Oregon Policy Academy Retreat on Energy Transmission

On May 20-21, the Oregon Department of Energy, in partnership with the National Governors Association (NGA) and the office of Gov. Tina Kotek convened a meeting to discuss challenges and potential solutions to upgrading and expanding transmission infrastructure in Oregon.

The following is a summary of that meeting.

Four 'Ps' were identified to structure the retreat: Planning, Participation, Permitting, and Paying. The agenda involved a combination of large group discussion and small group interactive flip chart activities based on each of the 'Ps' to identify problems and potential solutions for each 'P' related to expansion of transmission.

The retreat participants and facilitators were asked to abide by "Chatham House Rules" whereby participants are encouraged to freely use the information and ideas they hear, but are asked to not share the identity, organization or affiliation to encourage candid dialogue and reduce power dynamics around ideas.

Several messages generated strong interest across the room. These included:

• urgency of getting transmission built at a time of rapidly rising demand for electricity, the role of transmission in accessing low-cost clean energy, and the link between transmission and prosperity
• need for leadership and bold action
• the importance of government-to-government engagement with Tribes, along with the need to communicate and consult with Tribes, as sovereigns, early and often
• a range of issues/barriers and a need for long-term solutions, rather than just incremental fixes

A key prompt and question throughout the retreat was: How can the state support needed transmission development? Several ideas surfaced, such as supporting:

• meaningful engagement and participation by Tribal governments, local governments, communities and the public
• clearer understanding and communication of benefits and burdens of transmission projects, as well as honest articulation of options for mitigation and compensation
• more dedicated staff, resources, expertise and consistency in permitting
• expedited projects while maintaining existing land and resource protections
• solutions to wildfire liability that address risk to transmission and ratepayers
• creation of a transmission entity with new authorities
• opportunities for agencies to prioritize and support transmission projects with new authorities that are within their existing structures

This readout summary provides more detailed highlights and key themes from the retreat discussion.

Background

The Oregon Department of Energy received a technical assistance award from the NGA Center for Best Practices to assist the state in sharing information and convening policy discussions to explore ways to expedite transmission infrastructure enhancement and expansion while avoiding, minimizing, and mitigating negative impacts on energy burden, natural and working lands, Tribal cultural resources and communities.

NGA is working with a core team (from Gov. Kotek's Office, Oregon Department of Energy, Oregon Public Utility Commission, Portland General Electric, and Renewable Northwest) who brought together utilities, independent transmission developers, independent power producers, Tribal representatives, local governments, advocacy organizations, and state agencies.

This technical assistance will continue into the fall. It will inform work pursuant to EO 25-29 and the Oregon Energy Strategy, and result in a roadmap to inform the 2027 legislative session, agency regulatory reform efforts, and electricity planning.

Transmission State of Play in Oregon

In November 2025, the state released the Oregon Energy Strategy, which highlights the need for more reliable, affordable and clean electricity by expanding the electricity system and incorporating load flexibility while minimizing and mitigating negative impacts on customer energy burden, natural and working lands, Tribal cultural resources and communities.

At the same time, industry and regional partners in planning, expanding, and operating the electricity system have collaborated on a West-wide transmission expansion study via the Western Transmission Expansion Coalition (WestTEC). In January 2026, WestTEC released the results of a 10-year transmission expansion study, which has shown that the Western region of the U.S. needs more than 12,600 miles of high-voltage transmission system expansion and upgrades to meet the region's forecasted energy needs - including to integrate new loads, connect new generation, and support regional electricity markets for increased reliability and affordability through 2035. A 20-year expansion study is expected in the fall.

Relatedly, Gov. Kotek's Executive Order 25-29 directs state agencies to align their decisions, activities, and investments as appropriate to advance the five least-cost pathways in the Oregon Energy Strategy, which includes accelerating investment in and deployment of least-cost and least-risk clean energy and grid infrastructure.

Planning

Identifies why, where, how and when a transmission system expansion or upgrade project needs to occur. The primary motivations for transmission expansion are to maintain grid reliability, improve the economics of grid operations and meet public policy goals. This process relies on studies, forecasts and other inputs to determine the need and cost-effectiveness of proposed transmission infrastructure. Building consensus on a holistic regional or statewide transmission plan is difficult. Utilities and the Bonneville Power Administration conduct their own planning; competitive developers seek commercial opportunities; and local, state and federal authorities play regulatory and other roles. The lack of a national planning process further creates variations across regions of the country.

Highlights of Discussion:

• There is a lot of good planning already occurring - through "local" utility transmission planning (e.g. BPA, PGE, Pacificorp) as well as broader regional planning (NorthernGrid, WestTec), but the state may benefit from better understanding the need for transmission lines and prioritizing some local and regional lines.
• It could be helpful to have more details on the potential benefits and motivations (beyond just "load growth" and "reliability") to help communities understand benefits and build trust.
• Tribes are sovereigns, and acknowledging and engaging with them as such early in the process is important to a successful transmission planning process.
• Participants discussed greater coordination across planning processes and having greater involvement with Tribes with a stronger understanding of Treaty rights. Greater coordination could support collaboration and co-location across systems to reduce impacts.
• Participants discussed how planning and permitting could better dovetail . Planning won't necessarily solve any specific project's permitting issues, but planning can help increase transparency, education, participation and prioritization of projects. There were also points made about the need for large loads like data centers to more transparently participate in transmission planning processes. A key question in utility transmission planning was whether the line could be built in time for the needs that were assumed during the planning process.
• There were questions about whether planning starts with co-location ideas first. There was interest in expanding lines in current corridors (such as existing transmission corridors or other existing linear corridors like rail and roads). Co-location and transmission expansion could occur within a city, county, state, or across multiple states. There was discussion about incentivizing co-location and streamlining in the planning process (as well as permitting process) to encourage co-location. This would be important for both transmission and distribution lines.
• There were questions raised about how batteries are treated in current planning processes, depending on whether they are co-located with generation or standalone batteries charged from the grid. There may be different treatment of batteries across transmission planning processes.
• There were questions and discussion about what a state role could be in facilitating coordination across planning processes through prioritization and clearer articulation of the "why" and benefits.
• There was discussion about a state transmission authority and a role it could play in prioritization, but that it would need stand-alone governance by a diverse board. There was discussion about ensuring prioritization isn't politicized but rather based on objective criteria.

Lunch Presentation on The Western Transmission Consortium (TWTC)

TWTC is a member-owned entity seeking to fill funding gaps and build interregional and interjurisdictional transmission infrastructure across the 11western states.

It builds on planning efforts underway at WestTEC and involves different business models (investor-owned utility, public power, independent transmission companies) working together.

Learn more: The Western Transmission Consortium

Participation

Addresses public engagement in transmission project proposals. While oftenconsidered part of permitting, it is recognized here as a standalone component of the transmission development process that can occur from very early in the planning phase through permitting and construction. Rising public interest in decarbonization, environmental justice, sustainable land use, and related topics correlates to growing community involvement in transmission infrastructure at the same time that transmission projects often surface concerns over community and landowner impacts. Without support from local communities, affected landowners, and resource protection groups, major projects may be defeated in public referendums, or stalled or denied as a result of legal challenges or decisions by local policymakers. Participation can also help address conflicts, steering projects toward least-conflict solutions, helping to avoid, minimize, and mitigate impacts with the help of local expertise.

Highlights of Discussion:

• There was acknowledgement that there is already participation in planning and permitting processes, which often include public meetings with notice and comment periods, but that these may not be making the connection to community understanding of and agreement with the need for a project as well as within a broader understanding of the societal benefits of the grid before a project is proposed.
• There was also recognition that information may be shared later in the process, which can generate distrust and frustration over a project.
• There was discussion on early engagement and proactive communication to help build community understanding of a project - why it is happening, what the benefits are, what the impacts are, how to mitigate impacts, and being clear about what is possible.
• At the same time, there are risks to engaging too early if project details are not well known and communicated without key information about benefits and impacts as well as later changes to the project design creating distrust among communities.
• There was interest in hearing about transmission lines that were able to negotiate easements ahead of time with favorable terms that helped landowners feel financially whole or even part of a clean energy transition. There may be regulatory limitations on whether easement terms can include market rate, assessed rate, or anything above that for certain utilities.
• At the same time, transmission lines may need to use eminent domain and condemnation procedures for segments to be able to physically align and in the event where property owners are non-responsive or can't be found - but even if not used, these can be seen as backstops in negotiations.
• There was discussion about independent transmission companies may not have the ability to access eminent domain and condemnation - which can lead to different approaches. For example, because of their very limited ability to utilize eminent domain, independent developers have a greater incentive to offer property owners above market dollars for compensation.
• There was acknowledgement that people voicing strong concerns about a project may be experiencing impacts to their land or interests while comments about the broader public good or need aren't brought up as much. In particular, when there is distrust around the motivation and reasons behind potential development of transmission lines servicing load growth from data centers or loads in other communities and out of state. There was discussion about aligning what the state does on transmission policy with what the state does on data center policy going forward.
• There was discussion about partnering with non-profit groups that work on specific natural resources and sharing survey data and information, such as survey data about birds and habitat with groups seeking to protect them.
• There was discussion about how important it is to tailor language to speak to communities instead of "selling" to them. Some communities may not consider themselves "environmental justice" communities or have an interest in decarbonizing but love the natural landscape and do not want to see it change with infrastructure.
• There was also discussion about community benefit agreements in the context of generation projects as a tool to communicate proactively, understand community needs, and structure benefits to advance those needs especially in areas where there hasn't been economic growth and revenue to support schools and other services is limited. However, there weren't examples of community benefit agreements for transmission projects - rather the focus of the discussion centered on favorable terms for landowners in easement and right-of-way negotiations and examples of broader community grant programs with statewide non-profit organizations from the Grid United North Plains Connector Project.

Permitting

Permitting, which is often paired with siting, involves securing approvals from the requisite local, state, Tribal, and federal authorities before construction of transmission infrastructure may begin. It serves the purpose of ensuring that a transmission project will comply with environmental, land use, cultural resource, and other protections. Navigating the multiple statutory and regulatory requirements, which form a complicated and at times contradictory patchwork of policies, creates timing uncertainty and frequently delays the already years-long development process.

Highlights of Discussion:

• There was discussion of the value in having conversations with permitting authorities and communities early, as soon as transmission planners see them coming.
• There was also discussion about the difficulties of aligning processes across jurisdictions: Federal, Tribal, state, and local. Even after permitting, there are pre-construction activities that need to be accomplished to meet permitting requirements. The group discussed to what extent timelines could be better aligned across these processes, in particular when there may be different legal and evidentiary requirements that would need to be demonstrated in each process to withstand potential appeals.
• There was discussion about how a State Transmission Authority might have value beyond Oregon since it could be a vehicle for coordinating with neighboring states, Bonneville Power Administration, and federal agencies.
• Participants noted that Idaho has a state coordination role for energy projects, Wyoming has an energy authority, North Dakota has a transmission authority and infrastructure agency, Colorado has a transmission authority, New Mexico has a transmission authority, and Washington recently passed a law to create a new electricity transmission authority (WETA).
• There was discussion about how Goal 1 in Oregon Land Use Law is "citizen involvement" and that importance is seen in the Energy Facility Siting Council process as well. However, the contested case process can be difficult for people and community groups to engage in over a long period of time, and there was discussion on whether there are other ways to work out issues that do not involve a contested case.
• Projects that cross Tribal reservation boundaries and ceded lands need to work with Tribal agencies and their resource planning processes and seek approvals, which could include costs, economic development, watershed health, and other issues. There would also be consultation for projects crossing federal agency administered lands, such as U.S. Forest Service and Bureau of Land Management, as well as consultation about potential impacts to Treaty resources on ceded lands.
• There was discussion about transmission projects that had been prioritized in other states and therefore had adequate staff evaluating project applications as well as coordinating with other agencies and Tribes that had permitting decisions. Clear leadership, along with sufficient funding and agency staff, were necessary to carry out reviews and coordination in a timely manner. There was emphasis on the benefit of pre-application discussions, experienced staff, and dedicated staff for reviewing transmission applications.
• Other states and the federal government have overall project coordinators that understand all the key milestones and timelines for federal, Tribal, state, and local agencies to bring about alignment and decisions.
• There was discussion about agencies being risk-averse, which can show up as additional process steps, additional information requirements, or changes in agency requirements during the long-life of a transmission project to be able to withstand the likelihood of litigation. Prioritization, more staffing, and confidence in being able to defend tough decisions on priority projects were also discussed.
• There was discussion of complex permitting rules across agencies and jurisdictions and challenges in staff turnover. There can be different or inconsistent interpretation of rules that create confusion and stop/re-starts.
• There was discussion about whether an "opt-in" option for EFSC (by both developers as well as local governments) could be helpful for proposed projects that are complicated or may involve greater time and resources for project evaluation. There were also questions about whether information used in one permitting process could be used to comply with requirements from other permitting processes evaluating similar resources or issues.
• Most projects currently go through local permitting processes, not EFSC. There was discussion about the need to align review and permitting processes when there are multiple jurisdictions. There was also discussion around using more conditional use checkboxes with objective standards (yes/no). However, there was recognition that federal permitting alignment may still be an over-arching issue.
• There was discussion on ideas about simplifying re-permitting for a similar use and streamlining the Land Use Compatibility Statement. There was also mention of whether the "green corridor" rule (from LCDC) could help encourage collaboration across utilities and developers to use the same poles or corridor for their lines and reduce the number of overall lines needing to be built. There was also discussion about the benefit of reducing cumulative impacts to resources and landowners through co-location and use of existing corridors.
• There was discussion of State Land Use Goals and ideas to add goals around abating climate change and developing clean energy and transmission to help put grid needs on the same footing as other land uses.
• There was discussion about Oregon being part of an interconnected transmission system and the importance of engaging in multi-state, regional efforts to align and coordinate on transmission. There are a few regional efforts and discussions around multi-state permitting alignment and coordination around transmission development.

Paying

Refers to how much a project costs and how that cost is recouped. How a line is paid for depends on the jurisdictions and regulatory frameworks applicable to where a project is located, who benefits, and the business model of the entity constructing the line. A merchant transmission developer, which is an independent, for-profit company unaffiliated with an electric utility, pays for costs of a project by charging transmission service customers who voluntarily subscribe or "sign-up" for the use of certain amounts of transfer capacity provided by a project. For utility developed projects, costs incurred by utilities can be allocated to both its end-use "native load" customers through PUC-regulated cost-of-service rates and to transmission service customers through FERC-regulated transmission service rates. Both practices attempt to apportion costs commensurate with the benefits each type of customer receives. Ultimately, all transmission system costs are passed on to electricity consumers, most of whom are utility ratepayers. Determining who should pay for regulated transmission investments, and what portion of costs, is often referred to as "cost allocation." Because electricity is a public good/service, it is important to consider the need for a transmission project, the benefits it will deliver, as well as ways to minimize borrowing costs and mitigate risk.

Highlights of Discussion

• There was discussion about the various levers to finance a transmission line - but ultimately, ratepayers payfor these lines through their power bills. Three key levers to consider:
  • the entity/customer causing the load growth necessitating a new transmission line pays for it upfront,
  • use debt finance and pay back over time, e.g. federal/state government loans (low-risk, low-interest, highly subsidized but strictly regulated) or private market debt (higher-interest rates and more flexible, but subject to market volatility and strict credit constraints), and
  • There exist other mechanisms to help cover costs before project completion, including:
    • some combination of pre-collection of funds or subscriber increase rates to collect funds to build large-scale transmission projects. This can involve precollection of funds vs recovering cost through rate regulation. Precollection of funds are not possible for regulated utilities with a used/useful standard. Because of high upfront capital ($billions per project) and long operating lifespans (30 to 50+ years), developers typically use debt financing to spread out costs and risks. In addition, there has been more recent interest from data centers to directly pay for investments upfront.
• There was discussion about the differences between utility and independent transmission company approaches. For utilities, there are significant issues with debt financing due to wildfire liability concerns. Lenders want predictability and certainty, and it is currently a capital constrained environment for them.
• Rate recovery remains a key issue for investor-owned utilities. Large scale transmission investments present a large risk to Investor Owned Utilities already constrained with debt obligations.
• There was discussion about independent transmission companies securing long-term Transmission Service Agreements (TSAs) to reserve capacity or "buy space" on the proposed line, if a portion of the proposed line is unsubscribed/uncontracted, commercial banks reflect the risk of unreserved capacity by reducing the amount of debt they are willing to lend or increasing interest rates.
• There was discussion about New Mexico Renewable Energy Transmission Authority (RETA) partnering on a merchant transmission project through a build and transfer agreement. The project involved wind developers subscribing to the transfer capacity provided by the project, and these costs were then embedded into the power purchase agreement prices/costs of the energy contracts. Once energized, ratepayers would see those costs reflected in their power bills. RETA provided leadership and played a role in getting the project completed.
• There was discussion about how there is not a lack of capital, but rather variation in risk-profiles and a lack of certainty on projects that need to use debt finance.
• There was discussion about efforts in the federal government around permitting councils and Fast41 to help lower permitting risk by supporting coordination, agency responses, and addressing conflicts and issues.
• There was discussion on lowering wildfire risk with improved or more frequent vegetation management practices as well as other ideas around state insurer of last resort and more expansive homeowner insurance.
• There was also discussion about joint partnerships to help diversify and spread risk related totransmission projectsacross multiple entities.