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Providing coverage of Alaska and northern Canada's oil and gas industry
July 2009

Vol. 14, No. 27 Week of July 05, 2009

Denali has spent $100 million to date

TransCanada ups Valdez line to 3 bcf due to LNG interest; BP, Conoco tell legislators numerous risks remain for potential shippers

Kristen Nelson

Petroleum News

Spending to date by the BP-ConocoPhillips Denali gas pipeline project totals $100 million, Denali President Bud Fackrell told Alaska legislators at back-to-back House and Senate hearings June 23 in Anchorage. That amount includes $55 million spent last year and $45 million so far this year, Fackrell said, adding that the company expects to spend about half as much again this year as it did last.

The competing TransCanada line, which is now partnered with ExxonMobil, has a license for a project under the Alaska Gasline Inducement Act. The AGIA license provides up to $500 million in state matching funds in exchange for commitments to a number of state “must-haves” for the project.

The TransCanada line would ship gas to Canada or Valdez, depending on shipping commitments it receives at its 2010 open season.

Tony Palmer, TransCanada’s vice president for Alaska development, said that in ongoing discussions with potential customers there has been sufficient interest in liquefied natural gas out of Valdez that the line going to Valdez has been increased from 2 billion cubic feet a day to 3 bcf a day.

After discussions with potential customers who believe it should be 3 bcf a day, that’s what we’re preparing, he said.

However, TransCanada doesn’t believe that sufficient gas commitments for both a 4.5-bcf line to the Lower 48 and a 3-bcf line to Valdez would be likely, Palmer said. A Valdez liquefaction plant is not part of TransCanada’s AGIA license, and would be the responsibility of the parties wishing to ship LNG out of Valdez.

$100 million to date

The $100 million spent to date was the estimate of first-year spending by BP and ConocoPhillips when the Denali partnership was announced in April 2008. The companies also said at that time that they expected to spend as much as $600 million to get to open season.

When ExxonMobil joined TransCanada on the AGIA project the companies said the amount they planned to spend prior to an open season had been increased to $150 million; TransCanada had originally proposed to spend $83 million through open season.

Doug Suttles, president of BP Exploration (Alaska) when Denali was announced, said at an April 8, 2008, press conference that the companies would begin field work in the summer of 2008, as well as engineering cost estimating and permitting planning.

“We intend to hold an open season beginning in late 2010, early 2011 — within 36 months — and spend up to $600 million for that effort,” he said.

At that time the company expected to have “150 employees or more before the end of 2008 and within three years time we expect to employ some 500 people and several thousand contractors,” Suttles said.

Rep. Craig Johnson, R-Anchorage, co-chairman of the House Resources Committee, asked Fackrell if the $125 million 2001-02 producer gas line study and trans-Alaska oil pipeline right-of-way work already paid for in the oil pipeline tariff would be included in the gas pipeline tariff and Fackrell said FERC would have to look at that. Johnson said he is compiling a list of items which could be included in a tariff and intends to verify with the Federal Energy Regulatory Commission that those items can be included. FERC has regulatory control over the gas pipeline project.

Denali employees

Fackrell told Sen. Tom Wagoner, R-Kenai, that Denali has 80 to 90 employees, some 75 percent of them in Alaska.

He said the company expects to begin its open season before the end of next year, but said Denali doesn’t view this as a race and wants to make sure it’s ready when the company begins its open season.

Therriault told Fackrell he’d heard that Denali had cancelled contracts and asked if the company intended to spend $600 million by open season.

Fackrell said the company has a very busy active program.

The 2009 program is broader than the 2008 program, he said, with a lot of extra contractors.

As for the total amount, he said Denali will spend the money it needs to spend to move forward and said they haven’t budgeted for next year.

Sen. Lesil McGuire, R-Anchorage, co-chair of Senate Resources, asked Fackrell about rumors that Enbridge, another Canadian pipeline company, would be partnering with Denali.

Fackrell said Denali wouldn’t comment on any private conversations it was having, to which McGuire responded that those private conversations were getting pretty public.

Agency work in tariff

On the Canadian side of the TransCanada project, Palmer said ExxonMobil has reviewed and endorsed TransCanada’s plan to proceed under the Northern Pipeline Act. The Northern Pipeline Agency is being restaffed, he said, to support permitting on the Canadian segment of the line.

Johnson, working on his list of tariff questions for FERC, asked Palmer if the cost of permitting would be absorbed by the agency or go into the tariff.

Palmer said TransCanada bears the full cost of the Northern Pipeline Agency work on the project; that cost will end up in the tariff, he said, adding that is the way most agencies in the U.S. and Canada work.

If the project is unsuccessful, however, the company’s shareholders bear those costs, Palmer said.

There was a partnership formed to build the Alaska portion of a gas line in the 1980s; all certificates held by that partnership have been returned to the agencies which issued them, Palmer said, and the partnership is in dissolution. Of the six partners in the previous project not owned by TransCanada, Palmer said the company has full releases from all but one and is continuing to seek that release.

Sen. Gene Therriault, R-North Pole, told Fackrell that Denali was still talking about the withdrawn partners issue a month ago. Is that issue put to rest, he asked?

Fackrell said Palmer’s information indicates it is a resolved issue for five of six of the withdrawn partners.

Another TransCanada issue is the “Fort Nelson upside.” One segment of the proposed line within Alberta, some 200 miles, could see an 18-cent-per-million British thermal unit reduction in tariff to Alaska customers if that segment were aligned, Palmer said.

He said a recent decision by the National Energy Board approving federal regulation for the TC Alberta System improves the chance of achieving the Fort Nelson upside, but is only a beginning step in achieving that upside and has not been achieved yet.

BP wants long tax certainty

The House Resources and Energy committees also heard from BP and ConocoPhillips in their roles as leaseholders and potential shippers of gas.

As BP Exploration (Alaska) Senior Vice President Claire Fitzpatrick told legislators, there are restrictions under FERC which force BP as a leaseholder and a potential shipper on a line to separate itself from BP’s role in a pipeline.

As a leaseholder and potential shipper, BP’s objective is to monetize gas, and for that the project needs to be economic, she said.

The company continually evaluates options to monetize gas, including evaluating four key risks.

Those include the presence of gas, because the 35 trillion cubic feet of known North Slope gas is not enough for 30 years, she said.

There is the market value of gas: There is huge volatility in gas markets today, and the concern for the gas pipeline is gas markets in 2020 and beyond, Fitzpatrick said.

Then there are the costs associated with the gas line, which feed into the tariff.

Fourth is the fiscal framework. She said BP hasn’t approached the state with what’s needed in tax and tax stability; that is an ongoing assessment, Fitzpatrick said.

Asked by Johnson when BP would have enough data to tell the state what they need, Fitzpatrick said that having resolution of the tax issues at the time of the open season could eliminate risk, but said they are still running analyses.

Rep. Jay Ramras, R-Fairbanks, asked Fitzpatrick if ExxonMobil getting acceptable fiscal terms from the state would make BP more or less likely to join that pipeline.

Fitzpatrick said the risk will depend on the terms. If terms are negotiated, she said she would like to think BP would be part of that negotiation.

Asked by Rep. Nancy Dahlstrom, R-Anchorage, if 10 years tax stability would be sufficient, Fitzpatrick said as a shipper BP would like the tax stability to match the length of the company’s gas commitment to the line.

Commitment is expected to be longer than 10 years.

Conoco believes risks high

Wendy King, ConocoPhillips Alaska’s vice president of external affairs, said that in its role as a shipper ConocoPhillips will look for the best overall solution to move its gas to market.

Each company’s view on long-term natural gas prices is proprietary, King said.

Other economic drivers the company looks at include what gas is available to ship — both the volume and for how long; the terms and conditions for shipment; the cost of transportation, the actual tariff; factors such as the length of shipping commitment, the financing and receipt points; and terms with the state and federal governments over tax and royalty structures.

King said ConocoPhillips believes risks still remain high for shippers on the project.

King told Ramras that ConocoPhillips sees the addition of ExxonMobil as a positive step and said that will help improve the quality of the open season. Referring to a comment that Exxon was a proxy for ConocoPhillips as a gas producer, King said the companies have different interests and different equities and highlighted Conoco’s role as an explorer on the North Slope.

Editor’s note: For other issues discussed at the June 23 hearings see “A blast from the past” in the June 28 issue of Petroleum News.






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