Washington Code 19.280.030 – Development of a resource plan — Requirements of a resource plan — Clean energy action plan
Current as of: 2023 | Check for updates
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Each electric utility must develop a plan consistent with this section.
Terms Used In Washington Code 19.280.030
- Assets: (1) The property comprising the estate of a deceased person, or (2) the property in a trust account.
- Contract: A legal written agreement that becomes binding when signed.
- Equitable: Pertaining to civil suits in "equity" rather than in "law." In English legal history, the courts of "law" could order the payment of damages and could afford no other remedy. See damages. A separate court of "equity" could order someone to do something or to cease to do something. See, e.g., injunction. In American jurisprudence, the federal courts have both legal and equitable power, but the distinction is still an important one. For example, a trial by jury is normally available in "law" cases but not in "equity" cases. Source: U.S. Courts
- Jurisdiction: (1) The legal authority of a court to hear and decide a case. Concurrent jurisdiction exists when two courts have simultaneous responsibility for the same case. (2) The geographic area over which the court has authority to decide cases.
(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 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) Plans shall not be a basis to bring legal action against electric utilities.
(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.
[ 2023 c 229 § 2; 2021 c 300 § 3; 2019 c 288 § 14; 2015 3rd sp.s. c 19 § 9; 2013 c 149 § 3; 2011 c 180 § 305; 2006 c 195 § 3.]
NOTES:
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 § 1.]
Intent—2021 c 300: See note following RCW 47.01.520.
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.