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New study says Cook Inlet needs new gas reserves At issue — what can be discovered and developed in Southcentral, what needs to be imported, to keep area running on natural gas Kristen Nelson PNA Editor-in-Chief
Cook Inlet natural gas reserves have been falling since 1982, because no significant new reserves have been added and the area will need new supplies — or storage facilities — to meet peak demand by the end of the decade.
That is the conclusion of a report released April 11 by the Anchorage Economic Development Corp. The review of Cook Inlet natural gas supply and demand was prepared by Northern Economics for AEDC in cooperation with Municipal Light and Power, Chugach Electric Association and Enstar Natural Gas Co.
“The purpose of the study was to provide for an objective evaluation of the Cook Inlet natural gas situation and discuss factors affecting the role of Cook Inlet gas as an energy source for Southcentral Alaska,” Pat Burden, president of Northern Economics, said in presenting the study to Commonwealth North.
Division of Oil and Gas figures show declining Cook Inlet reserves and Burden said most industry representatives believe total future discoveries will be in the range of 1 to 2 trillion cubic feet, although the U.S. Minerals Management Services believes that, at higher prices, up to 3.6 tcf may be found.
“The major gas utilities,” Burden said, “have been fairly stable for some time now and the uses by residents of Southcentral Alaska have slowly been increasing over time,” with 1998 usage of 61 percent industrial (the Agrium ammonia-urea plant and the Phillips-Marathon liquefied natural gas plant) and 28 percent power generation and utilities.
Cook Inlet price low National wellhead prices for national gas have been “significantly higher than they have been in Cook Inlet,” Burden said, because the market in Southcentral Alaska is less competitive than in the Lower 48.
He had an opportunity to explain the economics of the situation when asked what price it would take for the producers to take gas out of the industrial market and sell it for power generation and utilities.
The answer, he said, is counterintuitive and has to do with the time-value of money and the relative amount of gas going to industrial uses (61 percent) compared to power generation and utilities (28 percent).
“Phillips and the other producers in the inlet will continue to sell to the LNG plant and to the ammonia-urea plant at lower prices than what we would pay them,” he said, because the high rates of production and high rates of sale for industrial use make it more valuable to the producers to sell to industrial users now than it would to us 20 years from now.
If the producers couldn’t sell that 61 percent of the gas for industrial uses, he said, “they would have to wait for years in the future before they could sell it. So they will be motivated to sell at lower prices to those industrial users just so that they can get the return on their investment now.”
Higher prices, more discoveries Burden said higher prices in Cook Inlet would lead to more exploration, but even with additional discoveries of 1 tcf of gas — or 2 tcf of gas — meeting average daily and peak daily demand would require consumption by major industrial users to be reduced by 50 percent by 2010. And, there will be difficulties with known reserves in meeting peak winter needs “in a few years.”
Peak deliverability could be addressed with new discoveries, or with gas storage facilities, or with additional compression and other mechanical means to facilitate gas transport, he said.
Burden said it might be difficult to reauthorize exports from the LNG plant without new supplies available for local use — and in the long term, he said, the plant might be needed as an LNG import facility, if additional supplies are not obtained locally or from the North Slope or other basins; conversions could be made to diesel or coal. Coalbed methane exists in considerable volume in the area, he said, but is not yet economically viable in this area.
If natural gas were not available for the LNG plant and the ammonia-urea plant, Burden said, more than 1,000 jobs would be lost in the state.
Marathon and other producers have exploration programs under way and within 3 to 4 years we’ll probably have a much better handle on what the reserve base is. But, he said, Southcentral “must diversify its energy base in the long term.” While conventional natural gas “will remain an important part of the region’s energy base for the foreseeable future, in the near term the region should begin to consider how it will use these other energy resources for the long-term health of the region’s economy.”
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