Utilities in Southcentral Alaska have asked for proposals for liquefied natural gas or compressed natural gas imports to help ensure local gas supplies, a utility group told the Regulatory Commission of Alaska Oct. 24.
Gas fields in the region, which date from the 1960s, are being depleted, and production will be inadequate to meet local demand for space heating and power generation by as soon as 2014, said Lee Thibert, vice president for strategic planning for Chugach Electric Association, the state’s largest electric utility.
Thibert was speaking for group of five regional Alaska utilities and Donlin Gold, a mining company which needs natural gas to power a large gold mine the company plans in Southwest Alaska.
Besides Chugach and Donlin Gold, the group includes the regional gas utility, Enstar Natural Gas, and three other electric utilities, Homer Electric Association, Matanuska Electric Association and Anchorage’s city-owned Municipal Light & Power.
There is new exploration drilling under way in south Alaska and some gas discoveries are being made, but permitting requirements and lead-times for construction, particularly offshore, will prevent gas being available to meet the projected 2014 shortfall, said Colleen Starring, CEO of Enstar, the gas utility.
The electric utilities have some ability to switch to oil but Enstar is totally dependent on gas.
“If gas is not available our only choice is curtailment,” she said, a gloomy prospect if it happens during the Alaskan winter.
Assuming no substantial reserve additions the gas supply gap in the region begins at about 10 percent of current demand in 2014 and grows to a 50 percent shortfall in 2019, according to an analysis by Petrotechnical Resources Alaska, a consulting group hired by the utilities. Total gas use is about 110 billion cubic feet per year, with utilities using about 70 billion cubic feet annually. Gas is also used as fuel for a Tesoro Corp. refinery near Kenai and offshore oil producing platforms in Cook Inlet.
Even with an optimistic reserve additional assumption of 20 million cubic feet per day of new production added per year the gap is still 25 percent of demand by 2019, according to the PRA study.
New exploration in the region could result in more substantial new supply by 2017, however, and a state corporation working on a 24-inch gas pipeline from the North Slope could meet the shortfall by 2020, but a gap between 2014 and 2017 remains under almost any scenario.
Thibert said the utilities working issued Solicitations of Interest for LNG or CNG supplies two years ago and have already met with one group of potential suppliers, he said. The utilities have hired an Alaska economic consulting firm, Northern Economics, to help them decide between LNG or CNG.
They will make the decision by the end of the year and are planning to spend $5 million next spring on engineering for facilities in Alaska needed for LNG regasification or CNG depressurization. The utilities will ask permission from the Regulatory Commission of Alaska to include that expense in their rate base, Thibert said, along with, eventually, an undefined larger amount for construction of facilities.
The group has also been in discussions with ConocoPhillips on converting its LNG plant at Kenai to a regasification and import facility. The plant is still making LNG and shipping it to Japan, but the LNG export license for the plant expires next March.
ConocoPhillips has made no statements on its plans for the facility, but in their planning the utilities assume exports will cease.
Thibert said gas imports would likely be in small increments at first so as to not disrupt exploration efforts under way. If those are unsuccessful the imports can be expanded.
The group has been working on import options for some time but did not seriously consider compressed natural gas until recently because of the lack of a licensed vessel for transporting CNG as well as an ability to get gas to tidewater in the Pacific Northwest.
Recently, however, the group has been in contact with three shipbuilders who are able to build CNG vessels, Thibert said. Once built, the vessels would have to be licensed by the American Bureau of Shipping as well as the U.S. Coast Guard if they are to operate in U.S. waters.
Citing confidentiality, Thibert said he could not identify the shipbuilders.
The utility group has also been in contact with Pacific Northern Gas in British Columbia, which currently delivers gas from Canadian producing areas to two ports, Prince Rupert and Kitimat, B.C.
Thibert said the LNG options being considered include conventional ships like those now carrying LNG from the Kenai plant, LNG vessels with ship-mounted regasification and LNG barges that would be towed by tugs.
Ironically, there are large resources of stranded gas on Alaska’s North Slope, about 800 miles north of Anchorage, which is on the state’s south coast. Unfortunately, there is no pipeline now available to bring gas south from the slope, although producing companies and the state are working on a pipeline plan.
Tim Bradner can be reached at firstname.lastname@example.org.