With natural gas supplies from Cook Inlet set to fall short of local gas demand by 2014 or 2015, the time has come to move ahead with arrangements to supplement those local supplies with imports from elsewhere, Southcentral power and gas utility executives told the Regulatory Commission of Alaska during a public meeting on Oct. 24. Southcentral residents and businesses depend on gas both for power generation and for the heating of buildings.
“I’m personally done wringing my hands,” Bradley Evans, CEO of Chugach Electric Association, told the commissioners, saying he takes responsibility for ensuring continuity of gas supplies for his utility. Chugach Electric currently generates about 90 percent its power using gas-fueled power plants.
“I’m not comfortable. I’ve lost a lot of sleep. But we’ve got to move forward,” Evans said, responding to a question from one of the commissioners about the utilities’ commitment to spending money on the engineering required for a final decision on a gas import project. “We need to get to where we have a business model — less study and more action, actually defining how would you get the job done to avert the problem. … We’ve got to move down this path. We’ve got to spend this money.”
Consulting firm Petrotechnical Resources of Alaska, or PRA, has been assessing and monitoring the Cook Inlet gas supply situation for the utilities and has reported that there is little likelihood that development drilling in existing fields will significantly defer a gas shortfall. At the same time, new fields discovered from an upsurge in Cook Inlet exploration are extremely unlikely to bring sufficient new gas online quickly enough to remedy the situation, PRA says. So, the utilities are now looking at two options for supplementing local gas supplies: the import of liquefied natural gas from overseas or the import of compressed natural gas from the west coast of North America.
Lee Thibert, senior vice president of Chugach Electric, said that the utilities have asked potential shippers of imported gas for expressions of interest in the import arrangements. Consultancy firm Northern Economics will analyze the relative merits of the two import options and will likely present the results of its analysis by the end of the year. The utilities will then decide in the first quarter of 2013 which option to progress, a decision that will subsequently lead to the negotiation of contracts for the various necessary arrangements, including gas supplies and the shipping of the gas. Before making a final decision on implementation, the utilities expect to have to spend somewhere around $5 million on the preliminary engineering of the gas importing facilities, Thibert said.
High fuel oil cost
Thibert explained that without the option to import gas from out of state, the only feasible way of keeping power plants running continuously would be to use of fuel oil instead of natural gas. But with fuel oil being much more expensive than gas, the use of oil would cause Southcentral energy prices to increase much more rapidly than would be the case with imported gas.
However, it will be important to bring in external gas quite slowly at first, importing minimal quantities that will not disrupt the Cook Inlet gas industry.
“We have to avoid discouraging new Cook Inlet production,” Thibert said.
The import arrangements also need to be scalable and flexible, allowing imported volumes to increase or decrease, depending on the health of Cook Inlet gas production.
LNG versus CNG
For several years a group of utilities and other stakeholders in the Southcentral gas industry has been studying the potential gas supply shortfall and has tended to lean towards the import of liquefied natural gas, or LNG, rather than compressed natural gas. LNG enjoys a well-developed market, as well as economies of scale in its shipping arrangements, Thibert said. There has been much talk about the possibility of converting an LNG export facility on the Kenai Peninsula into an LNG import terminal, although people have also been looking at several other options and sites for bringing LNG into the state.
With no access to pipeline capacity for delivering North American gas to a suitable port, and with no ships licensed or approved for transporting compressed natural gas, or CNG, the compressed gas option seemed the poor relation to its more mature LNG brother, Thibert said.
But the situation has changed in the past year, Thibert explained. There is now a shipbuilder with a permit to build ships for carrying CNG. And Pacific Northern Gas, the company that has recently taken over ownership of Southcentral utility, Enstar Natural Gas Co., operates a pipeline system for delivering Canadian gas to tidewater at Prince Rupert and Kitimat, British Columbia.
Pacific Northern Gas has expressed its willingness to support a CNG project, either through the use of existing pipeline capacity, or possibly through additional capacity, Thibert said.
CNG offers the advantage of tapping into supplies of cheap North American gas, while LNG purchased on the Pacific Rim would be much more expensive. And, while CNG is much more costly to transport than LNG, the shipping distance from British Columbia would be less than 1,000 miles. CNG is easier to load and offload than LNG, and does not require expensive handling and regasification facilities.
While the concept of importing gas is an anathema to many Alaskans, the utilities say that their duty to reliably provide energy leaves them with no alternative to this course of action.
“We have to keep the lights on and the homes heated, so we don’t really have any other option,” Thibert said.