisting of more than one measure, was cost-effective;

(b) The utility has documented that the measure was installed within its retail service area during the biennial period, or in the case of programs described in subsection (5) of this section, that the savings were attributed to the utility using a reasonable and consistent method;

(c) The utility used a reasonable and consistent method of assigning conservation savings to biennial periods such as, by the date the conservation measure was installed, by the date an incentive was paid to a customer, or by the date the conservation measure was reported to an external funding agency such as BPA; and

(d) The utility applied a reasonable and consistent policy of incorporating changes in unit energy savings values subsequent to the adoption of a biennial conservation target. Such a policy may either count savings using the unit energy savings values in effect at the time the biennial target is established or update all unit energy savings values as they are changed by the entity responsible for establishing the values.

(5) Subject to the requirements of subsection (4) of this section, each utility may count toward its biennial conservation target the proportionate share of savings resulting in its service territory from the implementation of regional or multistate conservation programs, market transformation programs, appliance standards, building energy codes, and nonprogrammatic savings including, but not limited to, the Northwest Energy Efficiency Alliance and BPA.

(6) A utility must not count as conservation a reduction in electricity consumption due to curtailment of a customer's process or service, such as the shutdown of a manufacturing facility. A change in the operating practices of a customer that reduces electricity consumption without reducing the level of output or other benefits of electricity consumption is not curtailment.

(7) A utility that does not acquire conservation savings during a biennial period sufficient to meet its biennial conservation target may document its level of effort at conservation acquisition. The documentation should include:

(a) A description of the utility's marketing programs, education programs, custom project proposals, monetary incentives, financing offers, and other efforts during the biennial period to motivate customers to install conservation measures;

(b) A detailed report of the utility's budget and actual expenditures for the activities in (a) of this subsection;

(c) An identification of all conservation measures, programs, or projects for which the utility offered to pay customers an incentive in an amount equal to the utility's full avoided cost over the lifetime of measures; and

(d) An identification of all conservation measures that were included in the biennial target and became unavailable to the utility due to the shutdown or curtailment of operations of a retail customer.

(1) A utility may count as conservation savings a portion of the electricity output of a high-efficiency cogeneration facility that commences operation in its service territory.

(2) The high-efficiency cogeneration facility must be 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 may not be considered in determining conservation savings.

(3) The useful thermal energy output of the cogeneration facility must be no less than thirty-three percent of the total energy output of the cogeneration facility under normal operating conditions.

(4) The reduction in customer load due to high-efficiency cogeneration must be 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; and

(b) The heat rate (in British thermal units per megawatt hour) of a combined cycle natural gas-fired combustion turbine. 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. The heat rate of the combustion turbine must be based on a facility using best commercial available technology on a new and clean basis.

(5) The utility's documentation of a cogeneration facility's compliance with subsections (3) and (4) of this section must be certified by a registered professional engineer licensed by the Washington department of licensing.

Each utility must submit a renewable resource energy report to the department by June 1st of each year using a form provided by the department. The report must reflect the actions that the utility took by the previous January 1st to meet the renewable requirements of chapter 19.285 RCW for that year. For example, a utility must report by June 1, 2015, the actions it took by January 1, 2015, to meet requirements applicable to the 2015 target year.

(1) Reporting requirements applicable to all utilities. Each utility must report the following information:

(a) The compliance method:

(i) Renewable energy target using renewable resources and RECs – RCW 19.285.040 (2)(a);

(ii) Incremental cost – RCW 19.285.050; or

(iii) No-growth cost – RCW 19.285.040 (2)(d).

(b) The utility's load for the two years preceding the target year and the average load for those two years.

(c) The utility's renewable energy target for the target year.

(d) The amount of eligible renewable resources, RECs, and multiplier credits to be applied toward the utility's renewable energy target for the target year. The report must identify, by generating facility or hydroelectric project, including the WREGIS generating unit identification where applicable, and, in the case of RECs, by vintage year:

(i) The eligible renewable resources in megawatt-hours to be applied toward the renewable energy target for the target year;

(ii) The RECs to be applied toward the renewable energy target for the target year;

(iii) Any additional credit for eligible renewable resources or RECs from generating facilities eligible for the apprentice labor provision in RCW 19.285.040 (2)(h), applied toward the renewable energy target for the target year;

(iv) Any additional credit for RECs from generating facilities eligible for the distributed generation in RCW 19.285.040 (2)(b), applied toward the renewable energy target for the target year.

(e) The percent of its total annual retail revenue requirement invested in the incremental cost of eligible renewable resources and the cost of renewable energy credits. Each utility must include in its report documentation of the calculations and inputs to this amount.

(a) Annual revenue requirement for the target year;

(b) The annual levelized delivered cost of its eligible renewable resource(s) reported separately for each resource;

(c) The annual levelized delivered cost of its substitute resources and the eligible renewable resource with which it is being compared;

(d) The total cost of renewable energy credits to be applied in the reporting year;

(e) The percentage of its annual revenue requirement invested in the incremental cost of eligible renewable resources and the cost of RECs; and

(f) The most current information required by WAC 194-37-160 used for this financial demonstration.

(3) No-growth cost compliance method report. Each utility reporting pursuant to subsection (1)(a) of this section its use of the no-growth cost compliance method for the target year must include the following information in its report:

(a) Annual revenue requirement for the target year;

(b) Actual and weather-adjusted load for each year used in determining that the utility's load did not increase;

(c) Delivered cost of its eligible renewable resource(s), RECs or a combination of both for the target year to be applied to the one percent of annual revenue requirement, reported separately for each resource;

(d) Generating facility identification, vintage, quantity and cost of any RECs to be retired as an offset for nonrenewable resource purchases pursuant to RCW 19.285.040 (2)(d).

(4) Final compliance report. A utility must submit a final renewable compliance report by the later of (a) two years after the filing of the report required in subsections (1) through (3) of this section; or (b) ninety days after the issuance of the auditor's report for the target year. The final renewable compliance report must provide an update of any revisions to the information previously reported pursuant to this section or, if no revisions were made, notify the department that the initial report should be considered the final report. For any target year that a utility demonstrates to the auditor that it did not meet the annual renewable resource requirements in chapter 19.285 RCW due to events beyond the reasonable control of the utility per RCW 19.285.040 (2)(i), the utility must summarize these events in the final compliance report.

A utility using an eligible renewable resource or REC for compliance with a requirement of chapter 19.285 RCW must document that use by following the procedures in this section.

(1) Documentation of energy from eligible renewable resources. Each utility using an eligible renewable resource for compliance must document the following for each resource:

(a) The electricity was generated by a generating facility that is an eligible renewable resource;

(b) The electricity was generated during the target year;

(c) If the utility sold, exchanged, or otherwise transferred the electricity to any person other than its retail customer, the utility retained ownership of the nonpower attributes; and

(d) The utility retired, consistent with the requirements of subsection (2) of this section, any RECs representing the nonpower attributes associated with the electricity or, if no RECs have been created, the utility has committed to use the nonpower attributes exclusively for the compliance purpose stated in its documentation.

(2) Documentation of renewable energy certificates. Each utility using a REC for compliance must document the following:

(a) The REC represents the output of an eligible renewable resource;

(b) For a REC from electricity generated by a resource other than freshwater, the vintage of the REC is the year immediately prior to the target year, the year of the target year, or the year immediately after the target year; and

(c) For a REC from electricity generated by freshwater:

(i) The vintage of the REC is the target year;

(ii) The REC was acquired by the utility through ownership of the generation facility or through a transaction that conveyed both the electricity and the nonpower attributes of the electricity; and

(iii) For RECs from projects marketed by the Bonneville Power Administration, the utility received the REC through a transaction with the Bonneville Power Administration that conveyed both the electricity and the nonpower attributes of the electricity.

(d) The utility has retired the REC to a retirement subaccount of the utility within WREGIS using the following values in the certificate transfer:

(i) Retirement type: Used by the account holder for a state-regulated renewable portfolio standard/provincial utility portfolio standard;

(ii) State/province: Washington; and

(iii) Compliance year: Applicable target year.

(1) Projects owned by qualifying utilities. Each utility using electricity produced as a result of a hydropower efficiency improvement, as defined in RCW 19.285.030 (12)(b), to meet a renewable energy target must provide documentation that:

(a) The hydroelectric generation project is owned by a qualifying utility and is located in the Pacific Northwest;

(b) The hydropower efficiency improvement was completed after March 31, 1999; and

(c) The additional generation does not result in new water diversions or impoundments.

(2) Federal projects. Each utility using electricity produced as a result of a hydropower efficiency improvement, as defined in RCW 19.285.030 (12)(g), to meet a renewable energy target must provide documentation that:

(a) The output of the hydroelectric generation project is marketed by the Bonneville Power Administration;

(b) The utility received the electricity through a transaction with the Bonneville Power Administration that conveyed both the electricity and the nonpower attributes of that electricity;

(c) The hydropower efficiency improvement was completed after March 31, 1999; and

(d) The additional generation does not result in new water diversions or impoundments.

(3) If the amount of electricity generated as a result of the hydropower efficiency improvement is directly measurable, the utility must use the measured output of the hydropower efficiency improvement as documentation of the amount of additional generation.

(4)(a) If the amount of electricity generated as a result of the hydropower efficiency improvements is not directly measurable, the utility must document the amount of electricity generated as a result of the hydropower efficiency improvement using an engineering analysis comparing the output in megawatt-hours of the hydroelectric generation project with the efficiency improvement to the output in megawatt-hours of the hydroelectric generation project without the efficiency improvement. Multiple efficiency improvements to a single hydroelectric generation project may be combined for purposes of the engineering analysis.

(b) The engineering analysis required by (a) of this subsection must be performed using an engineering model of the hydroelectric generation project that quantifies the relationship of stream flows, reservoir elevation, and other relevant factors to the electric output of the generating facility. The engineering model must accurately reflect the physical characteristics and operating requirements of the hydroelectric generation project during the target year and must accurately estimate the electric generation of the hydroelectric generation project without and with the hydropower efficiency improvement.

(c) A utility using the engineering analysis method to determine incremental generation must adopt and consistently apply in each target year one of the following methods:

(i) Method one - Actual incremental generation. A utility using this method must prepare an analysis using actual stream flows and the engineering model described in (b) of this subsection during each target year to determine incremental generation in the target year. A utility using this method must perform an updated calculation each year to determine the incremental generation amount for that target year.

(ii) Method two - Percentage generation.

(A) A utility using method two must prepare an analysis establishing the expected amount of incremental generation based on stream flows available to the hydroelectric generation project, adjusted for any known and measurable changes to stream flows due to environmental regulations or other factors, during a historical study period.

(B) The historical study period used in method two must be reasonably representative of the stream flows that would have been available to the hydroelectric project over the period of time for which stream flow records are readily available. A historical study period meets the requirements of this subsection if it includes the most recent readily available stream flow records and consists of a consecutive record of stream flow records at least five years in length.

(C) The amount of incremental generation using method two is calculated by multiplying the actual generation in megawatt-hours in the target year by a percentage amount equal to the difference between the calculated average generation over the historical study period with the hydropower efficiency improvement and the calculated average generation over the historical study period without the hydropower efficiency improvement, divided by the calculated average generation over the historical study period without the hydropower efficiency improvement.

(iii) Method three - Fixed amount of generation.

(A) A utility using method three must prepare an analysis establishing the expected amount of incremental generation based on stream flows available to the hydroelectric generation project, adjusted for any known and measurable changes to stream flows due to environmental regulations or other factors during a historical study period.

(B) The historical study period used in method three must be reasonably representative of the stream flows that would have been available to the hydroelectric project over the period of time for which stream flow records are readily available. A historical study period meets the requirements of this subsection if it includes the most recent readily available stream flow records and consists of a consecutive record of stream flow records at least ten years in length.

(C) The amount of incremental generation using method three is calculated as an amount in megawatt-hours equal to the difference between the calculated average generation over the historical study period with the hydropower efficiency improvement and the calculated average generation over the historical study period without the hydropower efficiency improvement. The amount must be adjusted in each target year for any reduction in availability of the hydroelectric generation project's generating capacity during the target year that is not accounted for in the analysis used to calculate the incremental generation amount.

(5) The requirements of this section are in addition to the documentation requirements specified in WAC 194-37-120(1).

(1) Multifuel biomass energy. A utility using biomass energy produced by a multifuel generating facility, where the biomass energy fuel provides less than ninety-eight percent of the total heat input, must document the eligible renewable energy using RECs created by WREGIS pursuant to the multifuel generating unit procedures of WREGIS.

(2) Qualified biomass energy. A utility using qualified biomass energy must document the eligible renewable energy using RECs created by WREGIS and must document:

(a) Information about the facility generating electricity from biomass energy:

(i) Ownership of the biomass energy facility;

(ii) Date of commercial operation of the biomass energy facility; and

(iii) Specific type of biomass used for generation by the biomass energy facility.

(b) Information about the industrial facility that hosts the biomass energy facility:

(i) The utility's load in megawatt hours that results from serving the industrial facility;

(ii) Evidence that the industrial facility had not ceased operation, other than for purposes of maintenance or upgrade, during the target year;

(iii) Evidence that the industrial facility engages in industrial pulping or wood manufacturing; and

(iv) If the facility generating electricity from biomass energy is not owned by the utility, evidence that the industrial facility owns the biomass energy facility and is directly interconnected with the electricity facilities that are owned by the utility and capable of carrying electricity at transmission voltage.

(3) Incremental biomass energy.

(a) A utility using incremental electricity produced as a result of a capital investment at a qualified biomass energy facility must document the eligible renewable energy using RECs created by WREGIS and must document:

(i) The status of the generating facility as a qualified biomass energy facility as provided in subsection (2) of this section;

(ii) Evidence of the quantity, in megawatt hours, of renewable energy electric power generation during the baseline period, which must be determined using the methodology provided in (b) of this subsection;

(iii) Evidence of the nature and amount of the capital investment, demonstrating that the capital investment project was completed after January 1, 2010, and that the expenditure was not on operation and maintenance in the normal course of business;

(iv) Evidence demonstrating that the incremental generation was a result of the capital investment; and

(v) The method or procedures that the facility owner uses to measure or calculate incremental generation and to track incremental generation within WREGIS separately from qualified biomass energy produced by the facility.

(b) Methodology for establishing baseline generation.

(i) The baseline level of generation for determining incremental generation must be established as the average quantity of net generation using eligible renewable energy fuel sources during the most recent three consecutive years of operation prior to the effect of the first capital investment completed after January 1, 2010. The three-year period must begin on or after January 1, 2007. Subsequent capital investments that result in additional amounts of incremental generation do not require a new baseline determination.

(ii) The baseline period must exclude any periods in which operation of the qualified biomass generation facility was unrepresentative of normal operating conditions.

(iii) Baseline generation must be documented using plant-level reports of net generation by fuel type submitted to the U.S. Energy Information Administration or, if such reports are not available, by business records of the generation facility owner.

(1) Apprentice labor credit. A utility claiming an additional credit for the electricity output from an eligible renewable resource per RCW 19.285.040 (2)(h)(i) must document that the facility commenced operation after December 31, 2005, and must provide written documentation from the Washington state apprenticeship and training council within the department of labor and industries that the facility qualified for the apprentice labor credit.

(2) Distributed generation credit. A utility claiming an additional credit for distributed generation pursuant to RCW 19.285.040 (2)(b) must meet the following requirements:

(a) The utility may claim a distributed generation credit only if the generating facility is registered in WREGIS and the utility retires all RECs associated with its distributed generation claim.

(b) In determining whether a generating facility has a generating capacity of not more than five megawatts, the capacity of the generating facility will be based on its nameplate rating measured in alternating current.

(c) In determining whether a generating facility is eligible for the distributed generation credit, the generating capacity of the generating facility will be based on the aggregate generating capacity of the generating facility and all other generating facilities in the same integrated cluster. An integrated cluster of generating facilities consists of all generating facilities that:

(i) Are located on the same or contiguous property. In determining whether properties are contiguous, interruptions in contiguity caused by easements, public thoroughfares, transportation rights of way, or utility rights of way must be disregarded; and

(ii) Have any of the following elements in common:

(A) Ownership. Each person with more than five percent beneficial ownership, other than tax equity owners, will be considered an owner for purposes of determining common ownership of generating facilities;

(B) Operational control; or

(C) Interconnection. Generating facilities have common interconnection if they have the same point of common coupling with the area electric power system.

For each year that a utility meets the renewable energy financial cost cap, associated with no load growth, identified in RCW 19.285.040 (2)(d), the utility must document the following by January 1:

(1) That it used a consistent methodology from year to year to weather-adjust its retail load;

(2) That the average of weather-adjusted loads over the three previous years did not increase over the weather-adjusted load in the year immediately prior to the three-year period;

(3) That it invested at least one-percent of its total annual revenue requirement in each target year on eligible renewable resources, RECs, or a combination of both;

(4) That it executed contracts, dated no later than January 1 of the target year, for power purchases of sufficient eligible renewable resources and/or RECs;

(5) The quantity of megawatt-hours for each target year for which the utility:

(a) Commenced or renewed ownership of nonrenewable resources, other than coal transition power, after December 7, 2006; or

(b) Made electricity purchases from nonrenewable energy resources, other than coal transition power, incremental to its annual electricity purchases made or contracted for before December 7, 2006.

Sources of power for daily spot market purchases are not included in this calculation;

(6) The RECs the utility acquired, in addition to any RECs acquired for subsection (3) of this section, to offset power purchases listed in subsection (5) of this section; and

(7) Annual revenue requirement for the target year.

(1) For purposes of the report filed pursuant to RCW 19.285.070, a utility shall document its annual revenue requirement.

(2) A utility that uses a different basis for the determination of its annual revenue requirement for purposes of calculating what it expects to recover or actually recovers through retail electricity sales in the state of Washington in that year may use that number in the calculation of the cost cap and must provide documentation to support this alternative approach.

By January 1 of the first target year that a utility fulfills its renewable energy requirements under RCW 19.285.050, the utility shall select one of the following methodologies for documenting the incremental cost of all eligible renewable resources acquired thereafter by that utility:

(1) Annual update methodology. In each year that a utility fulfills its renewable energy requirements by complying with the cost cap identified in RCW 19.285.050 it must document its calculations no later than January 1 of the target year. The utility will use the most current information available to the utility within twelve months prior to the initial documentation of the cost cap pursuant to WAC 194-37-170 through 194-37-190. The utility will update this documentation in its June 1 report submitted pursuant to RCW 19.285.070. These annual updates of costs, based on the most current information available, apply to both the eligible renewable resource and the substitute resource.

(2) Permanent one-time methodology. For each new investment in an eligible renewable resource, a utility shall perform a one-time calculation of the levelized incremental cost pursuant to WAC 194-37-170 through 194-37-190. The levelized incremental cost shall be a single annual value expressed in real, constant-year dollars. The levelized incremental cost for each eligible renewable resource project or purchase, calculated through this one-time analysis in the year of acquisition, shall be allowed to inflate utilizing the Producer Price Index over the life of the eligible renewable resource after the initial calculation. The utility will include a determination of incremental cost for each new investment in an eligible renewable resource and inflation-adjusted incremental costs for previous eligible renewable resource investments in its June 1 report submitted pursuant to RCW 19.285.070, beginning in the year the utility complies with the cost cap identified in RCW 19.285.050.

(1) Each utility must document its calculation of the levelized annual incremental cost of eligible renewable resources. Utilities are encouraged, but not obligated, to use the following methodology:

Step 1: Calculate the net present value of the cost of the utility's eligible renewable resource and substitute resource over an equivalent contract length or facility life.

Step 2: Calculate equal nominal values over the appropriate contract length or facility life that have a net present value equal to those calculated in Step 1, using the same discount rate.

Step 3: Calculate the annual difference between the levelized delivered cost for the eligible renewable resource and the substitute resource to determine the levelized incremental cost of the eligible renewable resource.

A utility that uses the annual update methodology must document the basis for any change to the levelization methodology used in a prior June 1 report to levelize the costs of an eligible renewable resource and its associated substitute resource.

(2) Regardless of the methodology chosen to levelize costs, utilities must document the basis for their chosen method for levelizing costs.

(3) Utilities must document the basis for the discount rate used in its levelized cost calculations.

(4) Utilities must document how the discount rate used to perform the levelized cost calculations is consistent with the inflationary assumptions incorporated into the delivered cost projections for the eligible renewable resource and substitute resource.

(5) Utilities must document how the method and assumptions used to levelize delivered costs for the eligible renewable resource are consistent with those used to levelize the delivered cost of the associated substitute resource.

(1) The delivered cost of a resource includes all direct and indirect costs associated with that resource being delivered to the distribution system of a utility over the contract length or facility life of the delivered resource. Direct and indirect costs may include operating and capital expenses related to the delivered resource.

(2) Using the Uniform System of Accounts of the Federal Energy Regulatory Commission (FERC) as an illustration, the reported resource costs are expected to generally fall within, but not necessarily be limited to, the following cost accounts:

(3) A utility may include actual costs in order to equitably compare the costs of eligible renewable resources and substitute resources. This may include the actual costs of transmission, firming, shaping, integration, and project specific development costs.

(4) Utilities are encouraged to use the FERC system of accounts to document the delivered cost of resources. Regardless of the accounting convention used, utilities must document the delivered cost estimates for eligible renewable resources and their associated substitute resources in a manner consistent with generally accepted accounting standards.

(1) In support of its annual filings to the department under RCW 19.285.070, utilities must document the type, availability, and cost of the reasonably available substitute resource used to calculate the incremental cost of an eligible renewable resource.

(a) In documenting the incremental cost under RCW 19.285.050 (1)(b), a utility is encouraged to identify substitute resources using its integrated resource planning process, if one is available. If a utility elects to choose a substitute resource from a different source other than its most recently published integrated resource plan, it must document the basis for this decision. Documentation of the cost of a substitute resource may include, but is not limited to, formal offers for the sale of electricity, or published cost projections from reputable third-party sources.

(b) In its selection of a substitute resource, the utility shall develop documentation demonstrating that the substitute resource satisfies the requirements set forth in RCW 19.285.050. The requirements are:

(i) Equivalence between the eligible renewable resource and the substitute resource by demonstrating the equivalence in the amount of energy produced by each resource;

(ii) Equivalence between the eligible renewable resource and the substitute resource by demonstrating the same contract length or facility life of each resource;

(iii) The substitute resource is reasonably available to the utility; and

(iv) The substitute resource does not qualify as an eligible renewable resource.

(c) Only supply-side substitute resources shall be used by utilities in the calculation of the incremental cost of eligible renewable resources.

(d) When the renewable requirements under RCW 19.285.040(2) result in a utility having resources in excess of its load, the utility may use that excess resource as the substitute resource if the substitute resource requirements of (b) of this subsection are otherwise satisfied. The utility will document the resale revenues, net of transaction costs, received through the sale of excess resources or the purchase price for the sale of the excess facility sold as a result of the requirement to acquire eligible renewable resources. A utility that uses a value other than the documented resale revenue in the determination of the levelized delivered cost of the substitute resource, such as a forecast of projected market prices, must provide documentation to support this alternative approach.

(e) A utility may use foregone power purchases from BPA, plus any billing credit obtained for reducing its purchases from BPA, as the basis for the cost of the substitute resource if:

(i) The substitute resource requirements of (b) of this subsection are otherwise satisfied;

(ii) It is entitled under its BPA power sales contract to have the BPA meet its net power requirements for the expected life of an eligible renewable resource or eligible renewable resource purchase; and

(iii) As a result of meeting the renewable requirements under RCW 19.285.040(2), it foregoes part of its BPA entitlement in order to obtain that eligible renewable resource.

(2) For an eligible renewable resource acquired prior to the passage of chapter 19.285 RCW, November 7, 2006, a utility must support the selection of the related substitute resource used in the determination of the incremental cost under RCW 19.285.050 with documentation that was available at the time of the utility's decision to acquire the eligible renewable resource. If no such documentation is available, the incremental cost of an eligible renewable resource acquired prior to the passage of chapter 19.285 RCW will be assumed equal to zero.

A utility may elect to invest in RECs to meet any portion of, or the entirety of, each annual renewable resource target in RCW 19.285.040(2) or 19.285.050(1). If the cost of the RECs and the incremental cost of acquired renewable resources, as documented according to WAC 194-37-150 through 194-37-190, for any one year meets or exceeds four percent of the utility's annual revenue requirement, the utility shall document that the utility achieved the four percent cost cap alternative compliance path in RCW 19.285.050(1). The documentation must include copies of its WREGIS RECs, copies of purchase contracts, and its annual revenue requirement.

(1) WREGIS is the renewable energy credit tracking system for purposes of verification of RECs under chapter 19.285 RCW.

(2) Upon request by a utility, the department may approve a special purpose renewable energy credit tracking system for the generation of any specific generating facility acquired through ownership or contract by a utility prior to January 1, 2015, if the utility certifies that it would be impractical or financially burdensome to track the generation of the facility using WREGIS. The approval of a special purpose tracking system may include limitations or conditions on the transfer of RECs. All references to WREGIS in this chapter include such approved special purpose tracking systems.