Clean Energy Transformation Act. In 2019, the Legislature passed the Clean Energy Transformation Act (CETA), which requires Washington's electric utilities to meet 100 percent of their retail electric load using non-emitting and renewable resources by January 1, 2045. CETA requires electric utilities to eliminate coal-fired resources from their allocation of electricity by December 31, 2025, and make all retail sales of electricity greenhouse gas neutral by January 1, 2030.

Integrated Resource Plans. All investor-owned and consumer-owned electric utilities in the state with more than 25,000 customers must develop integrated resource plans (IRPs). All other electric utilities in the state, including those that essentially receive all their power from the Bonneville Power Administration, must file either an IRP or a less-detailed resource plan (RP).

An IRP must include a number of components, such as the mix of generating resources and conservation and efficiency resources that will meet current and projected needs at the lowest reasonable cost to the utility and its ratepayers. IRPs and RPs must be updated every two years. Investor-owned utilities (IOUs) must submit their plans to the Utilities and Transportation Commission . Consumer-owned utilities (COUs) must file a copy of their plans with the Department of Commerce.

Clean Energy Action Plan.  IOUs and COUs with IRPs must also adopt a ten-year clean energy action plan for implementing CETA 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 its long-range IRP. 

Energy Facility Site Evaluation Council.  Created in 1970, the Energy Facility Site Evaluation Council (EFSEC) is the permitting and certifying authority for siting major energy facilities in Washington.  An EFSEC site certification agreement (SCA) authorizes an applicant to construct and operate an energy facility in lieu of permits or documents required by any other state agency or subdivision.  As part of the SCA process, EFSEC issues all state and federal air and water-discharge permits.

The Transmission Corridors Work Group. Under CETA, the Legislature directed the EFSEC to convene a Transmission Corridors Work Group (TCWG) to review the need for new or upgraded transmission to meet Washington’s renewable energy goals; identify where transmission and distribution facilities may need to be enhanced or constructed; and identify environmental review options and recommend ways to expedite review of transmission projects without compromising required environmental and cultural protection.

TCWG issued its final report in October 2022, and identified several key themes, including regional and interregional planning, staff resources in state agencies; enhanced resources for tribes; and pre-application planning and coordination.

National Environmental Policy Act. The National Environmental Policy Act (NEPA) was signed into law on January 1, 1970. NEPA requires federal agencies to assess the environmental effects of their proposed actions prior to making decisions. 

Electric Utility Integrated Resource Plans.  An IRP must include an assessment and 20-year, rather than 10-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 CETA and the state's emissions reduction limits. 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.

If an electric utility operates transmission rated 115,000 volts or greater, the transmission assessment must take into account opportunities to make more effective use of existing transmission capacity. An electric utility that relies entirely or primarily on a contract for transmission services may comply with the IRP transmission planning requirements by requesting that the counterparty to the contract include certain provisions of state law in the transmission service provider's process for assessing transmission need, and planning and acquiring transmission capacity.

Electric utilities may satisfy the IRP transmission assessment and 20-year forecast requirements through a separate assessment, individually or jointly with other utilities and transmission system users, if that assessment process meets the above requirements.

An IRP assessment, informed by the cumulative impact analysis, of energy and nonenergy benefits must include the avoidance as well as the reductions of budgets to vulnerable populations and highly impacted communities.

Electric utilities must 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. Conditional firm service, for this purpose, means any form of long-term firm point-to-point transmission service where transmission customers are able to reserve service, but the transmission provider may curtail the service under specific and limited conditions prior to curtailment of other firm service. 

Electric utilities are encouraged to participate and contribute to statewide or multiutility planning activities and through interstate transmission planning processes. To improve the planning and development of transmission capacity, they must consult with federal, interstate, and voluntary industry organizations with a role in the bulk power transmission system. 

Clean Energy Action Plans. COUs with more than 25,000 customers must also provide the same information the IOUs had been required to provide in a clean energy action plan, such as:  

• identify and be informed by the utility's ten-year cost-effective conservation potential assessment; 
• establish a resource adequacy requirement; 
• identify the potential cost-effective demand response and load management programs, renewable resources, nonemitting electric generation, and distributed energy resources that may be acquired; and 
• identify the nature and possible extent to which the utility may need to rely on alternative compliance options under CETA.

When identifying any need to develop new, or expand or upgrade existing bulk transmission and distribution facilities, the clean energy action plan must document existing and planned efforts by the utility to make more effective use of existing transmission capacity and secure additional transmission capacity consistent with its IRP. 

Energy Facility Site Evaluation Council Certification. EFSEC certification is required for construction, reconstruction, or enlargement of new or existing electrical transmission facilities that are: 

• of a nominal voltage of at least 500,000 volts alternating current or 300,000 volts direct current; 
• located in more than one county; and 
• located in the Washington service area of more than one retail electric utility. 

The EFSEC director must coordinate state agency participation in environmental review under NEPA for electrical transmission projects proposed or sited by a federal agency. 

The reference to the National Energy Policy Act of 2005 is updated. 

Nonproject Environmental Impact Statements. EFSEC must prepare nonproject environmental impact statements (EISs) that assess and disclose the probable significant adverse environmental impacts and identify related mitigation measures for electrical transmission facilities 230 kilovolts or greater.
 
The scope of a nonproject environmental review is limited to geographic areas that are suitable for these electrical transmission facilities. EFSEC may consider standard attributes for likely development, proximity to existing transmission or complementary facilities, and planned corridors for transmission capacity construction, reconstruction, or enlargement.
 
The scope of nonprojects EIS must consider, as appropriate, an analysis of direct and indirect cumulative impacts to:

• historic and cultural resources;
• protected wildlife or endangered species under current law;
• landscape scale habitat connectivity and wildfire migration corridors;
• environmental justice and overburdened communities;
• cultural resources and elements of the environment relevant to tribal rights, interests, and resources;
• land uses, including agricultural and ranching uses; and
• military installations and operations.

 
Nonproject EISs must identify measures to avoid, minimize, and mitigate probable significant adverse environmental impacts, including elements of the environment; tribal rights, interests, and resources; and overburdened communities. EFSEC must consult with other agencies with expertise in identification and mitigation of probable significant adverse environmental impacts, including the Department of Fish and Wildlife. EFSEC must specify when probable significant adverse environmental impacts cannot be mitigated.
 
When EFSEC defines the scope of nonproject review of the transmission facilities, it must request input from agencies, federally recognized Indian tribes, industry, stakeholders, local governments, and the public to identify the suitable geographic areas based on the climatic and geophysical attributes conducive to or required for project development. EFSEC must provide opportunities for engagement in the process.
 
EFSEC must offer early and meaningful consultation with any affected federally recognized Indian tribe on nonproject reviews for the purpose of understanding potential impacts to tribal rights and resources. Consultation is independent of, and in addition to, any public participation process required by state law or a state agency. The goal of the consultation process is to support the nonproject review by early identification of tribal rights, interests, or resources potentially affected by the project type and to identify solutions, when possible, to avoid, minimize, or mitigate any adverse effects on tribal rights, interests, or resources based on environmental or permit review.
 
Final nonproject environmental review documents for the transmission facilities must include maps that illustrate probable significant impacts and areas where impacts are avoided or capable of being minimized or mitigated, creating a tool to inform decision-making. Maps may not include confidential information.
 
The reasonable alternatives analysis is limited to the proposed action and a no action alternative for transmission line projects and transmission projects using an existing transmission right-of-way and transmission line projects located along a transportation corridor.
 
A lead agency conducting a project-level environmental review for transmission facilities with 230 kilovolts or greater must begin with a review of the applicable nonproject EIS. The review must address any probable significant adverse environmental impacts associated with the proposal that were not analyzed in the nonproject EIS. The review must identify any mitigation measures specific to the project for probable significant adverse environmental impacts.
 
Lead agencies reviewing site-specific project proposals for transmission facilities must use the nonproject review according to law and through one of the following methods:

• use of the nonproject review unchanged, if the project does not cause probable significant adverse environmental impact not identified in the nonproject review;
• preparation of an addendum;
• incorporation by reference; or
• preparation of a supplemental EIS.

 
Transmission facility proposals following recommendations from a nonproject EIS review must be considered to have mitigated probable impacts unless the project-specific environmental review identifies impacts not addressed in the nonproject EIS.