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Southcentral utilities plan to import gas to meet projected 2014 shortfall

Posted: November 1, 2012 - 3:20pm

Like it or not, new gas supplies will have to be imported into Southcentral Alaska to deal with pending shortages. They won’t be cheap, either.

Utilities in the region have asked for proposals from suppliers of liquefied natural gas or compressed natural gas to help ensure local 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.

 “We’ve kicked this around for 10 to 12 years. We don’t have any more time left,” Matanuska Electric Association General Manager Joe Griffith told the RCA.

Chugach Electric Association’s Manager Brad Evans agreed. 

“I’m done wringing my hands over this. We’re a little late, but it’s time to move. We need less study and more action,” he said.

Colleen Starring, president of Enstar Natural Gas Co., joined in: “We will be making a decision to move forward,” she told the regulatory commission.

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, have been working on the gas supply problem for some time.

Besides Enstar, Chugach and MEA, utilities at the RCA hearing included Anchorage’s city-owned Municipal Light & Power and Homer Electric Association.

Evans expressed frustration over a lack of concern from the state administration over the regional gas supply problem. “We’ve been asking the administration to come up with a regional resource plan but there has been no response. Now the utilities will have to do this ourselves, and it puts us in an awkward position,” Evans said at the RCA hearing.

Gov. Sean Parnell had been briefed on the problem recently, sources in the utility group said, but the governor made no response at the meeting.

There is new exploration drilling under way in southcentral 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, Starring told the commission.

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,” Starring said, a gloomy prospect if it happens during winter.

Lee Thibert, vice president for planning for Chugach Electric, said gas imports would likely be in small increments at first so as to not disrupt exploration efforts underway. If the exploration is unsuccessful in supplying enough new gas the imports can be expanded.

Assuming no substantial new gas reserves are added in the existing fields through producers’ investments, the supply gap in 2014 is estimated at 11.4 billion cubic feet, according to a study of Southcentral gas reserves by Petrotechnical Resources of Alaska, a consulting firm hired by the utilities. This is about a third of the annual requirement for Enstar Natural Gas, which is about 33 billion cubic feet.

Under this conservative assumption — no major reserve addtitions — the gap would grow to 41.8 billion cubic feet in 2017, according to the PRA study. This is over half the regional utilities’ total gas requirement of about 70 billion cubic feet annually, combining Enstar’s requirement with the electric utilities. 

If there is continued investment by producers in the current fields that results a net gain of 10 million cubic feet per day, with the decline being more than offset by new gas, this would reduce the 2014 gap to 5.1 billion cubic feet. Under this assumption the 2017 gap would be reduced to 29.2 billion cubic feet. That is between a third and one-half of the utilities’ total requirement. 

If there is more new investment by the producers, enough to get a net gain of 20 million cubic feet per day, the 2014 gap vanishes, the 2015 gap shrinks to 11.4 billion cubic feet and the 2017 gap drops to 16.6 billion feet. 

By 2017 there could also be some new production from exploration work being done now in the region, particularly from onshore discoveries on the Kenai Peninsula and west Cook Inlet that are near existing gas pipelines.

There could also be more natural gas available after 2017 offshore Cook Inlet exploration wells now being drilled find gas. Although oil is the main target for these drillers — oil is more valuable — it is likely that some gas will also be discovered. However, it will take time to secure permits and build new offshore platforms and pipelines to get the gas ashore.

Also, a state corporation, the Alaska Gasline Development Corp., is working on a 24-inch gas pipeline from the North Slope that could supply gas from the slope by 2020, if the Legislature approves funding to continue work on the project. 

Under even optimistic scenarios for exploration success, however, a gap in gas supply remains between 2014 and 2017, and gas imports will be needed, utility representatives told the RCA. 

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 also hired an Alaska economic consulting firm, Northern Economics, to help them decide between LNG or CNG.

The decision on which course to pursue must be made by the end of the year, he said. The utility group must then tackle the engineering and permitting needed for facilities in Alaska for LNG regasification or CNG depressurization. About $5 million will be needed for this.

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. Also, the regulatory commission will have to come up with some way of insuring the utilities don’t get caught with big stranded investments. This could happen if substantial sums are spent on gas import facilities and then an explorer makes a big gas discovery, to the point that the import facilities are mothballed.

There have also been in discussions with ConocoPhillips on converting that company’s 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.

As to whether liquefied natural gas or compressed natural gas should be imported, there are advantages and disadvantages in either case, the utilities told the RCA.

LNG’s advantage is that the technology for storage of LNG and regasification is well known and long-used, and LNG ships of various sizes are available. The major disadvantages are that the source of the LNG is likely to be Asia, where it is priced at almost twice what gas produced locally is now sold for in Southcentral Alaska.

LNG could also be imported from British Columbia if LNG export plants are built, but those may be years away.

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.

The major advantage of compressed natural gas, or CNG, is that it can be purchased in North America for very attractive prices – the glut of shale gas on the market has depressed prices – but there are now no available CNG vessels to bring it to Alaska. 

Thiebert said the utility group did not seriously consider compressed natural gas until recently because of the lack of a licensed vessel for transporting CNG, as well as questions about the ability to even get gas to a port 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 the vessels are ordered it would take 12 to 18 months for construction, most likely in South Korea, he said.

Once built the vessels would have to be licensed by the American Bureau of Shipping as well as the U.S. Coast Guard, for operating in U.S. waters. Citing confidentiality, Thibert said he could not identify the shipbuilders.

Although there are no ships available, mainly because of the lack of demand, the basic technology of shipping compressed natural gas in marine vessels has been around for decades.

The utility group has also been in contact with Pacific Northern Gas in British Columbia, a pipeline company which currently delivers gas from Canadian producing areas to two ports, Prince Rupert and Kitimat, B.C.

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 is a reporter for the Alaska Journal of Commerce.

 

 

 

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