Integrated Resource Plans and Clean Energy Action Plans.
Investor-owned electric utilities and consumer-owned electric utilities with 25,000 or more customers that are not fully served by the Bonneville Power Administration (BPA) must develop Integrated Resource Plans (IRPs). Utilities with fewer than 25,000 customers, or that are fully served BPA customers, must either file an IRP or complete a less-detailed resource plan. An IRP must be updated at least every four years by statute and the Utilities and Transportation Commission requires updated IRPs every odd-numbered year.
Of the multiple requirements for IRPs, a utility must include an assessment and 10-year forecast of the availability of regional generation and transmission capacity on which the utility may rely on to provide and deliver electricity to its customers.
Clean Energy Action Plans.
The Clean Energy Transformation Act (CETA) of 2019 required utilities to include within their IRPs a 10-year Clean Energy Action Plan with specific actions to be taken by the utility to implement the following CETA standards: (1) eliminate coal-fired resources from their allocation of electricity by the end of 2025; (2) ensure that all retail sales of electricity to Washington customers are greenhouse gas neutral by the beginning of 2030; and (3) supply 100 percent of retail electricity to Washington customers with nonemitting and renewable resources by the beginning of 2045.
One of a utility's requirements for Clean Energy Action Plans is that they must identify any need to develop new, or expand or upgrade existing, bulk transmission and distribution facilities.
The Energy Facility Site Evaluation Council.
The Energy Facility Site Evaluation Council (EFSEC) provides a single siting process for the construction, reconstruction, and enlargement of certain energy facilities located in the state. The EFSEC coordinates all evaluation and licensing steps for siting certain energy facilities, as well as specifies the conditions of construction and operation. After evaluating an application, the EFSEC submits a recommendation either approving or rejecting an application to the Governor, who makes the final decision on site certification. If approved by the Governor, a site certification agreement is issued in lieu of any other individual state or local agency permits.
Energy Facilities Covered Under Energy Facility Site Evaluation Council Laws.
Certain facilities are required to participate in the EFSEC process, while others may opt in. Facilities that must seek certification through the EFSEC process include energy plants such as nuclear power facilities, facilities that receive and store natural gas, facilities that process petroleum, biorefineries, and electrical transmission facilities, with many size and other specifications. The facilities that may opt in to the EFSEC's processes include clean energy product manufacturing facilities, storage facilities, all types of renewable natural gas facilities, and renewable and green electrolytic hydrogen energy facilities.
The EFSEC is the state authority for purposes of siting electrical transmission facilities, which are electrical power lines and related equipment. The preapplication requirements for electrical transmission facilities involve a process that includes public hearings and consideration of any corridors designated for transmission by local jurisdictions. Where there are no corridor designations by local jurisdictions, the applicant must attempt to reach agreement with local jurisdictions on a corridor plan. If no corridor plan is agreed upon, the applicant must propose a recommended corridor for the electrical transmission facilities and the EFSEC must consider the applicant's proposed corridor when making a recommendation.
The EFSEC's authority is limited to approving the siting of the construction, reconstruction, or modification resulting in a significant change of electrical transmission facilities that are located in a national interest electric transmission corridor as designated by the Secretary of the United States Department of Energy.
Applicants for an electrical transmission facility may opt in to participating in the EFSECs processes if that electrical transmission facility is:
State Environmental Policy Act and Nonproject Environmental Impact Statements.
The State Environmental Policy Act (SEPA) establishes a review process for state and local governments to identify environmental impacts that may result from governmental decisions, such as the issuance of permits or the adoption of land use plans. The SEPA environmental review process involves a project proponent or the lead agency completing an environmental checklist to identify and evaluate probable environmental impacts. If an initial review of the checklist and supporting documents results in a determination that the government decision has a probable significant adverse environmental impact, known as a threshold determination, the proposal must undergo a more comprehensive environmental analysis in the form of an Environmental Impact Statement (EIS). If the SEPA review process identifies significant adverse environmental impacts, the lead agency may deny a government decision or may require mitigation for identified environmental impacts.
The SEPA rules lay out the specifics for how a nonproject EIS may be conducted and then used for a specific project. A nonproject EIS is essentially an upfront, pre-project environmental analysis of the types of environmental impacts that could be expected from a type of governmental decision. Under the rules, when a lead agency prepares an EIS on a nonproject proposal, the lead agency has less detailed information available on environmental impacts and the environmental impacts of any subsequent project proposals that may follow the EIS. The lead agency's nonproject EIS discusses impacts and alternatives in the level of detail appropriate to the scope of the proposal and the level of planning for the proposal. If a specific geographic area is the focus of a nonproject EIS, site specific analyses are not required but may be included for specific areas of concern. After the approval of a nonproject EIS by the lead agency, when a project is proposed that is consistent with the nonproject EIS, the EIS for the project proposal must focus on the impacts and alternatives, including mitigation measures, that are specific to the subsequent project and that were not analyzed in the nonproject EIS. The SEPA procedures allow for the adoption and use of portions of the nonproject EIS in a subsequent project-level SEPA review. Lead agencies must, at the time of a project-level SEPA review, evaluate the nonproject EIS that was previously completed to ensure that the nonproject analysis is valid when applied to the current proposal, knowledge, and technology. If a nonproject EIS's analysis is no longer valid, the analysis must be reanalyzed in the project-level EIS.
Extended Forecast and New Transmission Assessment Requirements for Integrated Resource Plans.
The length of time for an electric utility's required forecast of its generation and transmission capacity is increased from 10 to 20 years in the Integrated Resource Plan (IRP) requirements.
A utility's transmission assessment requirements are expanded so that it must take into account: (1) the requirements of the Clean Energy Transformation Act (CETA); (2) the changes made to the Energy Independence Act (EIA) in 2019; (3) the state's greenhouse gas emissions reduction limits; and (4) the utility's expected needs to acquire new long-term firm rights, develop new, or expand or upgrade existing bulk transmission facilities.
For electric utilities that operate transmission assets of 115,000 volts or more, the transmission assessment must also 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.
For electric utilities that rely entirely or primarily on a contract for transmission service, the utility may comply with the transmission assessment and 20-year forecast requirements by requesting that the counterparty to their contract include the following public policy mandates in the transmission provider's process for assessing transmission need, and planning and acquiring transmission capacity: (1) the provisions of CETA; (2) changes made to the EIA in 2019; and (3) the state's greenhouse gas emissions reduction limits. Electric utilities may also comply with the transmission assessment and 20-year forecast requirements through a separate transmission assessment process, as long as that process meets the same requirements.
Another required assessment in the IRP, which in part directs utilities to assess the reduction of burdens to vulnerable populations and highly impacted communities, is modified so that the utility must also assess the avoidance of burdens to these groups.
Documentation of Transmission Efforts in Clean Energy Action Plans.
An electric utility's 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 the requirements of its transmission assessment and 20-year forecast in its IRP.
A requirement is removed that the Department of Commerce and the Utilities and Transportation Commission adopt rules to establish the requirements for incorporating a cumulative impact analysis for developing Clean Energy Action Plans by 2021.
Energy Facility Site Evaluation Council Siting.
The Energy Facility Site Evaluation Council (EFSEC) must now oversee the siting of additional transmission facilities, specifically the construction, reconstruction, or enlargement of new or existing electrical transmission facilities that are:
For projects proposed or sited by a federal agency, the Director of the EFSEC must coordinate state agency participation in environmental review under the National Environmental Protection Act.
Nonproject Environmental Impact Statements for Transmission Facilities.
The EFSEC must prepare nonproject Environmental Impact Statements (EISs) for transmission facilities with 230 kilovolts or more, with specified requirements for the content and development of the scope of these nonproject EISs. For example, the EFSEC must examine areas that are suitable for transmission facilities of at least 230 kilovolts or greater, and then consider impacts on historic and cultural resources, endangered species, landscape habitat connectivity and wildlife migration corridors, environmental justice and overburdened communities, cultural resources relevant to tribes, agricultural and ranching land uses, and military installations. The nonproject EISs must identify measures to avoid, minimize, and mitigate any identified probable significant adverse impacts.
In defining the scope of these reviews, the EFSEC must consult with other agencies, including the Department of Fish and Wildlife, industry, stakeholders, local governments, and the public, and must offer early and meaningful consultation with affected federally recognized Indian tribes. The EFSEC must also prepare maps to illustrate probable impacts and areas where impacts are avoided or can be minimized or mitigated.
For transmission projects that are in an existing transmission right of way or corridor, the required environmental review of alternatives is limited to two alternatives: the proposed action and no action.
When conducting a specific project-level review of a transmission facility of 230 kilovolts or greater, a lead agency must consider the nonproject EIS prepared by the EFSEC. The specific project-level review must analyze any probable significant impacts that were not analyzed in the nonproject EIS, and depending on whether impacts are assessed, a lead agency must take steps to adopt the nonproject EIS or do further review in the form of an addendum or 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.
Requirement for Electric Utilities to Consider Conditional Firm Transmission Services.
Electric utilities must reasonably consider conditional firm transmission services in planning and selecting renewable resources.
Conditional firm service is defined in the bill as any form of long-term firm point-to-point transmission service in which transmission customers can reserve service, subject to certain conditions under which the transmission provider may curtail the transmission customer's reservation before curtailing other firm service.
Additional Transmission Consultation and Participation.
To improve the planning and development of transmission capacity, electric utilities must consult with at least the following federal, interstate, and voluntary industry organizations with a role in the bulk power transmission system: (1) the Bonneville Power Administration; (2) the Pacific Northwest Electric Power and Conservation Planning Council; (3) NorthernGrid; (4) the Western Power Pool; and (5) public interest organizations.
Utilities are also encouraged to participate and contribute to statewide or multiutility planning activities and interstate transmission planning processes.
(In support) Thoughtful transmission planning will help ensure the state meets its obligations and that there is consistent, renewable, and reliable energy. The Clean Energy Transformation Act (CETA), the Climate Commitment Act, and other state energy policies are driving greater electricity demand, driving greater transmission demand and distribution capacity needs, so it is important to improve transmission planning. Transmission is almost fully subscribed and takes decades to develop, which is making it difficult for the state to meet its goals to transition to clean power. It is taking double the amount of time for wind, solar, and battery projects to connect to the grid as it did 10 years ago, and wait times are growing. The Bonneville Power Administration (BPA) has about the same amount of transmission lines as it had in 1975, which are not keeping up with demand, and the BPA recognizes this. Utilities have been increasing the use of renewable energy at record levels since the passage of CETA, but still need a significant scale of renewable power to meet CETA's requirements. The more robust Integrated Resource Plan requirements are reasonable to make sure utilities are prepared for electrification. Utilities are already doing a lot of this work, but this will increase consistency, and is not unduly burdensome. The long-term planning components ensures that there will be meaningful planning for the next generation. This dovetails well with ongoing conversations utilities are having with the BPA, especially as utilities approach their 2028 long-term contract with the BPA.
The striking amendment addresses the primary concern with the substitute bill; the BPA manages transmission for many utilities who have no transmission planning expertise, so the striking amendment exempts these utilities from transmission planning activities. This bill and the striking amendment incorporate feedback from stakeholders and address concerns with previous versions of the bill. The striking amendment is a significant improvement. The striking amendment is critical for driving job creation because it improves the siting process, and it will help create good family wage jobs across the state. The state needs adequate transmission capacity and the ability to connect storage and generation projects to the grid for the job creation and economic development, which should be part of the clean energy transition. We need access to a diversity of supply of renewable-generating resources across the western United States to make firm power. This bill will improve reliability and reduce costs compared to other alternatives.
The nonproject Environmental Impact Statements (EISs) will identify corridors to meet future energy needs, address the critical issue of transmission siting, and provide a streamlined and faster path for future transmission development. The two new sections on nonproject EISs will help transmission developers navigate the challenging siting process. However, there should be completion dates for the nonproject EISs to ensure these reviews are done in a timely manner. Local elected boards should also receive the same attention as federally recognized Indian tribes. The language related to conditional firm and resource planning is workable. There is appreciation for language in the intent section that affirms the use of the local permitting process for transmission siting.
(Opposed) The Energy Facility Site Evaluation Council (EFSEC) does not incorporate input from local governments, it only accepts their input. The bill includes much more detail for how the EFSEC must consult with federally recognized Indian tribes than for how the EFSEC must engage with local governments. Local governments know exactly what works best for natural resources. Local governments have agricultural land that they are supposed to protect but that has been sited for the solar industrial complexes. At a minimum, the EFSEC should consult with local governments in the same way as with federally recognized Indian tribes.