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Vol. 16, No. 12 Week of March 20, 2011
Providing coverage of Alaska and northern Canada's oil and gas industry

Keeping all options open

ConocoPhillips plans to preserve Cook Inlet LNG plant for possible future use

Alan Bailey

Petroleum News

When ConocoPhillips announced in February that it would close the LNG plant that it operates on Alaska’s Kenai Peninsula, the company said that it would begin mothballing the plant after it offloads its last consignment of LNG, probably in April or May. And at an Anchorage Energy Task Force meeting on March 15 Dan Clark, manager of Cook Inlet assets for ConocoPhillips Alaska, said that the company plans to put the plant into a “preserved condition.”

“Our intent is to preserve the plant so that whatever future opportunities might come up, whether it be future exports or an import situation, the plant would be in a position to be ready,” Clark said. Those opportunities could include conversion of the facility for importing LNG, to bolster local utility gas production, or restarting LNG exports, were some new source of Alaska gas to come online.

At the Energy Task Force meeting, Clark and several other officials from Cook Inlet gas and power businesses discussed some of the issues surrounding the closure of the plant.

Deliverability back stop

In addition to providing an industrial-scale market for natural gas from the Cook Inlet basin, the LNG plant has acted as a back stop for winter utility gas delivery in Southcentral Alaska: During periods of peak gas demand in severely cold weather ConocoPhillips has diverted gas, otherwise destined for the LNG plant, into the utility gas transmission network. And by providing a market outlet for gas from Cook Inlet wells during the summer, when utility gas demand is low, gas demand from the LNG plant has kept wells in operation year round, thus avoiding the risk of well deterioration, were wells to be temporarily shut-in.

In October 2010 the U.S. Department of Energy approved an application from ConocoPhillips to extend the export license for the plant from March 2011 to March 2013, but the company now says that it is closing the plant because of deteriorating market conditions. In February a Marathon official told The Associated Press that Tokyo Electric Power Co., the company that has been purchasing LNG from the plant for shipment to Japan, had decided not to renew its contract for the purchase of Cook Inlet LNG when that contract expires at the end of March.

Marathon co-owns the LNG plant with ConocoPhillips and is a major Cook Inlet gas producer.

But, regardless of whether the LNG plant were to remain in operation, supplying utility gas from the Cook Inlet basin is going to be difficult, given a continuing decline in peak winter gas delivery since 2006. After a slowing down of that decline since 2007, the decline has accelerated again to an annual rate of about 11 percent this winter, Clark said.

“Next winter there’s going to be a challenge in any circumstance, regardless of what the market does and everything else,” Clark said.

Critical time

Carri Lockhart, production manager for Marathon Oil Co. in Alaska, agreed, saying that the winter of 2011-12 will be the critical time for gas deliverability — the rate at which gas can be delivered. Much will hinge on whether the weather remains mild. Supply issues — questions over whether the total annual gas supply volumes will be sufficient to meet the utilities’ needs — will start to appear in 2013-14, Lockhart said.

And for several years Southcentral Alaska has been exposed to the risk of a major gas compressor outage somewhere in the gas infrastructure.

“If you have a major compressor going down, when it takes three or four months to secure a new one, that is a huge issue,” Lockhart said.

Lockhart said that she is encouraged to see two new operators looking for new Cook Inlet oil and gas. But she also pointed out the commercial challenges for explorers seeking to develop new gas resources in the Cook Inlet basin, given the need to make a return on investment in a gas market that is very small unless there is industrial gas demand.

Small market

“It’s a small market. There’s no doubt about it,” Lockhart said. “Cook Inlet will always be challenged in that regard of not having a massive market that’s fully open, like in the Lower 48.”

Lockhart said that, in addition to maintaining its gas storage facility in the Kenai gas field to bolster winter gas deliverability, Marathon has worked on its gas wells to enable the curtailment of gas production in the summer to lower levels than would otherwise be possible without damaging the wells. The company is also installing a bidirectional meter in the Kenai Nikiski pipeline on the Kenai Peninsula, to allow more flexible use of its Kenai storage facility, Lockhart said.

Clark said that, when gas demand slackens in the summer, ConocoPhillips will preferentially maintain production from wells that produce water along with gas, because those wells are most likely to suffer damage if shut-in.

Colleen Starring, president of Enstar Natural Gas Co., said that any damage to wells following well shut-ins could jeopardize Enstar’s ability to buy gas at short notice, to meet high winter demand.

“We’ve been fortunate, let’s face it, for the last two years. Mother nature has been extremely kind to Southcentral,” Starring said, referencing the relatively mild weather in the past two winters.

LNG imports

Lee Thibert, senior vice president of Chugach Electric Association, said that the Southcentral utilities are working together on various options to address the tightening gas supply situation, with the conversion of the LNG plant for the import of LNG being one of the possibilities.

“We’re all working very diligently, trying to look at all the options … trying to get something decided here, hopefully this summer,” Thibert said.

Daniel Helmick, manager of regulatory affairs for Municipal Light & Power, said that the utilities would not be surprised if they need to import LNG by 2013 or 2014.

“That’s probably what we’ll be working on night and day … for the next several months,” Thibert said. “It’s not attractive but I think we are in a position where we do have the obligation to serve the customer and make sure the lights are on.”

“There’s no doubt in my mind that we are going to import fuel, one way or another,” said Joe Griffith, general manager of Matanuska Electric Association. “I don’t sleep at nights worrying about what we are going to do for fuel in the future. … We can skin the cat but it may cost us a lot more than we would really like to pay.”

Clark said that ConocoPhillips has been investigating what would be involved in permitting the conversion of the LNG plant for LNG imports and had not found any major issues. The technical conversion of the plant would probably take about a year, he said.

New power plant

Thibert talked about the new state-of-the-art, gas-fired power plant that CEA and ML&P are building in south Anchorage. That plant will be 30 percent more efficient than the generating capacity that it replaces, thus saving about 7.5 billion cubic feet of gas annually, Thibert said. The new plant should go into operation by the winter of 2012, by which time CEA should also have available gas that it has stored in the new gas storage facility that Cook Inlet Natural Gas Storage Alaska is building on the Kenai Peninsula.

“The combination of those two (factors) will hopefully take care of the immediate needs,” Thibert said.

CEA has firm gas supplies under contract through 2013, is working on acquiring supplies for 2014 and has requirements partially met for 2015 and 2016, he said.

The utility is also addressing issues relating to the transportation of gas from the east side of Cook Inlet to the Beluga power plant on the west side of the inlet by working a project to allow bidirectional flow through the Cook Inlet Gas Gathering System, known as CIGGS, under the waters of the inlet — currently CIGGS only flows gas west to east.

Storage on the east side is of no use to either MEA or ML&P unless it is possible to move gas west under the inlet, Griffith said.

MEA is looking to buy a dual-fuel power plant, potentially to go into operation around September-October 2014, Griffith said, adding that he has been talking to gas independents about purchasing gas.

“I’ve told them I’d buy every molecule they can produce,” Griffith said.



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Accommodating Susitna hydropower

Asked how they would reconcile investments in new gas-fired power generation capacity with the possible future availability of power from a proposed major new hydropower system on the Susitna River, Southcentral electric utility officials told the Anchorage Energy Task Force on March 15 that they support the Susitna hydro proposal and will adjust to the use of Susitna hydropower as necessary. It is a question of allowing room for Susitna power, to accommodate the possibility of that power becoming available, said Lee Thibert, senior vice president of Chugach Electric Association.

Anchorage electric utilities Chugach Electric Association and Municipal Light & Power are already building a new, large gas-fired power plant, planned for startup in south Anchorage in 2012.

The new gas-fired plant will meet 50 percent of CEA’s base-load needs for the foreseeable future, Thibert said. The existing Beluga plant will supply much of utility’s remaining power needs, he said.

If the Susitna hydropower plant comes to fruition, power from that plant will replace power from Beluga, with CEA’s stable base load being filled by power from Susitna; the new gas-fired power plant would then be used to meet the more variable peaking demand. Essentially the role of the gas-fired plant would change and the plant has been designed to accommodate that change, Thibert said.

By using the relatively inefficient Beluga plant before new hydropower comes on line, CEA will incur relatively high fuel costs, although there is no outstanding capital cost for the aging Beluga plant, Thibert said.

—Alan Bailey