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Providing coverage of Alaska and northern Canada's oil and gas industry
September 2006

Vol. 11, No. 38 Week of September 17, 2006

Producers: Resource drives project

ANGDA board concerned about in-state participation in open season for North Slope gas pipeline, growing in-state demand

Kristen Nelson

Petroleum News

The Alaska Natural Gas Development Authority asked the Alaska gas project sponsors — BP, ConocoPhillips and ExxonMobil — for information on financing for a North Slope natural gas pipeline to Lower 48 markets.

ANGDA is working on a proposal for a spur line from the main line to bring natural gas to Southcentral Alaska.

Joe Marushack, ConocoPhillips Alaska’s vice president, Alaska North Slope gas development, joined by Ken Konrad, BP Exploration (Alaska)’s senior vice president for gas and ExxonMobil Production’s Alaska production manager, Richard Owen, met with the board Aug. 28.

Equity at risk

Once the fiscal contract is signed the companies will request authorizations for expenditures in the $100 million to $200 million range to get the project up and running, put a team together, “do another cost estimate and find out about the steel” and things like water crossings, Marushack said. That way when the project goes to the companies for the big money, $1 billion or so to get as far as the open season, “we’re going to have some basis for that — it’s not going to be just five-year old data.”

He said they’ll look at things like the right kind of steel. The preliminary study looked at 52-inch X-80 for the pipeline, inch and a quarter thick steel. But “there’s a tradeoff between steel and compression,” and with steel prices going up you may want less steel, maybe 48-inch X-100, with more compression.

It’s those kinds of questions, Marushack said, that will be addressed first.

A year or a year and a half into the project, with preparations under way for the open season, the project will go back to company boards with a request for $800 million or a billion dollars, enough money to get the gas pipeline to project sanction.

“So you do all your engineering, you get all your permits,” you get board approval, “then towards the end of that you’re starting to talk about how you get financing,” Marushack said.

Once the project has gone through the open season, gotten its permits and completed front-end engineering design, that’s when there are financing discussions and the request for authorization for construction, $19 billion-plus.

ANGDA Chief Executive Officer Harold Heinze noted that the companies would be working within the pipeline entity, the limited liability company which will actually own the pipeline, but still needed individual board concurrences.

BP’s Konrad said there would be a number of funding gates and in each case the approval comes from the individual companies as well as the state.

Upstream group looking at open season

Marushack said an upstream group is already looking at what it will take to make an open season commitment.

“Each field will look at how they make a nomination,” he said. That off-take planning has to be coordinated with the Alaska Oil and Gas Conservation Commission and will be based on engineering studies the companies have done.

“We’ve got to do that for every field,” he said.

Each company will have to approve the commitment, he said, because it will be a 20-year commitment to meet a tariff for whatever volume the company nominates. “And what I mean by that is, if the project gets built, we ship. If we have field problems (and can’t ship), we pay.” The commitment is a “very, very significant” one for a board to make. If the cost doubles, then the commitment doubles, he said.

Konrad said a company may also want to make a commitment based on its exploration portfolio, and may risk committing to shipping capacity based on undiscovered fields. Initial gas for the line will come from Prudhoe Bay, where gas is re-injected, and Point Thomson, where the condensate reservoir has been known for several decades, but is not in production.

That can work for a big company, Marushack said, because their balance sheet backs the shipping commitment. “On the other hand, if you have a company with no assets” that wants to commit to capacity “and they can’t back it up so that the pipeline company knows it’s going to be paid, they’ll probably be rejected.”

“It’s not the gas necessarily … it’s the company making the shipping commitment,” Marushack said.

Open seasons concerns

ANGDA Chief Executive Officer Harold Heinze said one concern ANGDA has is “problems related to the small in-state users and their participation at a commercial level.” Every electric utility, he said, would have to hire a lawyer to advise them on contractual terms, so ANGDA has looked at enabling in-state utilities “to look at a contract that’s been reviewed by somebody other than the pipeline company.”

Konrad said there is a role for aggregators, “that’s the way the market works.” Natural gas marketing aggregators are a big business, he said, and there might be a role for ANGDA as an aggregator.

Marushack said the open season is critical: “You can’t design until you know what people are willing to ship,” he said. The open season determines the size of the pipeline and “helps you determine whether the project’s viable commercially and if you can get financing.” Completion guarantees have to be in place, he said, before the federal loan guarantees would kick in.

ANDGA Board Chairman Andy Warwick asked how the federal loan guarantees work and Marushack said they would be another backstop which might lower the interest rate a little.

Would the federal government be left holding the bag on the line? Warwick asked.

Konrad said it would have to be a catastrophe — companies would have to go bankrupt.

Or abandon the project, Warwick said.

Marushack said if the project was abandoned the project sponsors would still be on the hook.

The federal legislation specifies that you have to finish building the line once you start drawing funds, Konrad said.

Marushack said a scenario where the federal loan guarantee could kick in would be if the project was built and up and running, “we’ve met all the completion criteria so it’s capable of producing,” and the gas market tanks, goes back to $2 per thousand cubic feet and one of the companies goes bankrupt. Then, he said, the loan guarantee would kick in.

Konrad said that if a small shipper couldn’t meet its shipping obligations then it wouldn’t be the loan guarantee — that’s just the pipeline owners — the small company’s equity would be the backup for its shipping obligation.

Initial money straight from companies

The money funded before project sanction, the $1.5 billion or whatever the total ends up being, comes straight from the companies and is not backed by a loan guarantee: “We could actually fund a billion and a half dollars and have it go south on us,” Marushack said.

There are demands for steel, construction equipment, skilled labor, he said, and regardless of what project you’re talking about, “nobody’s project has the steel necessary to do this project,” he said. It will take time, measured in years, to work with the steel companies, he said, and it doesn’t make sense to buy materials before you have all your permits.

The most challenging issues during project development, he said, are fiscal contract approval, commercial issues such as shipper commitments, engineering issues such as crossing the Brooks Range and obtaining enough throughput information from shippers to support design work, and environmental and public involvement issues: obtaining government approvals, rights of way and permits in a timely manner.

Once the fiscal contract is signed a two-year period of planning and application preparation begins: the open season occurs at the end of this time. Then the producers estimate it will take two years to obtain permit approvals, followed by five years of project execution: a continuation of detailed design, equipment and material supply and module fabrication, pre-construction, construction and commissioning of the line. It is expected to take a year to go from first gas to full capacity — nine years from fiscal contract approval to first gas, 10 years to having the line full.

Marushack said the one-year first phase is what costs maybe $100 million; the one-year second phase maybe a billion. Once you have the open season and have shipping commitments, spending on a project like this grows exponentially, he said.

Appeal of ownership may change once project up and running

Comparing all the different projects doesn’t make much sense to the producers because “the shippers, the owners of the resource, have to get help with this … so you can’t compare projects, because other projects can’t do the resource side,” Marushack said.

The shipping commitment “allows the pipeline company to repay its debt, pay its return on equity.” The shipping commitment allows the pipeline to obtain financing because “the commitments serve as collateral for the financing,” he said.

Heinze asked about initial producer support of the Lower 48 Alliance Pipeline and Marushack said the producers are still behind it through their shipping commitments. Interest in ownership changed over time. The producers wanted to know it was a real project, that it wouldn’t blow up on them and to try to have some control. Once it was built, ownership wasn’t so crucial.

“And that may happen on this project,” he said.

The North Slope pipeline is actually a little more like an international project and producers are having to move more and more into infrastructure abroad, Marushack said.

“There’s typically more risk early on,” where you’ve put a billion dollars out front, Konrad said. “It’s the people with money who tend to do it. At that phase they’re the deep pockets and then as the risk decreases … over time then it becomes a more comfortable investment.”

Questions unanswered

There were a couple of questions left unanswered — one of which Marushack called a discussion for another day.

The first was the composition of the gas. Heinze said ANGDA needs to understand more about the composition of the gas, and noted that a figure of 1,080 British thermal units was about 20 years old. He asked for a compositional breakout, rather than Btu, and said while he knows the information will be public eventually hearing only the Btu value of the gas was like being told the answer without seeing the numbers.

Marushack said they need to make it through the open season and see who nominates what, what fields the gas is coming from and then they’ll have a better idea of the composition. “I know you’re saying that’s too late,” he told Heinze.

Warwick said he was concerned that as the demand for gas grows over time in Fairbanks that they could end up paying the Chicago tariff for additional gas. The issue, he said, is not knowing at an open season what the ultimate in-state demand will be.

Konrad said “no matter how poorly you plan, the gas in Fairbanks will always be cheaper than the gas in Calgary or the gas in Chicago.”

Warwick agreed that would be true for gas committed to in the initial open season — but said he was concerned about the price for taking off additional gas at a later time.

Heinze said ANGDA’s concern is “the bootstrapping issue here in Alaska,” that as gas becomes available the demand for it will grow.

Enstar (the Southcentral local gas distribution company) started with some 10,000 customers and grew to 10 times that, Warwick said, and Fairbanks will also see growth in demand once North Slope gas is available there.

Marushack said this was another day’s topic, but agreed with Warwick and Heinze that the state has got to be able to get the gas it needs. He also noted that the State of Alaska, under the proposed contract, would have 800,000 to 1 billion cubic feet of gas a day.






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