Enstar CEO says Cook Inlet gas shortfall more serious than thought earlier

A projected natural gas shortage facing Alaskan communities may be worse than previously thought, the president of the state’s largest gas utility said.

Imports of liquefied natural gas thought of earlier as a short-term solution no longer appear to be an option at least at any scale, John Sims, CEO of Enstar Natural Gas Co., told the Resource Development Council in Anchorage.

State oil and gas officials say aging gas fields in the Cook Inlet basin, which have been producing since the 1960s, will see drops in production beginning in 2027 and be in serious decline by 2030.

It’s a serious problem because half of Alaska’s population lives in Southcentral Alaska, mostly in Anchorage. Space heating and most power generation in the region are fueled by gas.

Regional gas demand is steady at about 70 billion cubic feet per year, and that is met my existing production. But by 2027 annual is projected to drop to 65 billion cubic feet per year, to 55 billion by 2028 and 48 billion by 2030, according to a 2023 Alaska Division of Oil and Gas study.

Enstar and electric utilities in the region have been studying options for meeting the supply gap with imports of LNG but now find there isn’t time to build regasification and dock facilities for handling LNG imports by tanker before 2030, Sims said.

“That was a ‘big gulp’ moment for us,” Sims said.

Unless more production can be coaxed out of the region’s gas fields the utilities may have to rely on smaller-scale shipments of LNG using ISO containers, which will be extremely expensive, Sims said.

Hilcorp Energy, the largest gas producer in Cook Inlet, has told the utilities that it cannot renew gas contracts on a firm, or guaranteed, basis as contracts expire beginning this year.

It’s possible that Hilcorp or smaller companies active in the region could supply some gas on an interruptible, or non-guaranteed, basis but utilities are bound by regulatory rules to guarantee service to customers and must have firm contracts with producers to supply that, Sims said.

Hilcorp, the largest producer, has told the utilities it can no longer offer firm contracts, he said.

Electric utilities in the region depend on gas for most power generation although Matanuska Electric Association, which serves a large area north of Anchorage, has a dual-fuel capability, and oil, at its power plant.

The problem also affects Alaska’s sole liquid fuels refinery operated by Marathon Petroleum on the Kenai Peninsula, Casey Sullivan, external affairs manager for the company, said at the same briefing Sims spoke at.

Marathon uses natural gas in operations at the refinery, which supplies most of Alaska’s gasoline as well as jet fuel for Anchorage’s airport and Joint Base Elemdorf Richardson in Anchorage, a major military installation.

Ironically, Alaska has 35 tcf of gas that is stranded on the North Slope, 800 miles to the north, but with no pipeline to move the gas to the southern part of the state. Absent a $10 billion-plus state subsidy to build a pipeline, the North Slope gas is not an option.

Sims said that Enstar and the major electric utilities have spent $3.5 million on studies of possible LNG imports. The group is still studying the findings and are not yet ready to release the estimates, Enstar spokesperson Lindsay Hobson said.

However, based on preliminary findings released last year the cost of imported LNG could be in the range of $15 per mmcf, Sims said in previous briefings. That’s about twice the prevailing price now paid to producers in the region.

That assumes LNG imports using small tankers or large barges. If that option is unavailable until 2030, until import facilities are built, the option of using ISO containers or small LNG barges could push costs to $25 per mmcf, or more, Sims has said. That is about three times current prices, at least for the volume of LNG shipped in.

This would be very damaging to a regional economy already struggling with high energy costs and an out-migration of working-age adults and families, Sims said.

State legislators in Juneau are meanwhile working on incentives that could encourage new production. Bills that would reduce the state royalty rate could help one small producer, HEX LLC, finance new wells to tap a resource near its Kitchen Lights field in Cook Inlet.

That could result in some new gas in the near term, Mark Slaughter, chief commercial officer for HEX, told a legislative committee in Juneau.

The legislation that is most advanced is House Bill 223, by State Rep. George Rauscher, R-Sutton, that would reduce the state royalty from 12.5 percent of the production value to zero if new Cook Inlet gas is sold to public utilities. The bill would also reduced royalties on new oil in the Inlet to 5 percent.

Gov. Mike Dunleavy has a separate bill, now active in the state Senate, that would drop the royalty to 5 percent for new Cook Inlet gas.

In his talk to the RDC Sims urged legislators to required that new state incentives be linked to firm, non-interruptible, supply contracts gas sold to utilities.

If the gas contracts are interruptible, or non-firm, they won’t help the utility, which need firm contracts, he said.