Senate Resources Chair Cathy Giessel called the joint House and Senate Resources Committee to order at 1 p.m. Thursday with a single subject: Cook Inlet gas. Hilcorp Alaska, HEX Energy, and Chugach Electric Association showed up. BlueCrest Energy did not.
What the three companies testified put on the record something sharper than the usual basin briefing. Hilcorp says it will meet every contract it has signed and that there is enough gas in storage to cover ENSTAR’s shortfall this winter— if the utility agrees to pull that gas forward and take less later. HEX says it is already tripling firm sales to ENSTAR and could drill more if anyone would give it a runway longer than five years. Chugach says its members should have power through the next two winters, and that imported LNG is no longer a preference question. It is a reliability question by 2029.
Hilcorp: record drilling, flat gas, a 2029 cliff
Luke Saugier, senior vice president of Hilcorp Alaska, testified by video and the numbers did not need a projector.
Hilcorp employs 1,750 people in Alaska and three to four thousand contractors. It is running six drilling rigs on the North Slope and two in Cook Inlet. It operates about 350,000 barrels of oil equivalent a day and more than 2,000 wells. In the Inlet, Saugier said, Hilcorp operates “over 90 percent of the gas that is provided to Southcentral Alaska for heat and power.”
“Hilcorp has never been more active in the Cook Inlet, and we remain completely confident in our ability to deliver on all of the gas supply commitments that we have made,” Saugier said. Then the sentence that framed the rest of the afternoon: “Despite the fact that Hilcorp will deliver on all of its commitments, the market needs more gas, and without another source of gas supply by winter 2029, be that North Slope gas or LNG imports, there will not be enough gas in the system to meet all of the utilities’ needs.”
This year is a record drilling season for the company— the most wells since COVID, 26 or 27 more wells planned, $400 million to $500 million of capital, and three rigs in the basin. Two of this year’s platform wells came off the North Cook Inlet, or Tyonek, platform. Saugier said Hilcorp expects two to four Tyonek wells a year for the next four or five years. The shared jackup can work about six months in the ice-free window. HEX is using that same Spartan 151 rig right now.
Activity is not the same as surplus. A five-year project chart Saugier walked through shows monthly activity bars rising year after year while the red line of basin gas rate stays flat. “Even though we are at all-time high activity levels,” he said, the result is “basically flat for the last three years. So more and more activity, but really running to stand still as far as gas delivery.” New wells are declining 40 to 50 percent in the first year. Fourteen years ago, four or five companies were drilling in the Inlet. Today it is Hilcorp and HEX.
New state acreage is getting drilled only because DNR wrote different lease terms— a net-profit-share structure Saugier put at about 5 percent. “The only way that that was economic for us was because of the creative new leasing terms by the DNR,” he said. Asked by Rep. Zack Fields whether a lower state royalty would unlock more volume, Saugier declined to promise molecules. Most Hilcorp Inlet gas, he said, comes from private land. A lower state royalty “would be great. We would commit to higher activity levels. Maybe. I would not commit to higher volumes of gas being available.”
This winter: 3 Bcf short, 30 Bcf sitting in Pool Six
ENSTAR has told the Legislature it is about 3 billion cubic feet short heading into this winter. Saugier’s answer was storage, not new wells. Hilcorp’s Pool Six will enter winter with about 30 Bcf. CINGSA, the ENSTAR-managed facility, holds about 7 or 8 Bcf. “Hilcorp has 30 Bcf of gas in storage going into this winter. All— substantially all of that gas, really all of that gas— is dedicated for future delivery to ENSTAR,” he said. “This gas can be available today if contracts are adjusted.”
Adjusted means re-timed, not expanded. Hilcorp’s firm commitment runs about 33 Bcf a year on a rolling schedule. “We are very confident that we can deliver that volume, but not any more than that volume,” Saugier said. “What we can’t do is deliver a bunch of extra gas now and also deliver all of the committed volumes in the future.” Asked by Giessel what that does to the consumer price, he said Hilcorp and ENSTAR have not discussed pricing yet. Any amendment, he assumed, would go to the Regulatory Commission of Alaska.
That is the winter outlook in one sentence: the molecules exist. The contract shape does not. If ENSTAR and Hilcorp finish the deal and the RCA blesses it, Southcentral should have gas this heating season. If they do not, the 3 Bcf hole stays open, and the only fast substitutes are conservation, diesel, and whatever HEX or Marathon will sell on an interruptible basis.
The same model that gives Hilcorp confidence this winter is what puts a date on the next crisis. Native Cook Inlet production, according Saugier, still exceeds summer demand and refills storage. By summer 2029 it only just keeps up. There is nothing left to inject. “Come winter 2029 we will need LNG imports or access to North Slope gas.” Harvest’s conversion of the Kenai LNG plant, in Hilcorp’s telling, can land 20 Bcf a year by 2029 and buy three or four years. The Harvest team, Saugier said, still thinks it can start up within two years of a final investment decision. It is in customer negotiations. He would not put a cost on the conversion.
LNG does not work without storage. Utilities have told producers they need about 700 million cubic feet a day of withdrawal capacity and a little over 100 Bcf of working volume. Today’s facilities do not provide that. Hilcorp is developing two projects— one on the Kenai Peninsula and one at Beluga River. Asked whether the Kenai project is the same facility ENSTAR has been chasing at the RCA, Saugier said, “I believe it is.” Pore-space ownership between the City of Kenai and DNR is still a fight.
HEX: tripling firm gas, advocating for a runway
John Hendrix, president of HEX, brought CFO Mike Koy with him and a different diagnosis. HEX is Alaska’s only Alaska-owned oil and gas company. On Thursday the company was 4,600 feet into the 9,160-foot A7 well, having just finished A10, aiming for a third well before sea ice with Hilcorp’s Spartan 151 and 25 Alaska contractors.
“I think the state would be better if we had more producing wells and storage wells,” Hendrix said, “I think with 19 Tcf being listed, 244 years of potential gas from the reserves that are sitting in the ground in Cook Inlet is a great prize that we all ought to be aspiring to tap.”
The near-term fix, on HEX’s numbers, is already in a contract. Firm sales to ENSTAR are 8.1 million cubic feet a day now. That rises to 26 million a day in April 2027 and 29 million a day the year after— what Hendrix called a “3.2 times increase in our firm gas that we’ve committed to Alaskans.” The firm price is $12.30 per thousand cubic feet and escalates 1.5 percent a year for five years. “Who else has done that?” he asked. “No one’s talking about a three times increase of firm gas being sold.”
The problem is the tenor sitting next to that price. “You got to have the runway, where you know if you drill and you produce, you can sell into that runway,” Hendrix said. “ENSTAR earlier this year signed an agreement with Glenfarne for thirty years, and they wouldn’t sign an agreement with us beyond five.”
DNR’s February 2025 royalty cut on Kitchen Lights— 12.5 percent down to 3 percent for a defined revenue period, about $50 million of relief— is what made the current wells financeable. HEX says most of the benefit is not staying in the company. The post-relief price to ENSTAR is $1.30 per Mcf cheaper. Koy put consumer savings at about $2 million so far in 2026 and about $52 million over the life of a 40 Bcf contract. The stacked burden is still 3 percent to the state plus 12.5 percent to overriding royalty owners, or 15.5 percent. Administrative relief, Hendrix warned, is a rug that can be pulled.
Production has doubled to more than 20 million cubic feet a day. HEX delivered about 6.7 Bcf in the recent period: 1.24 Bcf of firm gas on schedule and 5.4 Bcf of interruptible against 4.2 Bcf expected. That interruptible market is not a utility. In February, Hendrix said, ENSTAR did not take available HEX gas. Marathon did. HEX choked wells 35 to 40 percent rather than pay to store it. “It costs me money to store gas. I’d rather sell it. I’d rather drill more wells and use that as my gas storage,” he said.
On the price fight that never leaves these hearings, Hendrix put a meter number on the table. “At your meter, and I’ll give ENSTAR credit and us credit and everybody else, it’s still the twelfth cheapest gas at your home meter than any other state. The twelfth cheapest, cheaper than Texas, and it’s been that way for decades. So you need to use facts when you start evaluating things.”
What would unlock exploration, Koy told the committee, is a menu: longer offtake and critical-infrastructure treatment; statutory royalty relief instead of a revocable DNR letter; rig time; state-partnered dry-hole insurance “used in other jurisdictions;” and a public-private structure that looks more like a utility than a wildcat.
Recognizing Cook Inlet natural gas production as critical infrastructure and modernizing its fiscal framework will support reinvestment, long-term production stability, and potential state revenue enhancement over time. Restructuring fiscal terms need to be designed to improve investment certainty, simplify taxation, and maintain or enhance state revenue durability.
Hendrix also wants the state to stop leaving seismic on a shelf and start pre-packaging leases. HEX has a new exploration agreement with Tyonek Native Corporation and CIRI. BlueCrest, sitting on Cosmopolitan— Giessel put the resource at 200 Bcf against 70 Bcf a year of Southcentral demand— did not appear to explain a development plan or an $827,000 lien filed August 4 by Nordic Calista.
Chugach: members first, LNG by 2029, hydro too late for the gap
Arthur Miller, CEO of Chugach Electric Association, opened with three points and a residency line. One hundred percent of Chugach employees live and work in Southcentral, he said. Point one: Chugach is in a good gas-supply position between now and an imported-LNG structure. Point two: “It’s not a question of do we want to import natural gas. We would much rather have in-state natural gas. It’s a question of making sure we have 100 percent reliability and deliverability of natural gas for our members.” Point three: LNG is an interim bridge to more Inlet development or a North Slope line, while Chugach builds more renewable generation.
Beluga is the resilience argument. Chugach is a two-thirds working-interest owner; Hilcorp holds one-third and operates. The field was the top producer in 2024 and 2025. The Beluga power plant sits on top of it. If the gas line between Beluga and Anchorage fails, Miller said, there is not enough gas on the Anchorage side to run the Southcentral Power Project and Sullivan plants. Beluga is the backup for a line break, an earthquake, or a volcanic plume that takes the efficient Anchorage units offline. Hilcorp’s planned Beluga storage would sit on the same footprint.
The cooperative has been drilling five Beluga wells a year since 2022 and banking surplus as underlift. That inventory, Miller said, shifts Chugach’s need for a new supply structure from the first quarter of 2028— when the Hilcorp firm contract expires— to the first quarter of 2029. Underlift returns run April 2028 through March 2032. Current estimated economic life of the field is early 2035. As of August 31, Chugach held about 0.4 Bcf in Hilcorp storage and 1.8 Bcf in CINGSA.
That is why Chugach is not describing blackouts this winter. It is also why Miller would not tell lawmakers that more Beluga wells can push LNG off the calendar. Decline is significant. Robust drilling raises current production at the expense of later years. Absent a major find, he said, the timeline does not move. LNG imports will have “some impact” on local exploration. Supply, he said, is “non-negotiable.”
Short-term, Chugach is meeting ENSTAR the week of September 14 to talk exchange, sale, displaced generation, or outside power purchases. Diesel and displaced generation price out in a $29 to $60 per Mcf world— the cost of missing gas, not the cost of producing it. Bradley Lake and Dixon Diversion will not be online for 2029. Chugach’s longer commercial idea is a buyers club: aggregate Railbelt demand and take the least-cost cargo rather than let each utility cut a separate terminal deal. Harvest and Glenfarne are both still in the room. ENSTAR has already said it prefers Glenfarne. Saugier, asked whether Harvest can finance without ENSTAR, went “out on a limb and [said] yes,” then sent the committee back to Harvest’s own testimony.
What the Legislature has to do
Force the Hilcorp–ENSTAR re-timing into an RCA filing before storage season ends. 30 Bcf in Pool Six does not heat a house if it is still titled as 2030 gas. Publish the consumer price effect Giessel asked for and Saugier could not give.
Write Kitchen Lights royalty relief into statute. The 3 percent DNR decision is why HEX doubled production and why ENSTAR members are seeing a $1.30 per Mcf discount. An administrative letter is not collateral for a jackup or a third well.
Decide whether the state wants exploration or only a bridge cargo. HEX asked for a runway longer than five years, dry-hole insurance, and processed seismic packaged into leases. Chugach said reliability comes first even if that shortens the runway. Those two sentences cannot both be ignored.
Settle Kenai pore space so someone— Hilcorp or ENSTAR— can actually build the storage LNG requires. Utilities say they need 700 million cubic feet a day of withdrawal and more than 100 Bcf of working volume. That capacity does not exist today.
Put BlueCrest and Cosmopolitan back on a hearing calendar with documents, not regrets. Two hundred Bcf sitting behind a no-show and an $827,000 lien is not a plan.
Require one Railbelt winter stack— firm gas, storage, underlift, hydro, intertie, diesel— that reconciles Chugach’s “good position,” MEA’s blackout warning from last month, and ENSTAR’s 3 Bcf hole. Chugach and ENSTAR are meeting next week. That meeting should produce a public contingency.
Do not pretend Harvest or Glenfarne is 2026 supply. Twenty Bcf of imports in 2029 buys three or four years. It does not refill CINGSA this October. The jackup is in the hole on A7 today. That is the winter program.
Giessel opened the hearing because the public is watching the topic. The public should watch the next ninety days. Either the Pool Six gas gets re-timed, HEX’s third well gets a market, and the RCA sees a contract— or Southcentral spends another winter managing a shortage the testimony shows is avoidable.
Watch the full meeting
Click here to watch the full Sept 10 Senate Resources Committee meeting.
