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Vol. 12, No. 4 Week of January 28, 2007
Providing coverage of Alaska and northern Canada's oil and gas industry

Export extension filed

Nikiski plant partners Conoco, Marathon apply to extend LNG license 2 years

Kristen Nelson

Petroleum News

John Barnes, manager of Alaska production operations for Marathon Oil, broke the news at The Alliance Meet Alaska conference Jan. 19: Nikiski LNG plant co-owners Marathon and ConocoPhillips had filed for a two-year extension of the export license for the plant.

Why the extension application, with concerns about Cook Inlet gas supplies?

Barnes said “the industrial use of natural gas in Cook Inlet is good, it’s important, it creates jobs, it creates opportunities.”

And, he said, the LNG plant “provides supply security to Southcentral utilities. Having that plant running provides for the ability to move gas away from the plant to serve local utilities if there’s an extreme cold weather event or upset in the system.”

Southcentral industrial users will be necessary to provide the economics for a spur line to Southcentral from a North Slope gas pipeline.

And there’s been talk about using the plant as an LNG import facility “or bridging tool until you get to that spur line. That won’t happen if that plant’s not running,” he said.

Barnes said his answer to why an extension should be granted is: “It makes good sense.”

License expires in 2009

Many gas discoveries were made in the 1950s and 1960s when companies drilled for oil in the Cook Inlet basin.

The Kenai liquefied natural gas plant, and the nearby fertilizer plant, were built to make use of the gas.

The LNG facility began operations in 1969, the companies said. It employs 58 people and supports another 128 jobs in the Kenai community.

The present export license expires in 2009; the extension would allow export of LNG for two more years, to 2011.

The plant, operated by ConocoPhillips, is owned by ConocoPhillips (70 percent) and Marathon Oil Corp. (30 percent.)

Darren Jones, ConocoPhillips Alaska vice president of commercial assets, told Petroleum News in an interview after the announcement that the application has been turned into the Department of Energy but won’t be public until DOE determines it is complete and notices it in the Federal Register.

The last two export license extensions have been for five years, he said.

Why a two-year extension?

Jones said “it’s really a recognition of the fact that there is a change in the Cook Inlet gas market,” with questions being asked about whether or not there are sufficient supplies.

He said the utilities “pretty much have gas through that time so it’s not a big issue there. At least they’ve identified gas sources.”

Barnes said the extension issue is federal, “although they will take input from the local communities and they will consider … the U.S. and local gas needs in their application review.”

Extension would drive activity

The extension would “drive increased activity for ConocoPhillips,” Jones said.

Overall activities include additional seismic planned with partners at the Beluga gas field, which ConocoPhillips operates.

The main source of ConocoPhillips’ gas for the LNG plant is the North Cook Inlet field, produced from the Tyonek platform.

“We’re planning two to four additional wells” at a cost of $10 million to $20 million each to support the license extension, Jones said, “so one of the reasons this is a good thing is it helps drive increased upstream activity in Cook Inlet.”

Natural gas drilling in the inlet was light from 1985 to 2000, Jones said, but in “the last five years 75 wells have been drilled,” as local natural gas prices started to move toward world market prices. “Southcentral still has a benefit vs. the world market,” he said, but prices have gone from about $1.50 per thousand cubic feet to more than $4, which has spurred activity.

Supply and demand are now in better balance, Jones said. Some 8.5 trillion cubic feet of natural gas were discovered in the Cook Inlet basin in the 1950s and 1960s when companies were searching for oil.

“That’s why the LNG plant and the fertilizer plant were built, was to monetize all that excess gas,” Jones said.

“We’ve still got some excess gas, which is why we can go ahead and export it,” he said.

And because prices are up, “we can go ahead and drill,” Jones said. Wells at the North Cook Inlet field will be in-fill drilling, delineation wells, rather than rank exploration, he said.

Marathon has been drilling for a number of years — it built in its own rig for its onshore gas drilling seven years ago — and Barnes said drilling “activity has been part of our longer-term plans.” If there’s a market, he said, “there’s … resource opportunities to pursue” and extension of the LNG plant license “is a critical part of maintaining that market.”

Marathon will continue to work onshore, Barnes said: “We’ll stay where we’ve been playing.”

What about the market?

Jones said the LNG plant’s customers “are very interested in gas from this project.”

Alaska gas is only 1.5 or 2 percent of their supply now and would fit into their supply portfolio, Jones said.

“They’ve told us … we’re interested; we’ll talk to you when the time is right.” And that time will be right, he said, when we have permission to export. They don’t want to negotiate a contract and then find the gas can’t be exported.

Based on DOE precedent you need a gas sales contract for a five-year extension, Jones said, but not for a two-year extension.

As to how long the DOE process could take, Jones said it took two years last time.

The drilling ConocoPhillips has planned at its North Cook Inlet field is tied to the export license extension.

Without the export extension, Jones said, the economics aren’t there to drill the wells because there is no utility demand for the gas.

The plant is in good shape, Jones said. Because the gas is almost 100 percent methane, with very small amounts of impurities, in the old vessels at the plant “you see the chalk marks from the original measuring and cutting the steel” because the surfaces are so clean.

Pieces of equipment have been replaced at the plant, most recently the turbine on the fuel gas compressor, “so we’re making investments so the plant is able to go on into the future.”

The LNG tankers were replaced in the late 1990s, Barnes said.

Deliverability the issue

Recently there’s been a hitch in contracting for gas supply.

The Regulatory Commission of Alaska rejected a proposed Marathon-Enstar Natural Gas supply contract last year.

Barnes said “the key point to remember out of that — it’s not an issue with the gas.” RCA disagreed with the pricing structure in the contract, he said, “it’s not about the gas available.”

“Gas was offered,” Barnes said, adding that it’s not correct to say there is a gas shortage.

RCA rejected the contract. “But the issue that’s left hanging, really, is what is an acceptable price model?”

The commission had previously accepted pricing models based on Henry Hub spot market prices, but rejected this contract.

Barnes said it isn’t a gas issue, “it was about a price model that they were stepping away from.”

How much gas is there? Depending on the study you look at, Jones said, there is 1.6 to 1.7 tcf, with the Alaska Department of Natural Resources showing about 1.6 tcf of resources “proved or probable reserves in the basin.”

But, Jones said, on the coldest days there is a deliverability challenge.

ConocoPhillips is putting in compression at Beluga right now and put in compression on the Tyonek platform a couple of years ago, Jones said. “The additional wells we’re planning to drill help meet that short-term deliverability, so one of the key benefits of having the LNG plant is that it’s a key part of the Southcentral energy infrastructure. If we have a really cold day, or if there was a system breakdown somewhere, we can bypass the plant” and easily provide that backup supply “with minimal impact to the facilities.”

If the LNG plant wasn’t there, “the local utilities would have to charge the consumers to either pay a lot more for more people to drill more wells … or they would have to invest in a lot of storage.” Upstream companies are now trying to develop storage, he said, “but you need that backup, you need a plan B if something goes wrong, either short-term or if there’s a breakdown in the system, the LNG plant acts as that plan B, and that’s very valuable.”

“We’re willing to work with those needs and turn the plant up and down,” Jones said. That “subsidizes yours and my gas price. We don’t have to pay for that backup.”

Bill Popp, special assistant to the mayor and oil, gas and mining liaison at the Kenai Peninsula Borough, said that in the Lower 48, where utilities pay for gas storage, “they pass that cost for storage on to consumers.”

Borough waiting to see application

Popp told Petroleum News the borough administration supports the application being filed.

But it hasn’t decided whether or not it will support the export extension application.

“We have not passed judgment yet on whether or not we’re going to support the ultimate outcome of that application, because we need to see it, we need to understand it and we need to put it in context with all the other issues that we’re balancing in terms of the regional supply picture, as well as the direct economic benefit that the plant provides to the local economy,” he said.

In addition to its importance to the Kenai Peninsula economy, the LNG plant is “also important in terms of maintaining a demand picture” for a future connection with a North Slope gas pipeline spur into Southcentral Alaska.

“If that ever becomes a reality,” Popp said, “it’s going to be based in no small part on having enough demand, which is going to be focused quite a bit on the industrial side of the piece at the end of the pipe.”

Enstar opposes extension

Enstar Natural Gas Co., the Southcentral gas distribution utility, opposes the extension. For now.

“We are opposed to it as long as long-term gas supply contracts are not in place for consumers in Southcentral Alaska,” said Curtis Thayer, Enstar’s director of government and public affairs.

With the rejection by RCA of the Enstar contract with Marathon, Enstar starts to have a shortfall in gas in 2009 of 1.5 billion cubic feet a year, out of some 30 bcf the company expects to need in 2009.

In 2010, he said, the shortfall would be 5 bcf.

Those are estimates, Thayer said, because customers keep coming back to Enstar as other suppliers are unable to deliver gas. In 2006, 4 bcf returned to Enstar as customers, including the State of Alaska, the Anchorage School District, the Municipality of Anchorage and Fairbanks Natural Gas.

This doesn’t change what Enstar makes because it charges to transport, but it needs more gas, Thayer said. The contract RCA rejected would have provided that supply through 2016 and into 2018.

He said Enstar wants to see its long-term gas supply go past the extension period.

Enstar is planning to go out with a request for proposals to all Cook Inlet producers for gas starting in 2009, and hopes to get long-term contracts. But, he said, only Marathon responded to the last RFP.

The Marathon contract took six months to negotiate and a year for the RCA process.

It’s 2007 and Enstar has a shortfall in 2009, Thayer said.

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