It is the intent of the legislature to encourage the development of new safe, clean, and reliable energy resources to meet demand in Washington for affordable and reliable electricity. To achieve this end, the legislature finds it essential that electric utilities in Washington develop comprehensive resource plans that explain the mix of generation and demand-side resources they plan to use to meet their customers' electricity needs in both the short term and the long term. The legislature intends that information obtained from integrated resource planning under this chapter will be used to assist in identifying and developing: (1) New energy generation; (2) conservation and efficiency resources; (3) methods, commercially available technologies, and facilities for integrating renewable resources, including addressing any overgeneration event; and (4) related infrastructure to meet the state's electricity needs.

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

(1) "Combined heat and power" means the sequential production of electricity and useful thermal energy from a common fuel source where, under normal operating conditions, the facility has a useful thermal energy output of no less than thirty-three percent of the total energy output.

(2) "Commission" means the utilities and transportation commission.

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

(4) "Consumer-owned utility" includes a municipal electric utility formed under Title 35 RCW, a public utility district formed under Title 54 RCW, an irrigation district formed under chapter 87.03 RCW, a cooperative formed under chapter 23.86 RCW, a mutual corporation or association formed under chapter 24.06 RCW, a port district formed under Title 53 RCW, or a water-sewer district formed under Title 57 RCW, that is engaged in the business of distributing electricity to one or more retail electric customers in the state.

(5) "Department" means the department of commerce.

(6) "Electric utility" means a consumer-owned or investor-owned utility.

(7) "Full requirements customer" means an electric utility that relies on the Bonneville power administration for all power needed to supply its total load requirement other than that served by nondispatchable generating resources totaling no more than six megawatts or renewable resources.

(8) "Governing body" means the elected board of directors, city council, commissioners, or board of any consumer-owned utility.

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

(10) "Investor-owned utility" means a corporation owned by investors that meets the definition in RCW 80.04.010 and is engaged in distributing electricity to more than one retail electric customer in the state.

(11) "Lowest reasonable cost" means the lowest cost mix of generating resources and conservation and efficiency resources determined through a detailed and consistent analysis of a wide range of commercially available resources. At a minimum, this analysis must consider resource cost, market-volatility risks, demand-side resource uncertainties, resource dispatchability, resource effect on system operation, the risks imposed on the utility and its ratepayers, public policies regarding resource preference adopted by Washington state or the federal government, and the cost of risks associated with environmental effects including emissions of carbon dioxide.

(12) "Overgeneration event" means an event within an operating period of a balancing authority when the electricity supply, including generation from intermittent renewable resources, exceeds the demand for electricity for that utility's energy delivery obligations and when there is a negatively priced regional market.

(13) "Plan" means either an "integrated resource plan" or a "resource plan."

(14) "Renewable resources" means electricity generation facilities fueled by: (a) Water; (b) wind; (c) solar energy; (d) geothermal energy; (e) landfill gas; (f) biomass energy utilizing animal waste, solid or liquid organic fuels from wood, forest, or field residues or dedicated energy crops that do not include wood pieces that have been treated with chemical preservatives such as creosote, pentachlorophenol, or copper-chrome-arsenic; (g) by-products of pulping or wood manufacturing processes, including but not limited to bark, wood chips, sawdust, and lignin in spent pulping liquors; (h) ocean thermal, wave, or tidal power; or (i) gas from sewage treatment facilities.

(15) "Resource plan" means an assessment that estimates electricity loads and resources over a defined period of time and complies with the requirements in *RCW 19.280.030(2).

Reviser's note: *(1) RCW 19.280.030 was amended by 2019 c 288 s 14, changing subsection (2) to subsection (5).

(2) The definitions in this section have been alphabetized pursuant to RCW 1.08.015(2)(k).

Finding—Intent—2015 3rd sp.s. c 19: See note following RCW 39.35.010.

Each electric utility must develop a plan consistent with this section.

(1) Utilities with more than 25,000 customers that are not full requirements customers must develop or update an integrated resource plan by September 1, 2008. At a minimum, progress reports reflecting changing conditions and the progress of the integrated resource plan must be produced every two years thereafter. An updated integrated resource plan must be developed at least every four years subsequent to the 2008 integrated resource plan. The integrated resource plan, at a minimum, must include:

(a) A range of forecasts, for at least the next 10 years or longer, of projected customer demand which takes into account econometric data and customer usage;

(b) An assessment of commercially available conservation and efficiency resources, as informed, as applicable, by the assessment for conservation potential under RCW 19.285.040 for the planning horizon consistent with (a) of this subsection. Such assessment may include, as appropriate, opportunities for development of combined heat and power as an energy and capacity resource, demand response and load management programs, and currently employed and new policies and programs needed to obtain the conservation and efficiency resources;

(c) An assessment of commercially available, utility scale renewable and nonrenewable generating technologies including a comparison of the benefits and risks of purchasing power or building new resources;

(d) A comparative evaluation of renewable and nonrenewable generating resources, including transmission and distribution delivery costs, and conservation and efficiency resources using "lowest reasonable cost" as a criterion;

(e) An assessment of methods, commercially available technologies, or facilities for integrating renewable resources, including but not limited to battery storage and pumped storage, and addressing overgeneration events, if applicable to the utility's resource portfolio;

(f) An assessment and 20-year forecast of the availability of and requirements for regional generation and transmission capacity to provide and deliver electricity to the utility's customers and to meet the requirements of chapter 288, Laws of 2019 and the state's greenhouse gas emissions reduction limits in RCW 70A.45.020. The transmission assessment must identify the utility's expected needs to acquire new long-term firm rights, develop new, or expand or upgrade existing, bulk transmission facilities consistent with the requirements of this section and reliability standards;

(i) If an electric utility operates transmission assets rated at 115,000 volts or greater, the transmission assessment must take into account opportunities to make more effective use of existing transmission capacity through improved transmission system operating practices, energy efficiency, demand response, grid modernization, nonwires solutions, and other programs if applicable;

(ii) An electric utility that relies entirely or primarily on a contract for transmission service to provide necessary transmission services may comply with the transmission requirements of this subsection by requesting that the counterparty to the transmission service contract include the provisions of chapter 288, Laws of 2019 and chapter 70A.45 RCW as public policy mandates in the transmission service provider's process for assessing transmission need, and planning and acquiring necessary transmission capacity;

(iii) An electric utility may comply with the requirements of this subsection (1)(f) by relying on and incorporating the results of a separate transmission assessment process, conducted individually or jointly with other utilities and transmission system users, if that assessment process meets the requirements of this subsection;

(g) A determination of resource adequacy metrics for the resource plan consistent with the forecasts;

(h) A forecast of distributed energy resources that may be installed by the utility's customers and an assessment of their effect on the utility's load and operations;

(i) An identification of an appropriate resource adequacy requirement and measurement metric consistent with prudent utility practice in implementing RCW 19.405.030 through 19.405.050;

(j) The integration of the demand forecasts, resource evaluations, and resource adequacy requirement into a long-range assessment describing the mix of supply side generating resources and conservation and efficiency resources that will meet current and projected needs, including mitigating overgeneration events and implementing RCW 19.405.030 through 19.405.050, at the lowest reasonable cost and risk to the utility and its customers, while maintaining and protecting the safety, reliable operation, and balancing of its electric system;

(k) An assessment, informed by the cumulative impact analysis conducted under RCW 19.405.140, of: Energy and nonenergy benefits and the avoidance and reductions of burdens to vulnerable populations and highly impacted communities; long-term and short-term public health and environmental benefits, costs, and risks; and energy security and risk;

(l) A 10-year clean energy action plan for implementing RCW 19.405.030 through 19.405.050 at the lowest reasonable cost, and at an acceptable resource adequacy standard, that identifies the specific actions to be taken by the utility consistent with the long-range integrated resource plan; and

(m) An analysis of how the plan accounts for:

(i) Modeled load forecast scenarios that consider the anticipated levels of zero emissions vehicle use in a utility's service area, including anticipated levels of zero emissions vehicle use in the utility's service area provided in RCW 47.01.520, if feasible;

(ii) Analysis, research, findings, recommendations, actions, and any other relevant information found in the electrification of transportation plans submitted under RCW 35.92.450, 54.16.430, and 80.28.365; and

(iii) Assumed use case forecasts and the associated energy impacts. Electric utilities may, but are not required to, use the forecasts generated by the mapping and forecasting tool created in RCW 47.01.520. This subsection (1)(m)(iii) applies only to plans due to be filed after September 1, 2023.

(2) The clean energy action plan must:

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

(b) Establish a resource adequacy requirement;

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

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

(e) Identify any need to develop new, or expand or upgrade existing, bulk transmission and distribution facilities and document existing and planned efforts by the utility to make more effective use of existing transmission capacity and secure additional transmission capacity consistent with the requirements of subsection (1)(f) of this section; and

(f) Identify the nature and possible extent to which the utility may need to rely on alternative compliance options under RCW 19.405.040(1)(b), if appropriate.

(3)(a) An electric or large combination utility shall consider the social cost of greenhouse gas emissions, as determined by the commission for investor-owned utilities pursuant to RCW 80.28.405 and the department for consumer-owned utilities, when developing integrated resource plans and clean energy action plans. An electric utility must incorporate the social cost of greenhouse gas emissions as a cost adder when:

(i) Evaluating and selecting conservation policies, programs, and targets;

(ii) Developing integrated resource plans and clean energy action plans; and

(iii) Evaluating and selecting intermediate term and long-term resource options.

(b) For the purposes of this subsection (3): (i) Gas consisting largely of methane and other hydrocarbons derived from the decomposition of organic material in landfills, wastewater treatment facilities, and anaerobic digesters must be considered a nonemitting resource; and (ii) qualified biomass energy must be considered a nonemitting resource.

(4) To facilitate broad, equitable, and efficient implementation of chapter 288, Laws of 2019, a consumer-owned energy utility may enter into an agreement with a joint operating agency organized under chapter 43.52 RCW or other nonprofit organization to develop and implement a joint clean energy action plan in collaboration with other utilities.

(5) All other utilities may elect to develop a full integrated resource plan as set forth in subsection (1) of this section or, at a minimum, shall develop a resource plan that:

(a) Estimates loads for the next five and 10 years;

(b) Enumerates the resources that will be maintained and/or acquired to serve those loads;

(c) Explains why the resources in (b) of this subsection were chosen and, if the resources chosen are not: (i) Renewable resources; (ii) methods, commercially available technologies, or facilities for integrating renewable resources, including addressing any overgeneration event; or (iii) conservation and efficiency resources, why such a decision was made;

(d) By December 31, 2020, and in every resource plan thereafter, identifies how the utility plans over a 10-year period to implement RCW 19.405.040 and 19.405.050; and

(e) Accounts for:

(i) Modeled load forecast scenarios that consider the anticipated levels of zero emissions vehicle use in a utility's service area, including anticipated levels of zero emissions vehicle use in the utility's service area provided in RCW 47.01.520, if feasible;

(ii) Analysis, research, findings, recommendations, actions, and any other relevant information found in the electrification of transportation plans submitted under RCW 35.92.450, 54.16.430, and 80.28.365; and

(iii) Assumed use case forecasts and the associated energy impacts. Electric utilities may, but are not required to, use the forecasts generated by the mapping and forecasting tool created in RCW 47.01.520. This subsection (5)(e)(iii) applies only to plans due to be filed after September 1, 2023.

(6) Assessments for demand-side resources included in an integrated resource plan may include combined heat and power systems as one of the measures in a conservation supply curve. The value of recoverable waste heat resulting from combined heat and power must be reflected in analyses of cost-effectiveness under this subsection.

(7) An electric utility that is required to develop a resource plan under this section must complete its initial plan by September 1, 2008.

(8) Plans developed under this section must be updated on a regular basis, on intervals approved by the commission or the department, or at a minimum on intervals of two years.

(9)(a) Plans shall not be a basis to bring legal action against electric utilities. However, nothing in this subsection (9)(a) may be construed as limiting the commission or any party from bringing any action pursuant to Title 80 RCW, this chapter, or chapter 19.405 RCW against any large combination utility related to an integrated system plan submitted pursuant to RCW 80.86.020.

(b) The commission may approve, reject, or approve with conditions, any integrated system plans submitted by a large combination utility as defined in RCW 80.86.010.

(10)(a) To maximize transparency, the commission, for investor-owned utilities, or the governing body, for consumer-owned utilities, may require an electric utility to make the utility's data input files available in a native format. Each electric utility shall publish its final plan either as part of an annual report or as a separate document available to the public. The report may be in an electronic form.

(b) Nothing in this subsection limits the protection of records containing commercial information under RCW 80.04.095.

(11) The commission may require a large combination utility as defined in RCW 80.86.010 to incorporate the requirements of this section into an integrated system plan established under RCW 80.86.020.

Findings—Intent—Effective date—2024 c 351: See notes following RCW 80.86.010.

Finding—Intent—2023 c 229: "(1) The legislature finds that the electric power system serving Washington will require additional high voltage transmission capacity to achieve the state's objectives and legal requirements. Washington must reduce its greenhouse gas emissions under state law, and the 2021 state energy strategy finds that this will require a significant increase in the use of renewable or nonemitting electricity in place of fossil fuels now used in the transportation, industry, and building sectors.

(2) The legislature anticipated the crucial role of additional transmission capacity in 2019 in the enactment of the clean energy transformation act and directed the energy facilities site evaluation council to convene a transmission corridors work group. The transmission corridors work group issued its final report on October 31, 2022, in which it confirmed the central role of transmission and recommended actions to achieve the expansion of transmission capacity to address this need.

(3) Expanded transmission capacity and the more effective use of existing transmission capacity will provide benefits to electricity consumers in the state by enhancing the reliability of the electric power system and increasing access to more affordable sources of electricity within the state and across the western United States and Canada.

(4) Existing constraints on transmission capacity within the state already present challenges in ensuring adequate and affordable supplies of clean electricity. Of particular concern is the capability of the transmission system to deliver clean electricity into and within the central Puget Sound area.

(5) There are multiple issues that contribute to the challenge of making timely and cost-effective expansions of the high voltage transmission system. Among those challenges is the need for a more proactive transmission planning process using a longer planning period than current law requires. Transmission planning must reflect not just the requirements to connect individual generating resources to the grid but also the need to transfer electricity across the state and the west. Transmission planning must incorporate state policies and laws in planning objectives.

(6) Certain transmission projects are of significant state interest due to their impact on the access of multiple utilities and communities to gain access to clean, affordable electricity supplies and obtain electricity that is necessary to comply with state laws.

(7) The legislature intends and affirms that the option to use local government permitting processes remains available for transmission projects not subject to mandatory jurisdiction under RCW 80.50.060(2).

(8) Transmission projects typically take at least a decade to develop and permit. This timing presents particular challenges for achieving the state's greenhouse gas emissions reduction mandates, which include ambitious benchmarks as early as 2030. There is a need to accelerate the timeline for transmission development while still protecting other Washington values.

(9) Some electric utilities rely entirely or primarily on a contracted network transmission provider for required transmission services. These electric utilities may contribute to the objectives of this act by requesting that each provider of network transmission service to the utilities include the provisions of chapter 288, Laws of 2019 and chapter 70A.45 RCW as public policy mandates in the transmission service provider's transmission planning process." [ 2023 c 229 s 1.]

Intent—2021 c 300: See note following RCW 47.01.520.

Findings—Intent—Effective date—2019 c 288: See RCW 19.405.010 and 19.405.901.

Finding—Intent—2015 3rd sp.s. c 19: See note following RCW 39.35.010.

Findings—Purpose—2011 c 180: See note following RCW 80.80.010.

(1) Investor-owned utilities shall submit integrated resource plans to the commission. The commission shall establish by rule the requirements for preparation and submission of integrated resource plans.

(2) The commission may adopt additional rules as necessary to clarify the requirements of RCW 19.280.030 as they apply to investor-owned utilities.

(1) The governing body of a consumer-owned utility that develops a plan under this chapter shall encourage participation of its consumers in development of the plans and progress reports and approve the plans and progress reports after it has provided public notice and hearing.

(2) Each consumer-owned utility shall transmit a copy of its plan to the department by September 1, 2008, and transmit subsequent progress reports or plans to the department at least every two years thereafter. The department shall develop, in consultation with utilities, a common cover sheet that summarizes the essential data in their plans or progress reports.

(3) Consumer-owned utilities may develop plans of a similar type jointly with other consumer-owned utilities. Data and assessments included in joint reports must be identifiable to each individual utility.

(4) To minimize duplication of effort and maximize efficient use of utility resources, in developing their plans under RCW 19.280.030, consumer-owned utilities are encouraged to use resource planning concepts, techniques, and information provided to and by organizations such as the United States department of energy, the Northwest planning and conservation council, Pacific Northwest utility conference committee, and other state, regional, national, and international entities, and, for the 2008 plan, as appropriate, are encouraged to use and be consistent with relevant determinations required under Title XII - Electricity; Subtitle E, Sections 1251 - 1254 of the federal energy policy act of 2005.

The department shall review the plans of consumer-owned utilities and investor-owned utilities, and data available from other state, regional, and national sources, and prepare an electronic report to the legislature aggregating the data and assessing the overall adequacy of Washington's electricity supply. The report shall include a statewide summary of utility load forecasts, load/resource balance, and utility plans for the development of thermal generation, renewable resources, conservation and efficiency resources, and an examination of assessment methods used by utilities to address overgeneration events. The commission shall provide the department with data summarizing the plans of investor-owned utilities for use in the department's statewide summary. The department shall submit any reports it receives of existing and potential combined heat and power facilities as reported by utilities to the Washington State University extension energy program for analysis. The department may submit its report within the biennial report required under RCW 43.21F.045.

Finding—Intent—2015 3rd sp.s. c 19: See note following RCW 39.35.010.

(1) At least once every twelve months, the department and the commission shall jointly convene a meeting of representatives of the investor-owned utilities and consumer-owned utilities, regional planning organizations, transmission operators, energy analytics experts at Pacific Northwest national laboratory, and other stakeholders to discuss the current, short-term, and long-term adequacy of energy resources to serve the state's electric needs, and address specific steps the utilities can take to coordinate planning in light of the significant changes to the Northwest's power system including, but not limited to, technological developments, retirements of legacy baseload power generation resources, and changes in laws and regulations affecting power supply options. The department and commission shall provide a summary of these meetings, including any specific action items, to the governor and legislature within sixty days of the meeting.

(2) In 2023, the meeting convened by the department and the commission pursuant to subsection (1) of this section must address strategies to ensure power supply adequacy to avoid the risk of rolling blackouts. The meeting must also focus discussion on the extent to which proposed laws and regulations may require new state policy for resource adequacy. The stakeholder meeting should seek to identify regulatory and statutory incentives to enhance and ensure resource adequacy and reliability. If regional energy analytics capability is established at Pacific Northwest national laboratory, the department and the commission must invite the Pacific Northwest national laboratory to the meeting to provide relevant analytics to inform the discussion.

(3) This section expires January 1, 2031.

Finding—2023 c 200: "The legislature finds that the electric grid is undergoing profound changes. Due to decreasing costs of renewable generation and policies like the clean energy transformation act, the grid is gradually evolving from one built to deliver to the customer electricity from centralized electric generation plants to one with variable energy resources like wind turbines and solar panels dispersed geographically across a broad landscape. As described in the 2021 Washington state energy strategy, the grid that our region is transitioning to will require greater transmission capacity and make greater use of energy storage and customer-side resources to manage the generation on the supply side.

As clean electricity replaces fossil fuels in the state's economy, the transmission and distribution infrastructure, the sticks and wires of the grid, must meet increasingly complex service requirements and loads. The changing demand includes, but is not limited to, population changes, vehicle charging, serving other specialized technology that requires high power quality, electrification of building-related end uses now served by fossil fuels, electricity deployed on the customer side of the meter through net metering, community solar programs, and the growth of demand response programs.

Further, the clean energy transformation act requires that utilities making investments in new resources after May 2019, rely on energy efficiency, demand response, renewable resources, and energy storage to the maximum extent feasible, while transitioning away from coal and natural gas-fired generation. Electric utilities are actively working to ensure resource adequacy through the development of explicit resource adequacy standards and a standardized resource adequacy program. This work is ongoing and should result in a binding and enforceable program with a robust public oversight mechanism. Understanding and addressing any energy adequacy challenges created by a deeply decarbonized grid is key to keeping the state's supply of electricity reliable." [ 2023 c 200 s 1.]

Finding—2020 c 63: "The legislature finds that the Northwest's power system is undergoing significant changes, including the retirement of baseload power generation resources, changes in hydroelectric output, and increases in distributed generation and variable renewable generation. Maintaining the adequacy, sufficiency, and availability of power supply to the growing populace in the Northwest is critical to the future of the region. Additional information sharing and coordination among utilities, planning entities, and state agencies is necessary to ensure that the region is adapting to the changing power system while maintaining the adequacy, sufficiency, and availability of the power supply for the region." [ 2020 c 63 s 1.]

(1) The legislature finds that combined heat and power systems provide both energy and capacity resources. Failure to assess the electric output of combined heat and power systems as both an energy and a capacity resource may result in a failure to account for the total benefits of that output in its posted price.

(2) Electric utilities with over twenty-five thousand customers in the state of Washington must value, pursuant to RCW 19.280.030, combined heat and power as having both energy and capacity value by December 31, 2016, for the purposes of setting the value of power under the federal public utility regulatory policies act, establishing rates for power purchase agreements, and integrated resource planning only if an assessment of combined heat and power identifies opportunities for combined heat and power that are dispatchable and that may provide capacity value.

Finding—Intent—2015 3rd sp.s. c 19: See note following RCW 39.35.010.

(1) The legislature finds that power purchase agreements of a minimum of fifteen years for the electric output of combined heat and power systems may be advantageous to both electric utilities and the owners or operators of combined heat and power systems.

(2) Electric utilities with over twenty-five thousand customers in the state of Washington are encouraged to offer a minimum term of fifteen years for new power purchase agreements for the electric output of combined heat and power systems beginning December 31, 2016.

(3) The commission may authorize recovery of the actual cost of fuel incurred by an electrical company under a power purchase agreement for the electric output of a combined heat and power system.

(4) The governing body of a consumer-owned utility that offers a fifteen-year minimum term for a power purchase agreement for the electric output of a combined heat and power system may, every five years after signing the agreement, initiate a fuel cost adjustment process in order to recover the actual cost of fuel incurred by the consumer-owned utility under a power purchase agreement under this section.

Finding—Intent—2015 3rd sp.s. c 19: See note following RCW 39.35.010.

The Washington State University extension energy program may electronically submit an annual report to the appropriate legislative committees on the planned and completed combined heat and power facilities in the state, including but not limited to the following information: Number, size, and customer base of combined heat and power installations in the state; projects that have been publicly considered but have not been developed; and recommendations to further attain the goal of improving thermal energy efficiency.

Finding—Intent—2015 3rd sp.s. c 19: See note following RCW 39.35.010.

(1) The legislature finds that the proliferation of distributed energy resources across the distribution system is rapidly transforming the relationships between electric utilities and their retail electric customers. The legislature finds that distributed energy resources planning processes will vary from one utility to another based on the unique characteristics of each system. However, distributed energy resources planning processes may allow electric utilities to better anticipate both the positive and negative impacts of this transformation by: Illuminating the interdependencies among customer-sited energy and capacity resources; identifying and quantifying customer values that are not represented in volumetric electricity rates; reducing, deferring, or eliminating unnecessary and costly transmission and distribution capital expenditures; maximizing system benefits for all retail electric customers; and identifying opportunities for improving access to transformative technologies for low-income and other underrepresented customer populations.

(2) Therefore, it is the policy of the state of Washington that any distributed energy resources planning process engaged in by an electric utility in the state should accomplish the following:

(a) Identify the data gaps that impede a robust planning process as well as any upgrades, such as but not limited to advanced metering and grid monitoring equipment, enhanced planning simulation tools, and potential cooperative efforts with other utilities in developing tools needed to obtain data that would allow the electric utility to quantify the locational and temporal value of resources on the distribution system;

(b) Propose monitoring, control, and metering upgrades that are supported by a business case identifying how those upgrades will be leveraged to provide net benefits for customers;

(c) Identify potential programs that are cost-effective and tariffs to fairly compensate customers for the actual monetizable value of their distributed energy resources, including benefits and any related implementation and integration costs of distributed energy resources, and enable their optimal usage while also ensuring reliability of electricity service, such as programs benefiting low-income customers;

(d) Forecast, using probabilistic models if available, the growth of distributed energy resources on the utility's distribution system;

(e) Provide, at a minimum, a ten-year plan for distribution system investments and an analysis of nonwires alternatives for major transmission and distribution investments as deemed necessary by the governing body, in the case of a consumer-owned utility, or the commission, in the case of an investor-owned utility. This plan should include a process whereby near-term assumptions, any pilots or procurements initiated in accordance with subsection (3) of this section or data gathered via current market research into a similar type of utility or other cost/benefit studies, regularly inform and adjust the long-term projections of the plan. The goal of the plan should be to provide the most affordable investments for all customers and avoid reactive expenditures to accommodate unanticipated growth in distributed energy resources. An analysis that fairly considers wire-based and nonwires alternatives on equal terms is foundational to achieving this goal. The electric utility should be financially indifferent to the technology that is used to meet a particular resource need. The distribution system investment planning process should utilize a transparent approach that involves opportunities for stakeholder input and feedback. The electric utility must identify in the plan the sources of information it relied upon, including peer-reviewed science. Any cost-benefit analysis conducted as part of the plan must also include at least one pessimistic scenario constructed from reasonable assumptions and modeling choices that would produce comparatively high probable costs and comparatively low probable benefits, and at least one optimistic scenario constructed from reasonable assumptions and modeling choices that would produce comparatively low probable costs and comparatively high probable benefits;

(f) Include the distributed energy resources identified in the plan in the electric utility's integrated resource plan developed under this chapter. Distribution system plans should be used as inputs to the integrated resource planning process. Distributed energy resources may be used to meet system needs when they are not needed to meet a local distribution need. Including select distributed energy resources in the integrated resource planning process allows those resources to displace or delay system resources in the integrated resource plan;

(g) Include a high level discussion of how the electric utility is adapting cybersecurity and data privacy practices to the changing distribution system and the internet of things, including an assessment of the costs associated with ensuring customer privacy; and

(h) Include a discussion of lessons learned from the planning cycle and identify process and data improvements planned for the next cycle.

(3) To ensure that procurement decisions are based on current cost and performance data for distributed energy resources, a utility may procure cost-effective distributed energy resource needs as identified in any distributed energy resources plan through a process that is price-based and technology neutral. Electric utilities should consider using competitive procurements tailored to meet a specific need, which may increase the utility's ability to identify the lowest cost and most efficient means of meeting distribution system needs. If the projected cost of a procurement is more than the calculated system net benefit of the identified distributed energy resources, the governing body, in the case of a consumer-owned utility, or the commission, in the case of an investor-owned utility, may approve a pilot process by which the electric utility will gain a better understanding of the costs and benefits of a distributed energy resource or resources.

(4) By January 1, 2023, the legislature shall conduct an initial review of the state's policy pertaining to distributed energy resources planning under this chapter. By January 1, 2026, and every four years thereafter, the legislature shall conduct a full review of the policy and determine how many electric utilities in the state have engaged in or are engaging in a distributed energy resources planning process, whether the process has met the eight goals specified under subsection (2) of this section, and whether these goals need to be expanded or amended.

(1) Electric utilities must in their planning and selection of renewable resources give reasonable consideration, consistent with prudent utility practice, to renewable resources that would use transmission services considered to be conditional firm under the tariff of the relevant transmission provider. For the purposes of this section, conditional firm service means any form of long-term firm point-to-point transmission service in which transmission customers are able to reserve service subject to specific and limited conditions under which the transmission provider may curtail the transmission customer's reservation of service prior to curtailment of other firm service.

(2) Electric utilities are encouraged to participate and contribute to statewide or multiutility planning activities and through interstate transmission planning processes.

(3) Electric utilities must consult with federal, interstate, and voluntary industry organizations with a role in the bulk power transmission system, including but not limited to the Bonneville power administration, the Pacific Northwest electric power and conservation planning council, NorthernGrid, the Western Power Pool, and public interest organizations in improving the planning and development of transmission capacity consistent with chapter 229, Laws of 2023.

Finding—Intent—2023 c 229: See note following RCW 19.280.030.