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Energy On The Edge: Future of Cook Inlet Gas
Energy Forum Summary By Ross Johnston, Executive Director.
| Venue | Denali Towers North |
| Address | 2550 Denali St, 16th FloorAnchorageAK99503,US |
| Starts | Tue May 20 2025, 4pm AKDT |
| Sponsored By | Enstar Natural Gas Company |
Cook Inlet’s natural gas, the lifeblood of Southcentral Alaska’s electricity and heating, is nearing an inflection point—one marked not by the exhaustion of geology, but by economics, policy stasis, and technological reckoning.
At our recent energy forum titled Energy on the Edge: Future of Cook Inlet Gas, state officials, utility executives, economists, and industry leaders gathered in Anchorage to confront a future that is arriving faster than anyone would like. The meeting was both somber and spirited—part clarion call, part therapy session.
The unifying anxiety was simple: where will the gas come from next?
The Premises of Precarity
Dr. Brett Watson of the University of Alaska’s Institute of Social and Economic Research (ISER) opened with a gentle but unsparing economic framework. Behind the policy debates and production forecasts lies a simple, stubborn number: 70 billion cubic feet. That is the annual volume of natural gas required to keep Southcentral Alaska running. It is not an abstraction—it’s a ledger of necessity. Alaska is profoundly dependent on natural gas: it heats half the homes in the state, powers 70% of the electricity in Southcentral, and supports myriad industrial and commercial needs. And nearly all of that gas comes from Cook Inlet.
There’s still gas in the ground—perhaps trillions of cubic feet—but extracting it is increasingly uneconomical without new technology, infrastructure, or policy change. Because of rising extraction costs, particularly in the next 5-10 years, Cook Inlet gas faces what Watson and other resource economists call economic depletion. A 2018 DNR study forecast that even conservative demand scenarios will soon outstrip economically viable production, especially as costs per unit rise and producers face structural disincentives to invest.
“The stakes aren’t existential in terms of survival,” Watson clarified. “But they are existential in economic terms.”
Increased costs will ricochet across the state: higher utility bills, a heavier burden on low-income households, costlier goods and services, and intensified outmigration. The challenge isn’t about keeping the lights on. It’s about keeping Alaska competitive, livable, and just.
The Bridge and the Fork
Watson offered a metaphor for the path ahead—a trail hike through the Chugach, with a stream to cross and a forked path a few miles away. Utilities will need to make some investments to ensure short term reliability, then build a bridge across the stream (medium term, but reliable solutions including small-scale imports of liquefied natural gas). On the other side of this bridge will be two starkly different forking paths for Alaska: import large quantities of LNG or bring gas down from the North Slope via pipeline and exporting the surplus to international markets.
Both are costly, complex, and politically loaded.
“If we get it wrong,” Watson warned, “we build a bridge that leads us to a path we regret.”
A Producer’s Lament
If Watson’s tone was diagnostic, John Hendrix’s was defiant. The CEO of Furie Operating Alaska—one of the few remaining gas producers in the basin—challenged the narrative of depletion and scarcity.
“There’s gas there,” he said plainly. “We just have to develop it.”
Hendrix, a grizzled veteran of oil and gas operations from Prudhoe Bay to the Middle East, was unsparing in his critique of what he called a “false mindset” that Alaska must become a net importer of energy.
At the heart of Hendrix’s frustration is the dichotomy between producers and utilities, between risk and regulation. Utilities want long-term contracts to ensure reliability. Producers, burned by past bankruptcies and underinvestment, want commitments and pricing that reflect the true costs—and risks—of production.
“We’re risking our capital,” Hendrix said. “Utilities go to the RCA and get recovery. We get nothing unless the gas flows.”
He also highlighted the burden producers carry that renewables and utilities do not: property taxes, full royalties (12.5%), and no guaranteed cost recovery. “If I were a utility, I wouldn’t pay property tax. If I were renewables, I wouldn’t pay royalties. But I’m oil and gas—I pay both.”
Utilities Bridging Gaps
Arthur Miller, CEO of Chugach Electric Association, spoke with a stoic urgency. Chugach, the state’s largest electric utility, gets 60% of its gas from its Beluga River Unit (which it partly owns) and 40% from Hilcorp—a contract that expires in March 2028.
“No supplier has come forward with a firm offer to replace that gas,” Miller stated. Miller mentioned that it would be in the best interest for the utility companies of Alaska to coordinate their plans, but their different contract time horizons make it difficult. Chugach Electric has the shortest runway to find a solution.
To manage the looming shortfall, Chugach is building a buffer: underlift agreements with Hilcorp, a gas exchange with Marathon Petroleum, investments in gas storage, and 30 MW of a new battery storage system. But those measures are temporary, bridging only a few years.
The real question, Miller echoed, is what comes after.
Imported LNG is one answer—specifically through the Kenai LNG Terminal, now under redevelopment by Harvest Alaska. The timeline matches Chugach’s need, and while importing gas is more expensive, the utility estimates a 10% increase to electric bills—a manageable, if painful, bump.
But it’s not the preferred path.
“We’d rather use Alaska gas,” Miller insisted. “But we need gas in 2028. Full stop.”
The Gatekeeper’s Dilemma: Enstar and the Clock
As president of Enstar Natural Gas, Alaska’s largest gas utility, Sims does not produce energy, nor does he convert it to electricity. He delivers it. His job is to manage expectations, hedge bets, and—above all else—ensure that gas flows to the homes and businesses that rely on it, no matter the upstream drama.
Enstar, like Chugach Electric, has a major contract with Hilcorp that expires in 2033. Unlike a utility with a power plant or a producer with a drill bit, Sims doesn’t have the option to diversify in place. If the gas doesn’t arrive, Enstar doesn’t deliver.
He pointed to the stark map of current lease ownership: Hilcorp controls most of the Cook Inlet basin. The remainder—Furie, BlueCrest, and a scattering of smaller players—are producing, but not at a scale that can replace what’s lost. Hilcorp has made clear it will not renew existing contracts under previous terms. That decision may be rational, but it is not comforting.
Like others, Sims praised Furie’s investment and commitment, but he was brutally honest about the limits of optimism. “If Furie succeeds—and I hope they do—it’s maybe 11% of the total market. We still have to find the other 89%.” By the following summer, Hendrix noted, it may produce 16%.
For Sims, the math isn’t just sobering—it’s structural. Utilities cannot build a business plan around hopes or handshakes. They need firm delivery volumes, with real molecules behind them, and an enforceable price. Producers, understandably, need assurances they won’t be undercut by LNG imports or priced out of the market after investing millions.
That is why Enstar is also pursuing LNG as a backstop. They have an exclusivity agreement with Glenfarne and plan to build a new terminal. Sims called it “a necessary insurance policy,” not a preferred path.
“If I could buy every molecule John Hendrix drills, I would,” Sims said, “and I will. But that still doesn’t fix the whole problem. We need scale, and we need certainty.”
Time, he reminded the audience, doesn’t yield to process. “We can’t bank on a North Slope pipeline. We can’t wait for federal permitting cycles. We’ve got to make decisions that protect customers—today.”
The quiet implication: failure to act isn’t theoretical. It’s logistical.
North Slope Mirage?
Talk of bringing gas from the North Slope—once a state obsession—now elicits weary nods and half-hearted hand raises.
“Who thinks a pipeline from the North Slope is coming?” John Sims asked. Five hands rose among a crowd of dozens.
The Alaska LNG pipeline has been studied, delayed, and reimagined for decades. But in the absence of shovels in the ground, utilities can’t plan on a promise. They need certainties, not aspirations.
The problem isn’t belief—it’s bankability.
The Role of Government: Keeper of the Hopper
Throughout the forum, another thread emerged: the need for better policy alignment and state leadership.
Who, exactly, is coordinating Alaska’s energy transition? Is it the Department of Natural Resources (DNR)? The Regulatory Commission of Alaska (RCA)? The Alaska Energy Authority (AEA)? The utilities? The Legislature?
“The hopper of opportunities is there,” Hendrix said. “But who’s keeping it?”
DNR Director Derek Nottingham acknowledged the fragmentation. His presentation highlighted recent drilling (19 wells completed in 2024 across multiple fields), and upcoming undeveloped gas projects that could add supply. But even with aggressive development, the basin’s ability to meet growing demand remains in doubt.
“We don’t have a central authority coordinating production, regulation, and consumption,” Hendrix noted off-mic. “It’s everyone managing their corner.”
Reframing the Future
As the session drew to a close, a sense of convergence emerged. No single solution will save Cook Inlet’s gas ecosystem. But neither will inertia.
Short-term, the region needs aggressive storage, flexible contracts, and policy support to incentivize new exploration.
Medium-term, imported LNG may be unavoidable. The infrastructure is being readied. The cost impact—significant but not catastrophic—is a political hurdle, not a technical one.
Long-term, the fork in the trail remains: an import economy or a pipeline reality.
And beyond even those binary choices lies the promise—and complexity—of decarbonization. Electric utilities like Chugach have set ambitious goals: reduce carbon intensity by at least 35% by 2030, 50% by 2040, so long as rates and reliability are not compromised. That’s a fine line to walk—especially when you’re also bracing for an energy crunch.
However, decarbonization doesn’t mitigate the supply needs of the natural gas utilities that heat our homes.
Conclusion: Bridging To The Fork
Utilities like Chugach and Enstar are already navigating the bridge—patching together underlift agreements, investing in storage, exploring renewables, and preparing for LNG imports. They are managing the immediate crossing, step by cautious step, with one eye on the current and the other on the shoreline ahead.
But the real decision doesn’t belong to them alone. At the far end of that bridge lies a fork in the road—one that Alaska as a state must confront. Will we invest in the infrastructure and policy coordination needed to become a long-term energy exporter, unlocking North Slope gas and leveraging our vast reserves? Or will we accept the role of importer, dependent on volatile global markets for the fuel that powers our economy and warms our homes? Perhaps we will cross our fingers for a future technology that simply doesn’t exist yet.
This is not just a question of engineering or pricing. It is a question of identity—of sovereignty, resilience, and economic direction.
The bridge can only carry us so far. What matters now is whether we choose a path that ensures energy security for the next generation—or simply delay the decision until the options disappear.
The stream is rising. The fork is near. And our time horizons, as ever, are getting shorter.
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