www.AlaskaAlliance.com 2024 Meet Alaska Conference & Trade Show 25 Cosmopolitan, which is now being produced. BlueCrest needs a production platform and pipelines to tap the gas, which will cost about $400 million, its CEO, Benji Johnson, told legislators. The company is producing the deeper oil at Cosmopolitan with high-angle lateral wells drilled from shore, but this can’t be done with the shallower gas deposit, Johnson said. So far, BlueCrest has been unable to finance this large investment partly because of the unique nature of the small regional gas market. If the state could help with at least some of this financing, Bluecrest could have the gas in production possibly within three years, and bringing 50 million cubic feet of new gas production on-line, Johnson said. A state loan guarantee may be the easiest way to do this because it wouldn’t involve the state putting up cash. The Alaska Industrial Development and Export Authority, the state development finance corporation, has helped both BlueCrest and HEX with loans to do drilling, but a $400 million commitment may stretch AIDEA’s capacity. However, the state itself has a good credit rating and relatively low levels of debt to backstop a loan guarantee. Its current borrowing capacity is $1.4 billion, according to the state Department of Revenue. This may take new legislation to accomplish. HEX has a different problem at Kitchen Lights, Mark Slaughter, the company’s chief commercial officer, told legislators. The company has partners with royalty shares and this, combined with the state’s 12.5 percent royalty, raises the combined royalty payout to 30 percent of gross royalties, Slaughter said. This heavy gross royalty burden makes it difficult for HEX to borrow for new drilling into known gas deposits near the company’s Julius R platform at Kitchen Lights. HEX has tried unsuccessfully to renegotiate the partners’ royalties, Slaughter said, so the easiest way to solve this would be if the state could reduce its 12.5 percent royalty. With this, HEX could finance $3 million needed to drill prospects near its platform and possibly have new gas in 60 days, Slaughter said. The initial drilling could add 10 million to 20 million cubic feet per day of gas production, he said. Royalty reduction is proposed in bills now in the Legislature sponsored by the governor and, in a separate bill, by Rep. George Rauscher, R-Sutton, who chairs the House Energy Committee. There is other new legislation in the mix, too. Sen. Cathy Giessel, R-Anchorage, the Senate Majority Leader who also cochairs the Senate Resources Committee, has a bill in that would expand the capability to store gas in the Cook Inlet region. Additional storage is needed to augment the Cook Inlet Natural Gas Storage Alaska, or CINGSA, facility near Kenai, which is owned partly and operated by Enstar Natural Gas. Hilcorp Energy owns gas storage elsewhere in the region. — Tim Bradner Does all this sound familiar? A looming natural gas shortage in Cook Inlet. Regional utilities being forced to import liquefied natural gas? Governor, Legislature called on to act. It should ring familiar. It was all the talk in 2012. The predictions by geologists then were for legacy producing fields in Southcentral Alaska to decline by 10 percent to 26 percent yearly and for gas production to drop from 107 billion cubic feet per year in 2012 to 20 billion cubic feet per year in 2020 (the region requires about 80 billion). There was a lot of teeth-gnashing. Then-Mayor Dan Sullivan organized for rolling “brown outs” of power to conserve gas. Utilities began seriously working on plans to import LNG. All that didn’t happen. The two major Inlet producers, Chevron and Marathon Oil, sold out to Hilcorp Energy, an energetic independent with a reputation for rejuvenating old oil and gas fields. Alaska was no longer a priority for major companies Chevron and Marathon and their lack of drilling demonstrated that. Hilcorp was different. It invested and brought in new equipment and within two or three years the Inlet was actually producing more. The state did its part by enacting the Cook Inlet Recovery Act to encourage new gas and to facilitate natural gas storage, or the storing of surplus gas produced in the summer to supply peak gas demand in winter. But what’s different now is that Hilcorp itself is predicting a decline and this is backed by reservoir studies by the state Division of Oil and Gas. LNG imports are being considered again as a backstop, but the state hopes to avert this with new incentives for drilling and development. Will history repeat itself with new gas in 2025 and 2026? Too early to tell. — Tim Bradner LOOKING BACK: LNG history nothing new RAUSCHER
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