Will they or won’t they? Without viable economics accounting for the risks involved, North Slope producers cannot make long-term commitments to the “global mega-project” to build a pipeline from Alaska’s North Slope to the Lower 48 states, the producers told Alaska legislators last week. But a MidAmerican Energy executive suggested the producers’ are “posturing,” and in the end will sell their gas through the pipeline.

Lawmakers should not underestimate the “world-scale undertaking” involved in the largest private investment in North America, Martin Massey, joint interest manager for ExxonMobil, told members of the Alaska state finance committee on Wednesday. He said the cost estimate of $20 billion was made in 2001, but today it would be substantially higher. For one thing, he pointed out that the price of steel has doubled.

The plan advanced by Alaska Gov. Sarah Palin for the pipeline construction, the Alaska Gasline Inducement Act (AGIA), does not account for the upstream risks faced by producer shippers, Massey said.

It is the shippers who will be underwriting the project by making long-term capacity commitments. The project will be built “directly on the backs of long-term transportation commitments,” Massey said, and the upstream and pipeline economics must be integrated.

“Only a limited number of companies are capable of mega-projects,” Massey said, noting that there are not many with the experience in large projects around the world and the financial strength to pull it off. The producers can handle the geologic risk, the risk of cost overruns and the risk of volatile natural gas prices, he said, but they cannot cope with changing fiscal rules imposed by the state. The rules for taxes and royalties need to be “durable and predictable before producers commit to the long-term contracts necessary to get the project financed.”

Massey, the third representative of the three major North Slope producers to testify before the committee, said the rules laid out in the AGIA for companies to bid to construct the pipeline are too prescriptive, and are not likely to foster competitive bids for the project. The producers recommended that the project rules be more flexible to allow project sponsors to develop viable plans.

If the pipeline project goes forward, however, North Slope producers are not likely to withhold their vast reserves of Alaskan gas because they could be accused of antitrust behavior, and it would work against the interest of their shareholders to pass up the opportunity to monetize stranded gas, Kirk Morgan, president of Mid-American’s Kern River Gas Transmission Co., told Alaska legislators in another session last Thursday.

Morgan said his company would be willing to go ahead and seek a certificate from the Federal Energy Regulatory Commission, with the backing of the state of Alaska, even if an open season for the mega-pipeline project was initially unsuccessful.

“I don’t think it’s a sustainable position for producers to withhold gas,” Morgan said. “It’s their duty to develop and market gas. For them to withhold gas would be engaging in the type of behavior that is clearly anti-competitive. The Energy Department, FERC and the companies’ shareholders all would be concerned with them not developing their gas,” he said, describing their current stance as posturing. “They won’t pass up an opportunity to make $3-4 a dekatherm on their gas.”

Under the plan put forward by Alaska’s governor, following a determination that the project is economically feasible, the state would pay 80% of the $500 million cost of taking the project to the point of obtaining a FERC certificate. The pipeline project developer would pay the other $100 million. Morgan said MidAmerican, which is owned by the $37 billion conglomerate Berkshire Hathaway, would have no problem going forward on that basis even if an initial open season was unsuccessful in signing up the producers.

The MidAmerican position was in contrast to testimony from a TransCanada PipeLines representative, who wanted the AGIA changed so that the pipeline company would not be required to continue and seek a FERC certificate if the three major North Slope producers, who hold more than 90% of gas reserves in Alaska, did not sign up for capacity during the initial open season.

Tony Palmer, TransCanada vice president for Alaska business development, said the AGIA requirement to seek the certificate without the producers constituted a significant risk. TransCanada would prefer to continue to try to get the producers to sign on before proceeding. He asked legislators on the state House Finance Committee to amend that portion of the AGIA, although he admitted he had been unsuccessful in convincing the Palin administration to do just that. “We are concerned about development of the pipeline if it has not attracted enough of a commitment to make the project viable,” Palmer said, advising that TransCanada’s board of directors would have trouble committing $100 million without more certainty.

TransCanada has held a certificate for the pipeline in Canada for 30 years, Palmer said. The problem has been it has not been able to attract customers or shippers on a pipeline.

Meanwhile, Morgan wanted a provision added to the AGIA that would require applicants to disclose if any of their other business interests around the world conflict with the objectives of the pipeline project. He also said he did not believe the pipeline should provide “a bullet ride to Chicago.” That would put too much gas into one market and depress the price there. Rather, the pipe should go to the Alberta Hub for takeaway on various pipes to different markets.

One version of the project being contemplated would be a 1,750-mile, 48-inch diameter pipe from the North Slope to Alberta. Initial throughput would be 4.5 Bcf/d, with a potential to go to nearly 7 Bcf/d.

Anadarko Petroleum, which has a large acreage position in Alaska but no production, told legislators it probably would not be a bidder in the initial open season, but it wants to see the possibility for rolled-in rates included, since it could seek an expansion within two years of the project going forward, even before construction has started. The company already has done geologic and seismic work, but probably would not start serious drilling until it was likely the project was viable.

Mark Hanley, Anadarko manager of public affairs, said the AGIA should require the pipeline developer to seek rolled-in rates from FERC for expansions. Then it would be up to FERC to decide if the use of rolled-in rates would constitute a subsidy. He postulated, for instance, that if the initial tariff were $1.62/Mcf and the first addition of compression cost another $1.07/Mcf, the average of those costs rolled in would result in a lower tariff of $1.47/Mcf. If the next compression addition cost $1.73, that still would average out to $1.51, which is below the initial rate. The sticking point likely would come with looping, which could cost $3.25/Mcf. But FERC would have to decide if subsidizing the looping addition would increase the reliability of the pipe for all customers.

Hanley said Anadarko would like to see the AGIA stipulate that the pipeline developer may not negotiate rates that would not allow for rolling in. Also, the authority of FERC to order a design change should be preserved, for instance, if the agency decided the pipe was underdesigned with only 42-inch diameter pipe, which when fully compressed would only carry 4.5 Bcf/d, Hanley added. He said the large producers are challenging FERC’s authority to order a design change in the U.S. Circuit Court in the District of Columbia, calling this “a real red flag.”

Hanley also said Anadarko was concerned if the “inducements,” such as a locked-in tax rate would go only to the initial shippers, that would make it hard for expansion shippers to compete.

Finance Committee lawmakers, saying they believed ConocoPhillips might go forward with a commitment to the project, even if BP and ExxonMobil did not, asked if the pipeline would be feasible at only one-third the planned size. Morgan said it could possibly be “doable” with two-thirds the size, but they wouldn’t get the financing with only one-third. He noted there are doubts that the Mackenzie Pipeline, which is proposing to carry 1-2 Bcf/d, might not have sufficient economies of scale to be built (see Mackenzie story, this issue).

In late March, the federal coordinator for the Alaska natural gas pipeline project predicted that Palin would have a gasline bill on her desk by the end of the state legislative session and likely would issue a request for proposals in July (see NGI, April 2). The legislative urgency to get the project moving seems to be intensifying as the project’s backers continue to cast their doubts. In February, Sen. Lisa Murkowski (R-AK) said she felt like the “window of opportunity is closing” (see NGI, Feb. 26). FERC Chairman Joseph Kelliher said he backed Palin’s pipe proposal, calling it the “best hope” for an Alaskan gas pipeline.

Earlier in the week executives from BP and ConocoPhillips also told legislators the project criteria in the AGIA would have to be loosened or there wouldn’t be any viable bidders.

“There has been too much focus on the pipeline and not enough on the upstream,” said Brian Wenzel of ConocoPhillips. There needs to be a fiscal package for upstream resources with “long-term clarity on state taxes and royalties.”

Testifying for pipeline builder Enbridge, Ron Brintnell said his company was not interested in having the whole project. For his company a project that size would be “betting the farm.” Enbridge would like to be a 10-20% equity owner.

A proposal to build a long-line pipeline south from Alaska through Canada has been under consideration for 30 years. Most recently, a plan proposed by former Gov. Frank Murkowski got hung up in the legislature last year over the issue of resource taxes and royalties. In the meantime, some LNG receiving terminals are under construction that will bring competing gas supplies into North America.

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