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Armstrong prepping supply contract Successful test well at North Fork means issue of gas pricing will return before state regulators; company asking for $7 to $10 Eric Lidji Petroleum News
For Cook Inlet explorers, finding gas is only half the battle. Selling it is the other half.
Following a successful test well in the southern Kenai Peninsula last summer, Armstrong Cook Inlet seems to have won the former half, and is now gearing up for the latter half.
“We are going to be moving forward in an attempt to get a gas contract with any utility that we can … ,” Ed Kerr, vice president of land and business development for Armstrong, told the House Resources Committee March 9. “It’s going to have a price associated with it.”
The head’s-up is warranted: Over the past decade, and increasingly over the past few years, contracts have led to intense debates over how best to price natural gas supplies.
Armstrong drilled an onshore exploration well last summer east of Anchor Point.
The North Fork 34-26 well found gas, and combined with test results from a previous exploration well drilled nearby 44 years ago, Armstrong is now “very comfortable” the prospect holds between 7.5 billion and 12.5 billion cubic feet of natural gas reserves and said it is “realistic” the prospect could hold between 20 billion and 60 billion cubic feet.
“There is some potential that it could be substantially larger than that,” Kerr said.
The company won’t know for sure, though, without more wells and it won’t drill more wells without a supply contract guaranteeing a market to sell into at an agreeable price.
“Our intention would be to sell gas as soon as a pipeline is built,” Kerr said, estimating a pipeline could be ready by late 2010. The length of pipe depends on the ultimate route the project takes, but “We have wells that are ready to produce today,” Kerr said.
Another blow to cheap gas? Because of the limited market in Southcentral Alaska, where only a few producers sell supplies to a few large buyers, there is no spot market for natural gas, and therefore the Regulatory Commission of Alaska has traditionally set prices, often after great debate.
To make North Fork profitable, Kerr said Armstrong needs a price above $7 per million British thermal units, but possibly as high as $10, and needs the price to track with broader trends, so that if gas prices rise and push up costs, the company can still turn a profit.
The Henry Hub price for gas is around $4 per million Btu, down from highs near $13 last year. The average cost of Enstar’s gas supply contracts is around $9 per million Btu.
Consumers around Southcentral have historically enjoyed some of the lowest natural gas prices in the country, the result of having a prolific basin supplying an isolated market.
But ongoing production declines from the largest of those Cook Inlet fields have recently prompted policymakers to consider new ways to either spur new exploration or replace supplies with natural gas from some other source most likely from much further north.
Lawmakers and the public need to shift from thinking about “cheap” gas supplies to the cost of not having enough gas supplies to meet Railbelt demand, according to Rep. Craig Johnson, an Anchorage Republican and co-chair of the House Resources Committee.
“Cheap gas may not ever be available to us again, but I certainly want to have gas,” Johnson said during the March 9 meeting.
That old question of cost When finished, North Fork 34-26 is expected to cost between $8 million and $10 million, which Kerr estimated was 400 to 600 percent more expensive than a similar well drilled in the Permian basin in West Texas. “It is more expensive here to find gas,” Kerr said.
Companies frequently point to the higher production costs in Alaska as a way to justify the need for higher natural gas prices in Cook Inlet. The RCA keeps rejecting that argument, though, saying companies haven’t put actual production costs on the record.
“So when people come and just state that they need a price and don’t produce any evidence, what are we to do?” Commissioner Anthony Price said on March 11.
It’s been nearly eight years since the RCA last approved a gas supply contract in Cook Inlet. Over the past few years, the commission considered and ultimately rejected a pair of contracts Enstar Natural Gas made separately with ConocoPhillips and Marathon.
The debate over production costs played a large role in those deliberations. Because the RCA does not regulate producers, it cannot require the companies to provide information.
Asked by RCA Chair Robert Pickett whether Armstrong would add to the record in the future, Kerr said, “I think we would do whatever we could to try to facilitate the process.”
Sell gas north or south? Denver-based Armstrong arrived in Alaska in 2000, taking a previously unseen strategy on the North Slope. The company drilled nearly a dozen exploration wells, but turned over its assets to other, larger companies to ultimately bring the fields into production.
That approach lead to the Oooguruk unit, which Pioneer Natural Resources brought online last June, and the Nikaitchuq unit, which Eni Petroleum is currently developing.
Armstrong acquired North Fork in late 2007, starting a third chapter for the unit.
Standard Oil of California drilled the original North Fork well in 1965, but never developed the field. Through the late 1990s and early 2000s, a series of smaller independents owned the field, but failed to segue into sustained commercial production.
There have long been two likely options for selling North Fork gas: north and south.
Armstrong could sell natural gas to the city of Homer, about 10 miles to the south.
Homer predominately uses fuel oil for space heating, and therefore would need not only a transmission pipeline from North Fork to the city, but also a new distribution grid.
Or Armstrong could feed to the existing pipeline grid crisscrossing the Cook Inlet region, which would mean finding demand not served by the existing, longer-term contracts.
That option might also require Armstrong to build a small feeder pipeline from North Fork to Anchor Point, an option Kerr said shouldn’t be a problem for the company.
Kerr mostly ruled out industrial customers like the liquefied natural gas export facility in Nikiski or the mothballed Agrium plant, focusing instead on possible utility customers.
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