One way out of Alaska’s impending natural gas shortage could sit under the ocean floor, a few miles north and offshore of the Kenai Peninsula community of Anchor Point.
There, a company says it’s sitting on an enormous pool of natural gas, equivalent to years of supply for Alaska’s power plants and home heating systems.
In fact, the company, BlueCrest Energy, has already brought numerous, productive wells online there, using a rig that drills horizontally from land out under the water. But the wells have been used mostly to pump oil from deep below the seafloor; the big pool of gas, BlueCrest says, sits higher up, between the oil and the ocean bottom.
BlueCrest says extracting the gas will require wells drilled vertically, from a new offshore platform it wants to build in the water. But even though Anchorage-area policymakers and utilities are girding for an impending crunch in natural gas supplies, the company has failed to find investors willing to front the money for what could be a $350 million project.
“This is a sure deal,” Benjy Johnson, BlueCrest’s chief executive, said in an interview. “The issue is, simply, the funding for the development. We are literally, every day, talking to investors, to try to convince them that Alaska is a safe place to come back to.”
There’s plenty of gas left in Cook Inlet — the aging basin offshore of Anchorage and the Kenai Peninsula — where BlueCrest says an engineering firm has validated its discovery with at least 90% confidence, using data from a decade-old test well and other past drilling efforts. A second company with holdings in the Inlet, HEX, also says it has similar amounts of untapped natural gas.
State experts agree that the deposits are significant, even if their exact scale remains unknown.
But after more than six decades of petroleum extraction in Cook Inlet, the companies’ recent experiences show that oil and gas are proving much harder for the industry to develop, and more expensive to produce. The biggest obstacle to further development in the basin is that potential investors and buyers are wary of the risk involved, according to Johnson and John Hendrix, HEX’s president.
Drilling is an uncertain proposition: Wells can fail to produce gas, or cost far more than expected. Investors are demanding high returns for putting their money on the line, the executives said.
Alaska’s electric utilities also say they want to shift to renewable power, which would reduce their demand for gas and their willingness to buy it from HEX, BlueCrest or other producers. And a state agency is still trying to secure investment to build an enormous new gas pipeline to Cook Inlet from the huge North Slope oil and gas fields, which would “kill us,” Hendrix said.
Hendrix said he thinks that utilities should take the unusual step of directly investing in drilling, thereby taking on a share of the financial risk. That wouldn’t be unprecedented, he noted: Anchorage’s big electric utility, Chugach Electric Association, already owns a majority stake in an onshore gas field next to Cook Inlet.
Without utility investment, it makes more sense to produce a dwindling amount of gas from wells that HEX has already drilled, rather than borrowing money at high interest rates to drill more, Hendrix said.
“The do-nothing case, it doesn’t cost me much to just sit on it and watch gas prices go up,” Hendrix said. Alaska’s utilities, he added, “want me to take all the risk” and continue signing long-term contracts that require his company to pay punitive damages if it can’t deliver promised supplies.
“We can’t afford to do that,” Hendrix said.
Hendrix’s position underscores the challenges faced by policymakers, including Republican Gov. Mike Dunleavy, who hope that more local production could meet Alaska’s demand without turning to liquefied natural gas from Canada or Mexico — an option that the state’s utilities say they’re studying seriously.
Imports wouldn’t create Alaska jobs tied to local petroleum drilling, nor would they generate royalty revenue for the state. But utility leaders say they could provide the gas that they need on a clear timeline, without asking them to bet on new in-state wells that could cost more money or produce less gas than expected — or run into delays.
The cost of imported gas, according to utility analyses, could be 50% higher than Cook Inlet gas supplied under existing contracts. But those same analyses suggest that prices for new Cook Inlet contracts could be the same or even higher — and utility leaders say they have more confidence that imports will arrive on time and under budget.
“We’re pretty agnostic about where we get our gas,” said Sam Cason, Chugach Electric Association’s board chair. “It’s not that we think LNG is better gas. But it’s predictable. And we’re very risk-averse.”
The nearest-term prizes
BlueCrest and HEX aren’t the only companies in Cook Inlet that could be extracting more gas.
The basin’s biggest operator is Hilcorp, the privately owned company based in Texas. Hilcorp, from its many offshore platforms and onshore wells in and around Cook Inlet, produces more than 80% of the gas used in what’s known as the Railbelt — the area of urban Alaska that stretches from Fairbanks south through Anchorage to the Kenai Peninsula.
A group of state legislators asserted recently that Hilcorp is using its “monopoly position” to “drive up prices,” and they’ve pushed Dunleavy’s administration to use its legal authority to compel the company to produce more gas.
Hilcorp officials testified earlier this year that they’re already investing ample cash in Cook Inlet: They’ve drilled 90 wells in the basin since 2012, and plan to spend more than $1 billion in the basin over the next five years. Nonetheless, they haven’t publicly announced the discovery of any large, untapped gas pools like the ones HEX and BlueCrest say they’ve identified.
Without a major production boost from Hilcorp, those two smaller companies are likely the best hope for locally produced gas to fill Alaska’s supply gaps. BlueCrest’s and HEX’s deposits appear to be the Inlet’s “nearest-term prizes,” said John Crowther, the state’s deputy natural resources commissioner.
“Based just on unquestionably public information and production information, those are two significant gas resources,” Crowther said in an interview.
Lacking Hilcorp’s comparatively deep pockets, HEX and BlueCrest say they need help to pay for the new infrastructure and drilling required to get gas out of the ground.
BlueCrest’s history and continuing problems finding investors show how securing that money remains a huge obstacle in Cook Inlet, even when companies have data that supports their claims of finding huge quantities of gas.
The company’s main asset is the Cosmopolitan Unit, which it acquired a decade ago. The unit was first drilled in the 1960s by Pennzoil, then drilled and tested many times since. But until BlueCrest took over the prospect, it had never actually produced oil or gas for commercial sale.
With more than $400 million raised from investors, BlueCrest expanded an existing pad overlooking Cook Inlet just off the Sterling Highway, some 50 miles southwest of Soldotna. The company also borrowed $30 million from Alaska’s state-owned economic development corporation, the Alaska Industrial Development and Export Authority, to help pay for a new, high-powered drilling rig.
Additional cash was supposed to come from generous tax credit programs established by the Alaska Legislature.
But the company’s plans went awry after oil prices crashed in 2014. Alaska policymakers subsequently repealed the Cook Inlet tax credits, which had been paid as real money, not tax deductions, to small producers like BlueCrest that had minimal tax bills.
Future credits had been essential to the company’s business plan, Johnson said. After spending investor money on startup costs, BlueCrest planned to use credits to support ongoing drilling at its pad, because it needed more wells to fully maximize its oil production.
“We had, at that point, developed only about 10% of the proved reserves,” Johnson said. “But we had spent almost 100% of the money for it.”
Without the cash to continue, BlueCrest had to stop drilling five years ago. Unable to find additional investors, it hasn’t drilled a well since, and it’s also renegotiated its loan from the state development corporation several times to allow for slower repayment.
BlueCrest now produces just 700 barrels of oil a day, far short of the 10,000 its infrastructure was built to handle. And potential investors, Johnson said, are now wary of putting more money into Alaska projects like new oil wells or an offshore gas platform after seeing how lawmakers slashed the tax credit budget — and how activists continue to push legislation and citizens initiatives to raise oil taxes.
Even bringing back tax credits for Cook Inlet drilling likely wouldn’t help, Johnson added.
“I don’t think that investors would trust it,” Johnson said. “They all know about the unreliability of the state.”
Drilling costs are also higher in Alaska than they are in other oil basins where investors could put their money instead, Johnson said. And in spite of BlueCrest’s confidence in its gas deposit at Cosmopolitan, he added, risks remain.
“There’s always uncertainty when you’re dealing with geology,” he said.
What’s next?
The Railbelt’s biggest natural gas buyers — its utilities — now appear to be looking toward imported LNG, not local supplies, to fill the gaps forecast to begin in the next few years.
It would be “risky and unadvisable under current market conditions” to count on Cook Inlet supplies past 2026, said a report commissioned earlier this year by Enstar, the natural gas utility that sells to consumers in Anchorage, the Kenai Peninsula and the Matanuska-Susitna Borough.
Outside of a heavily subsidized, multibillion-dollar pipeline connecting the Railbelt to the North Slope that would take years to build — an option that faces political headwinds — Enstar’s analysis points toward imported LNG as the best fit for the region’s natural gas and electric utilities.
Enstar officials said they’ve shared with BlueCrest and HEX that there’s still ample interest in buying gas from the two companies. But they also said that Enstar prizes dependability, and suggested that it wouldn’t be prudent to assume the risks that accompany a direct investment in drilling.
“We prioritize contracts for firm and reliable supplies of gas,” spokeswoman Lindsay Hobson wrote in an email. “Enstar does not deem it prudent to risk customer dollars on the highly speculative industry of gas exploration.”
In the absence of utility investments, Dunleavy’s administration is using other tools to try to spur more Cook Inlet drilling.
The governor has already announced he’ll introduce a bill in the upcoming legislative session to reduce the royalty rates that companies must pay, according to state leases, once they begin producing oil and gas.
And officials from the Department of Natural Resources, which oversees oil and gas leasing in the state, say the agency is carefully scrutinizing the yearly work plans of companies with holdings in Cook Inlet. Officials say they have the legal authority to reject those work plans or even compel companies to drill wells if development isn’t happening quickly enough.
“We know the demand is there,” said Crowther, the deputy commissioner. “And we want to see responses to that by all of our operators.”
One obvious potential source of the cash needed to drill in deposits like BlueCrest’s or HEX’s is Hilcorp, the dominant producer in Cook Inlet.
In fact, BlueCrest and Hilcorp “have been in conversations” about a partnership to develop the Cosmopolitan Unit’s gas, said Anchorage Democratic Sen. Bill Wielechowski, who has closely followed developments in Cook Inlet. But the discussions broke down because Hilcorp and BlueCrest couldn’t agree on how to divide potential costs and profits, according to Wielechowski.
Johnson, the BlueCrest chief executive, declined to comment on his company’s relationship with Hilcorp but said his company is “always open” to working with good partners. A Hilcorp spokesman declined to comment.
Johnson said he thinks Dunleavy’s proposal to reduce royalties would improve projects’ profitability for potential investors.
But that policy, he added, is more helpful over the long term, since it can take “decades” for companies to start producing oil and gas from their leases — a necessary step before they can benefit from the lowered royalty rates.
“We support the governor in that. It’s a good idea,” Johnson said. “But we need more short-term help in getting Cosmopolitan up and running.”
Nathaniel Herz welcomes tips at natherz@gmail.com or (907) 793-0312. This article was originally published in Northern Journal, a newsletter from Herz. Subscribe at this link.
