Session Recap

Energy & The Grid Committee

79th CSG West Annual Meeting
Salt Lake City, Utah

Introduction

As global energy demand accelerates, Western states are navigating a fast-moving convergence of supply constraints, aging infrastructure, and rising public scrutiny over cost. The CSG West Energy & The Grid Committee’s session during the 79th Annual Meeting in Salt Lake City, co-chaired by Alaska Representative Maxine Dibert and Wyoming Senator Dan Dockstader, brought together four presenters to address two central questions: what role natural gas still plays in meeting Western energy demand, and what it will take to modernize the transmission system that carries power across the region.

Opening the session, the co-chairs noted that demand is outstripping supply due to population growth, industrial expansion, data center development, and electrification, and framed the core challenge for policymakers as keeping energy reliable and affordable while working with infrastructure built for a different era.

Natural Gas: Supply Innovation and Growth Tradeoffs

Elena Sudduth, General Manager of Interior Alaska Natural Gas Utility (IGU) in Fairbanks, described the operating reality behind her utility’s supply model. Temperatures routinely drop to -50°F across a service area nearly the size of New Jersey, and Fairbanks ranks among the five worst U.S. metro areas for PM2.5 air quality, driven largely by wood heating. Despite 60 years of pipeline discussions, Fairbanks still has no natural gas pipeline; the utility instead trucks liquefied natural gas roughly 500 miles down the Dalton Highway from the North Slope.

Deliveries began in October 2025, marking the first time North Slope gas has ever reached homes off the Slope. The resulting residential rate—about $24.88 per MCF (thousand cubic feet), compared with roughly $5 per MCF elsewhere—reflects the cost of liquefaction, long-haul trucking, and storage, but gas remains cheaper and cleaner than the heating oil it displaces. IGU’s 5.5 million gallons of storage capacity, covering 30-plus days of peak demand, allows a single weather-vulnerable highway to reliably serve life-safety heating load. Ms. Sudduth also noted Alaska is weighing a longer-term 800-mile pipeline from the North Slope to the south coast, but that project only pencils out economically if the gas is exported to Asian markets, since in-state demand alone cannot justify the multibillion-dollar investment.

*Elena Sudduth speaks with audience members during the Energy & The Grid Committee session. Photos by Nathanael Peterson*.

Bear Prairie, CEO of Lower Valley Energy, a Wyoming and Idaho-based electric and gas cooperative founded in 1937, presented a contrasting picture of resource abundance: the co-op’s power supply is 95 percent carbon-free hydro sourced from the Bonneville Power Administration, supporting one of the lowest electric cooperative rates in the nation. However, Mr. Prairie was direct about the cost and permitting pressures behind that reliability, namely that utility equipment costs like transformers and trucks have doubled since 2018, and a 48-mile gas pipeline in his service territory took eight years to permit and remains in litigation.

He framed natural gas specifically as a “peaking” solution that lets the co-op meet extreme winter demand without building large high-voltage transmission lines through environmentally sensitive mountain terrain. Mr. Prairie advocated for an “all-of-the-above” resource strategy, noting that every energy infrastructure decision involves real tradeoffs utilities are responsible for balancing transparently. This includes providing affordable rates and reliable service, meeting growing community needs, demonstrating environmental stewardship, and engaging with those members who may oppose new power lines or gas pipelines.

Transmission: A Grid Under Strain

James Hanson, Manager of Operations Analysis at the Western Electricity Coordinating Council (WECC), presented data on the changing resource mix and reliability profile across the West’s 14 states. Coal capacity is projected to decline sharply through 2045 as solar, wind, and battery storage continue to rise.

As traditional generators are replaced by inverter-based resources, the grid’s spinning-mass inertia, its natural ability to recover from system events, is weakening. Notably, the West’s daily low point for grid inertia has shifted from early morning hours to midday between 2016 and 2025, reflecting solar displacement rather than simple resource retirement.

Mr. Hanson also flagged an emerging risk from demand-side behavior: time-of-use rate structures can create sudden “step changes” in load, such as when large numbers of electric vehicles begin charging simultaneously at midnight, unnecessarily stressing the system. Demand growth itself is accelerating as annual demand is now forecast to grow 25 percent over the next decade, up from a 20 percent forecast a year ago, driven substantially by data centers, which can be built in 18 to 24 months while the generation and transmission needed to serve them take far longer to permit and construct.

*James Hanson, Manager of Operations Analysis at the Western Electricity Coordinating Council*.

Brian Dudeck, Director of Development at Grid United, framed the region’s transmission buildout challenge around three areas: planning, permitting, and paying. On planning, no single body coordinates transmission planning across the full Western Interconnection; utilities plan within their own balancing authorities, creating “seams” that prevent power from moving easily between regions.

The Western Power Pool’s WestTEC process, endorsed by eleven governors in June 2026 and Wyoming’s SF0102 (Wyoming Energy Transmission Study) were cited as emerging models. On permitting, Mr. Dudeck noted that with 64 percent of land in states like Utah under federal ownership, projects almost always trigger long National Environmental Policy Act (NEPA) reviews; he cited the North Plains Connector as a success story for early coordination between Montana and federal agencies and pointed to a U.S. Department of Energy (DOE) coordination tool aimed at a two-year federal review timeline for transmission projects.

On paying, Mr. Dudeck emphasized the importance of low-cost capital. The North Plains Connector’s $700 million federal GRIP grant was the catalyst that brought utility partners on board and lowered costs for ratepayers—alongside state-level tools like Idaho’s Energy Resources Authority and the CREPC Order 1920 committee’s June 2026 cost-allocation proposals to Federal Energy Regulatory Commission.

*Brian Dudeck (foreground,) Director of Development at Grid United*.

*From left: CSG West Director Edgar Ruiz; Energy & The Grid Committee Co-Chairs Alaska Representative Maxine Dibert and Wyoming Senator Dan Dockstader.*

Key Takeaways for State Policymakers

Storage, not just supply, is the resilience asset. Alaska’s model shows a single vulnerable supply route can reliably serve critical heating load if paired with sufficient storage, a principle applicable beyond natural gas.

Export markets, not in-state demand, may determine whether major new gas infrastructure pencils out. Alaska’s proposed 800-mile North Slope pipeline is only economically viable with Asian export demand, a reminder that the business case for large capital projects may hinge on factors outside a state’s borders.

Permitting timelines are a material cost driver, not just a delay. A 48-mile gas pipeline in Wyoming and Idaho took eight years to permit and remains in litigation, while equipment costs have doubled since 2018. Both factors compound the cost of growth for ratepayers.

Grid vulnerability windows are shifting, and new ones are emerging. Rising solar penetration is moving the West’s lowest-inertia hours from early morning to midday, while synchronized EV charging under time-of-use rates can create sudden load “step changes.” Both are relevant to rate design and reliability planning.

Infrastructure timelines are badly mismatched with demand timelines. Data centers can be sited and built in 18–24 months; the generation and transmission needed to serve them take years longer to permit and construct. This is a gap legislatures should expect to keep widening.

States do not need to wait on a regional planning authority to act. Participating in existing coordination bodies (WestTEC, PACT, CREPC) and clarifying Integrated Resource Plans (IRP) and siting processes are actions states can take now.

States hold permitting leverage even on federally entangled projects, especially where federal land ownership is high. In Utah, for example, 64 percent of land is federally owned. Synchronizing state and federal review timelines, as Montana has done, can meaningfully shorten project timelines without new statutory authority.

Federal grant capital can be a catalyst, not just a subsidy. The North Plains Connector’s $700 million federal GRIP grant was what brought utility partners to the table and lowered costs for ratepayers. This is a model other states may be able to replicate for their own priority projects.

Cost allocation is now a political issue, not just a technical one. With utility bills drawing national media attention, legislatures should track the CREPC/FERC cost-allocation process and consider engaging early.

*Legislators and audience members at the Energy & The Grid Committee session.*

Looking Ahead

The members of the committee closed the session by identifying regional legislative coordination, specifically, how states can work across borders to support shared transmission infrastructure, as a likely focus for future discussions. Moreover, members expressed interest learning more and engaging with the Wester Power Pool’s WestTec process.