Healy Power Plant is seen in this undated photo. (Image courtesy of Dan McIntosh)
Earlier this month, Golden Valley Electric Association held a community meeting in response to growing frustration among its members. The standing-room-only crowd at the Noel Wien Library included many familiar faces involved in Fairbanks energy issues. But what stood out were the people I didn’t recognize: residents who don’t typically show up to these kinds of meetings, clearly searching for answers to their high energy bills. A military mom with a toddler. A retired, disabled veteran trying to make ends meet.
GVEA CEO Travis Million laid out some of the key challenges facing the Interior — not only around cost, but supply as well. One issue that received particular attention was the absence of inexpensive “economy power” from Southcentral via the Alaska intertie.
Historically, GVEA has had two primary ways to access lower-cost power from Southcentral, much of it associated with Cook Inlet gas. One is to purchase gas directly from producers and contract with Southcentral utilities to generate electricity using that gas and send it north over the intertie. The other is to purchase excess generation from those same utilities — regardless of the fuel source — which can often be produced at relatively low marginal cost.
But with tightening gas supply in Cook Inlet, neither option is available — there simply isn’t surplus to go around. As a result, deliveries of lower-cost gas-fired power to the Interior have been declining for some time, but last year was the first time they effectively dropped to zero.
The result is that Fairbanks is replacing that lower-cost supply with much more expensive diesel-based generation — this winter, that has averaged around 250,000 gallons per day. And much of that fuel is being burned in older, less efficient units. GVEA has been trying to move away from fuel oil for years, so investing in new oil-based generation hasn’t made much sense.
The cost implications are significant. As GVEA noted during the meeting, changes in global diesel prices due to the war in Iran are now translating more directly into local electricity costs, not to mention the cost of heating oil.
To put this in perspective, each $1 increase in diesel prices corresponds to roughly $250,000 per day in additional expenses for GVEA — about $7.5 million more per month in generation costs.
The implications are being felt directly in residents’ pocketbooks. Right now, residential customers in GVEA’s service territory pay an effective rate of about 32.9 cents per kilowatt-hour (kWh). That’s roughly 7–10 cents per kWh higher than what residents in Anchorage and the Mat-Su pay. Nearly all of that difference comes from the Cost of Power Adjustment — the COPA. This is the line item on your bill that reflects how current fuel costs compare to a set base rate. At around 12.8 cents per kWh, GVEA’s COPA is two to three times higher than that of Anchorage residents. That’s the story: we are spending far more on fuel. And that takes us right back to the 250,000 gallons of diesel per day.
To close out the presentation, GVEA outlined several steps it is taking to address the high cost of fuel, including plans for new local generation such as a second LM6000 in North Pole — essentially a jet engine adapted for power generation. It would join an existing unit running on naphtha refined at the Petro Star facility from oil pulled directly off the pipeline. The project is expected to go before the board next month, but even if approved, it would likely take three years to come online. A 30-megawatt wind project in Delta is also in the works, but it has recently encountered permitting delays at the federal level.
When the floor opened for questions, hands shot up immediately. What about solar? Nuclear? How much power do the military bases consume? How much is your salary—can’t we cut costs somewhere? And don’t we have cheap local coal?
The bottom line is that none of these options fully address the immediate challenge of high energy costs — at least not in the short term. Fundamentally, Fairbanks is not particularly well positioned geographically when it comes to energy resources. We lack significant hydro potential, and we are not located near a major natural gas resource like Cook Inlet or the North Slope.
We do have coal, and it is already an important resource. The two mine-mouth plants in Healy make up a significant share of GVEA’s baseload and are, arguably, among the lowest-cost sources of reliable generation available to the system. But they’re not without challenges. I’ve heard anecdotally that Healy Unit 2 has been giving operators and dispatchers fits this winter. It’s definitely not performing like the steady, dependable baseload resource that coal is often assumed to be.
Then there’s the UAF coal plant. I work on campus, and around mid-winter I started to notice that emissions from the smokestack were less consistent than I expected. So I began paying closer attention. By my count, the plant has operated roughly 28 days since January 1st — about a quarter of the time.
When it’s offline, UAF shifts to burning heating oil to heat the campus, which is a higher cost fuel than coal. It then purchases electricity from GVEA, which in turn places even more demand on a system that is already relying heavily on diesel generation. This layering effect increases overall liquid fuel use locally, putting additional strain on supply to the point where fuel is now being trucked up from the refinery in Valdez to meet demand. I suspect we’re in for a sobering financial realization when UAF’s energy bills are finally tallied.
Is Fairbanks Rural Alaska?
In rural Alaska, energy costs are a major burden — one that families and communities deal with every day. Fuel must be imported over long distances, and power systems remain largely diesel-dependent, driving electricity prices to very high levels. To address this issue, the State of Alaska developed Power Cost Equalization, or the PCE program, around 40 years ago. The idea was that when investments were made by the state, such as in hydroelectric projects that benefited one community or region, other money would be put aside to help subsidize costs in diesel dependent communities.
In statute, the PCE program is designed to equalize the cost of electricity for residential customers to something close to the average of Anchorage, Fairbanks and Juneau. These locations were selected as the major population centers at the time the program was created. It was assumed that each one of these communities would have access to relatively low-cost power that was at least in part state-subsidized: Juneau through the Snettisham hydroelectric project, and Anchorage, the Kenai Peninsula and Fairbanks through interconnected infrastructure supported by state investment in both generation and the transmission backbone now known as the Alaska Intertie.
Under this framework, rural communities would receive a subsidy to bring residential rates closer to that urban benchmark. The intent was that, at least in theory, all residential customers across the state would have access to reasonably comparable electricity rates — something akin to a shared, or “postage stamp,” average.
In practice, however, things work differently. The relatively high rates in Fairbanks are effectively canceled out by the very low-cost hydropower in Juneau. And because Chugach Electric Association in Anchorage sells the largest share of electricity, Anchorage ends up disproportionately influencing the so-called “PCE base rate” — the “floor” price that rural residents pay after the subsidy is applied.
For example, the PCE base rate last year was 19.92 cents per kWh, which in turn was largely derived from Chugach’s 2024 average rate of around 21 cents per kWh. If a rural utility is well run and doesn’t have a lot of non-allowable costs inflating its rates, rural residential customers should pay something close to that level — at least for the first 750 kWh per month which is covered by the program, which is a reasonable amount for most households.
This has worked out well for rural residents, and is a cornerstone program for making living costs slightly more affordable in rural Alaska. But Fairbanks is struggling.
In 2025, Fairbanks residents paid about 11.5 cents per kWh more than residents in places like Akiak, Akutan, Anaktuvuk Pass, Atmautluak, and Atqasuk. Those are just the communities starting with the letter “A” in the annual PCE report published by the Alaska Energy Authority, that have managed to hit that PCE floor of about 20 cents per kWh.
Looking across all 188 communities that received PCE last year, Fairbanks residents paid more than about 140 of them. That’s sobering. And if the goal of the program is to offset diesel costs, consider this: GVEA burned more diesel fuel last year than all of rural Alaska combined. This year, it won’t even be close. Our 250,000 gallons per day dwarfs the roughly 70,000 gallons rural Alaska consumes on average for power generation.
So what does this mean? It raises questions about how Fairbanks fits within the broader structure of Alaska’s energy system. Should it be viewed more like rural Alaska in certain respects? Should we consider expanding the PCE program to cover Fairbanks residents? For many, that idea is heretical — and not without reason. PCE currently serves about 80,000 residential customers; extending it to GVEA would effectively double the program.
Some of my colleagues have suggested this is a temporary disparity, driven by the loss of gas-fired economy power, and that rates could moderate over time. But looking at historical data, Fairbanks has always been above the PCE base rate benchmark — roughly 10 cents per kWh higher for virtually all of the past decade.
So why are we noticing it so much more now? It may be that rates are reaching a breaking point for local residents. Crossing the 30 cents per kWh threshold stands out as a kind of high-water mark — likely because, historically, it is. But the floodwaters are still rising. I would not be surprised to open my bill in July and see rates approaching 35 cents per kWh.
So what about the Alaska intertie?
When Alaska lawmakers began shaping their vision for an equitable energy system, the solution for Fairbanks was, in part, the Alaska Intertie. The idea was that physical interconnection would allow lower-cost power to move across regions, benefiting everyone connected to the grid. So why hasn’t it worked as intended?
Part of the challenge is that while the system is connected physically, it’s not integrated operationally. This means the system is not dispatched as a single, coordinated grid where the lowest-cost generation is brought online first for the benefit of all customers. Instead, it continues to function more like three loosely connected regions — the Kenai, Southcentral, and the Interior — each making decisions within its own boundaries.
The result is that some of the most efficient generation is not fully utilized, while higher-cost resources continue to run elsewhere on the system. This dynamic is a classic prisoner’s dilemma: the best overall outcome comes from cooperation, but each utility is incentivized to act in its own interest because that is what it can directly control.
If this were happening in the Lower 48, utilities would likely be required to operate under a more coordinated system due to regulatory frameworks established decades ago to support regional power markets. Alaska, however, falls largely outside of those Federal Energy Regulatory Commission requirements, which are tied to interstate transmission and wholesale power markets. Because Alaska’s grid does not cross state lines, it is exempt from many of these rules.
One result is that the governance structure of the Railbelt has evolved differently — and in some ways, more slowly. Without the same regulatory drivers, the system has remained more fragmented, with each utility continuing to operate largely within its own footprint.
This has implications across the grid, but the effects are not evenly distributed. Communities at the edges of the system tend to feel these dynamics most acutely. While this commentary has focused on Fairbanks, similar pricing pressures can be seen in other peripheral areas, including Homer Electric Association and the City of Seward, albeit for somewhat different reasons.
The fix is ultimately a governance fix when it comes to the Railbelt. We can’t build our way out of high energy prices — at least not in the near term. And the reality is that high prices are going to be with us for a while. That doesn’t mean we are without options. But it does mean that the most meaningful progress will come not from the next project, but from how we choose to operate the system we already have.
Today, we are not consistently dispatching the lowest-cost resources across the grid, nor are we planning and operating the system as a single, coordinated network. That gap has real consequences. It means we carry unnecessary costs, underutilize our best assets and expose some regions — particularly those at the edges of the system — to higher and more volatile prices.
We have done hard things before. We built legacy hydropower projects around the state that continue to benefit residents with access. We also created mechanisms to share resources across communities through the PCE program. And we have taken meaningful steps toward greater coordination on the Railbelt as well. In Southcentral, utilities now operate more closely together through coordinated dispatch arrangements, and regionally we have established organizations like the Railbelt Reliability Council and the Railbelt Transmission Organization to support more integrated planning and operations.
These are important steps in the right direction — but they are still incomplete. The next step is less about infrastructure and more about alignment: establishing the structures and incentives needed to operate the Railbelt as a single system. Until we do that, we will continue to fall short of what this grid was designed to deliver.
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