The price of North Slope natural gas delivered to Southcentral Alaska via spur line would work for residential and commercial users, as well as power-generating companies, but might prove too high for heavy industry, says a Department of Energy study released this month.
The “South Central Alaska Natural Gas Needs Assessment” used a variety of data to forecast future gas use for existing consumers and for potential new markets during the period between 2015 and 2035.
A spur line built off a pipeline from the North Slope to Canada and Lower 48 markets would be expected to deliver gas to Southcentral Alaska at a cost roughly between $4 and $5 per million British thermal units (MMBtu) over the 20-year period (2005 dollars). There are 1,050 Btu’s in one cubic foot of gas, so a million Btu’s is approximately equivalent to 1,000 cubic feet of gas.
According to the study, given that price range and the estimated maximum various customers would be willing to pay, North Slope gas is likely to be bought by residential and commercial consumers and power companies, even if prices were to rise well above $5. But industrial users, such as a gas-to-liquids plant or the liquefied natural gas (LNG) plant owned by ConocoPhillips and Marathon “fall just below the point of economic feasibility” when prices rise above $3.20 MMBtu, the study said. For Agrium USA’s fertilizer plant, feasibility ends well below $3, the study said.
Several variables could affect the breadth of a gas supply’s customer base, the study said. For instance, when gas prices are high, the incentive to explore for more gas is also generally high an important factor in Cook Inlet, which studies indicate contains far more gas than has already been discovered.
If significant gas were found, however, it would likely supply regional needs, thus lowering the demand for North Slope gas. Beyond that, a spur line connecting Southcentral to the North Slope could put a ceiling on the price of gas in Southcentral that would be lower than the Henry Hub price (a Lower 48 benchmark to which Alaska gas is tied), and that “would potentially be a disincentive for Cook Inlet exploration in the long term,” the study said.
On the other hand, high prices would put gas out of the picture for large industrial users.
“The industrial sector has the greatest maximum potential for natural gas demand; however, it is also the sector for which demand is most sensitive to price,” the study said.
At prices below $3/MMBtu, the full range of existing or potential Southcentral consumers (Agrium fertilizer, the ConocoPhillips/Marathon LNG plant, a gas-to-liquids plant (GTL), Liquified Petroleum Gas (LPG), a major petrochemical plant, power companies, and residential and commercial users) would all likely buy gas.
The LNG plant uses about 212 million cubic feet per day; and Agrium, currently operating at about half capacity, about 68 million cubic feet per day. Tesoro’s refinery also uses gas, but only about 11 million cubic feet per day.
At the predicted pipeline price of $4 to $5/MMBtu, however, Agrium would close. There also might be no future in a major petrochemical plant, in GTL manufacture or in the manufacture of LPG (propane, butane, etc.), all industries in which at least some interest in Alaska development has been expressed, the study said.
Agrium already is pursuing an alternative course and is doing a feasibility study to determine if it should build a coal-gasification plant to supply its needs, as well as energy to the Railbelt power grid. Lisa Parker, spokesperson for Agrium, said the company is expected to reach a decision in the next four to six weeks.
If gas prices were to rise above $5, the only consumers buying spur line-delivered gas would be power companies and residential and commercial users. Above $6, power companies would be turning to coal, the study said.
The potential for more gas within Cook Inlet fields was not included in the study’s assessment. However, the study did say the inlet “remains a highly prospective natural gas basin.” A 2004 Department of Energy study put gas resources as high as 25 to 30 trillion cubic feet (tcf), more than twice as much as already discovered.
The study noted that continued exploration of the Cook Inlet basin was important to state and regional economies, and current prices look to be providing the necessary incentive. Escopeta Oil recently announced plans to bring an offshore jack-up rig to Alaska and drill prospects in the inlet. Other companies are likely to lease use of that rig.
“It is likely that renewed exploration focused on natural gas will result in discoveries of new reserves,” the study said.
The DOE study was done without considering the possible impact of state incentives. It noted that depending upon the incentive, a consuming entity not currently viable might become viable. Likewise, improvements in technology, particularly in processes such as GTL and LNG, could improve their economics, the study added.
The study assumed construction of a dry gas pipeline capable of delivering 350 million cubic feet per day, which would be enough to supply all users except large industry for which the price was assumed to be too high. That idea also assumed a Southcentral region storage capacity of 80 million cubic feet per day to meet peak winter demand periods.
Alternate scenarios included a larger pipeline able to deliver wet and dry gas.
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