Denali -- The Alaska Gas Pipeline, which is owned by subsidiaries of BP plc and ConocoPhillips, filed its open season plan last week with FERC for a $35 billion project to carry Alaska natural gas from the North Slope to Lower 48 markets. Denali said it expects the project to be in service in 2020.

The 886-page filing [PF08-26] outlines the commercial terms, technical plans, estimated costs and projected rates for the project.

The Denali project consists of a gas treatment plant (GTP) on Alaska's North Slope, transmission lines from Prudhoe Bay and Point Thomson fields to the GTP, and a mainline that would cross Alaska into Canada with its terminus at Blueberry Hill, AB. Also included would be delivery points along the route to help meet gas demand in Alaska and Canada.

"Since its inception in 2008, Denali has invested over $140 million and over 600,000 man-hours to significantly advance this project," said Denali President Bud Fackrell. "Our commercial offer includes competitive transportation rates and at the same time recognizes the significant risk that both Denali and its customers will take."

Denali's cost estimate for the GTP and mainline is US$35 billion, and Fackrell told reporters during a briefing last week that it's a pretty solid number. "This is not what's called a factored estimate," he said. "We got quotes on almost everything and have a very good idea of where the costs stack up now."

On March 31 the Federal Energy Regulatory Commission (FERC) approved the open season plan for the competing Alaska gasline project of TransCanada Alaska Co. LLC, called The Alaska Pipeline Project (see NGI, April 5), which has been proposed under the state's Alaska Gasline Inducement Act (AGIA). As such, it qualifies for a $500 million state subsidy for which the Denali project does not qualify (see NGI, Dec. 15, 2008). The TransCanada project, which has ExxonMobil as a partner, has a projected cost of $32-41 billion, and its open season is slated to begin April 30.

The estimated rate to carry gas from the GTP to Alberta on Denali is $2.67/MMBtu, including gas treatment but excluding fuel. That breaks out to 90 cents for the GTP, 80 cents for the Alaska mainline and 97 cents for the Canada mainline.

In a presentation earlier this year on its open season, TransCanada quoted a tariff range from a GTP to Alberta of $2.80-3.50/MMBtu including fuel and the services of the GTP.

"I'm actually quite pleased that after two months of them having a look at our proposal -- because we had to do that publicly -- it looks like their proposal basically matches our commercial terms," TransCanada Vice President Tony Palmer told NGI. "I think that customers will have to examine which alternative they think is more credible and which is more competitive and I think we've got some distinct advantages.

"I think that ExxonMobil and TransCanada's abilities to build a pipeline and gas treatment plant are unsurpassed. We're proposing an LNG alternative as well as the proposal to Alberta. A number of customers may want to have those alternatives. And certainly we're aligned with the state and we have a distinct advantage through Canada because we have a certificate to build a pipeline."

Fackrell would not entertain questions about the competition between Denali and the TransCanada project. "We're not going to be comparing our estimate [of costs and services] against theirs," he said, noting that prospective shippers will choose between the projects or choose none at all. "They are going to see every detail we've put together and every detail of TransCanada, and they will make the judgment of which project they want to sign up for."

And the door is open to ExxonMobil's upstream business and any other producers that want to participate in Denali, Fackrell said, echoing similar remarks made recently by TransCanada CEO Hal Kvisle. Fackrell said it would be "problematic" for Denali's producer partners to sign on to TransCanada's project because they do not agree with the conditions to which AGIA would bind them.

Among the hurdles to either project are a resolution of litigation dealing with the Point Thomson field on the North Slope between producers and the state (see NGI, Jan. 18), as well as the producers and the state coming to terms on production taxes, Fackrell said. Further, booming shale gas production in the Lower 48 and a surfeit of liquefied natural gas supplies worldwide make demand for Alaska gas less than a sure thing.

"People are not sitting there waiting for Alaska gas right now," he said. "We are going to have to compete, and to do that we're going to have to have an economic project, and we're going to have to compete heads-up with these other alternatives."

Denali has been designed to deliver approximately 4.5 Bcf/d to North American markets. The GTP at Prudhoe Bay would remove carbon dioxide (CO2) and dehydrate, compress and chill the gas in preparation for transport down the mainline. The GTP would be the largest facility of its kind in the world, Denali said.

The mainline would consist of a 48-inch diameter pipeline and 15 compressor stations, six of which would be in Alaska. The mainline would run approximately 730 miles through Alaska and 1,020 miles through Canada. Customers would be provided with multiple interconnect options to transport gas to markets in North America.

Denali said foundation shippers will need to have at least a "BBB" credit rating and be willing to commit to a 20-year agreement. There is no minimum volume requirement, though, and Fackrell said it hopes that smaller leaseholders, explorers and end-users, as well as the state of Alaska, will participate in the open season.

For their commitment foundation shippers will get a five-year extension option; negotiated, levelized rates; and a "most favored nation" clause, as well as recognition of the project's uncertainty with decision points available as new information becomes known. Denali said it is willing to risk that 20% of its capital cost can be recovered from "late-life" shippers. It also said existing shippers will not be required to subsidize expansion shippers and that it is willing to consider project alternatives, such as a reduced-capacity project.

The project as currently proposed does not include an option to carry gas to a liquefied natural gas (LNG) liquefaction plant for export to Asian markets or to the U.S. West coast, should a regasification terminal be built there. The TransCanada project does offer such an option. Fackrell said the project backers would consider adding such a feature to Denali should the open season reveal a demand for it.

Denali said it anticipates FERC approval of its plan and is planning to start its open season on July 6 to run for at least 90 days with a simultaneous open season in Canada.

"The Denali commercial offering is based upon a high-quality cost estimate and includes terms that will provide customers decision points as the project progresses," said Fackrell. "We believe our technical work and our commercial offer provide the best opportunity for potential customers to evaluate the competitiveness of Alaska North Slope natural gas sales."

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