The Alaska Pipeline Project -- the gasline proposed by TransCanada Corp. and ExxonMobil Corp. -- has filed its open season plan with FERC, the company said last Friday. It is one of two competing projects proposed to tap the vast gas reserves of Alaska's North Slope for Canadian and Lower 48 markets but the first ever to file an open season for a North Slope pipeline.

The Alaska Pipeline Project is proceeding under terms of the Alaska Gasline Inducement Act (AGIA). A competing project, Denali -- The Alaska Gas Pipeline LLC, which is proposed by BP and ConocoPhillips, is not part of the AGIA process. It is expected to begin its open season in April (see NGI, Jan. 18a).

"The open season plan filing is an important step in the development of Alaska natural gas resources and we have worked diligently to advance the project," said TransCanada CEO Hal Kvisle. "This significant milestone demonstrates that we are meeting the AGIA commitments on schedule and in line with the required process, effectively aligning the interests of the state of Alaska, the project, shippers and other interested parties."

Two options are available for shipper assessment. The first option is a pipeline from Alaska's North Slope to Alberta, a distance of approximately 1,700 miles (2,737 kilometers), where the gas can be delivered on existing pipeline systems serving major North American markets. The second option would transport gas from the North Slope to Valdez, AK, a distance of approximately 800 miles (1,287 kilometers), where it would be converted to liquefied natural gas (LNG) in a facility to be built by others and then delivered by ship to North American and potentially international markets. Shippers wishing to export LNG would need to secure the necessary permits from the federal government.

Both options have an expected in-service date of 2020 and would provide either 4.5 Bcf/d of gas under the Alberta option or 3 Bcf/d under the Valdez option.

Components of both options include a gas treatment plant (GTP) and Point Thomson natural gas transmission pipeline. The GTP would be built next to the North Slope's Prudhoe Bay facilities to treat gas so it can be shipped on the pipeline. An approximately 58-mile (93 kilometers) pipeline would connect gas supplies of the Point Thomson field to the plant and pipeline.

The projected tariff for the North Slope-Alberta option is $2.80-3.50/MMBtu for transport from GTP to the Alberta Hub. The projected tariff for the North Slope-Valdez option is $2.45-3.15/MMBtu for transport from GTP to Valdez.

Citing U.S. Department of Energy statistics, the pipeline backers said gas prices at the Alberta Hub for 2020-2030 are projected to range $6.25-7.65/MMBtu, and prices at Henry Hub for the same period are projected to range $6.75-8.15/MMBtu. Oil prices during the period -- which would be of concern to those pursuing export of LNG -- are projected to range $110-125/bbl.

Updated cost estimates for the project are in the range of $32-41 billion for the North Slope-to-Alberta option (up from a previous forecast of $26 billion), and $20-26 billion for the Valdez option. Details of the cost estimates are to be made available to prospective shippers in a confidential data room.

Both options would provide opportunities for Alaska communities to acquire gas from the pipeline from at least five off-take connections. This is significant because parts of Alaska, particularly the state's Southcentral region, are seen to be running short of gas available from Cook Inlet fields. Alaskans have been working to develop an in-state pipeline option to tap North Slope gas that would meet their needs sooner than the long-sought Lower 48 pipeline (see related story).

Since ExxonMobil signed on with TransCanada to develop the Lower 48 project (see NGI, June 15, 2009), the companies have sweetened the offer to shippers from what was originally proposed by TransCanada in its AGIA application. The project sponsors have cut the proposed return on equity from 14% to about 12% and have proposed to take 20% of the project's capital risk where TransCanada had originally proposed to take none.

During a conference call with reporters last Friday, Paul Pike, Alaska Pipeline Project senior project manager for ExxonMobil Development Co., said the enhancements benefit shippers by about $500 million per year over 25 years. "That shows you how responsive we're being to competition," he said.

During the briefing with reporters Pike and Tony Palmer, TransCanada vice president of Alaska development, emphasized that the pipeline project is progressing independent of negotiations between gas producers and the state of Alaska over taxes and drilling permits, particularly at Point Thomson (see NGI, Jan. 18b). Pike noted that federal regulations preclude him from discussing the pipeline project with employees of ExxonMobil's exploration and production business.

While BP and ConocoPhillips are proceeding with their Denali project, each company has been offered an equity stake in the TransCanada-ExxonMobil project, Palmer said. Others would be offered equity stakes as well, he said.

The filing of open season materials marks a big step forward for an Alaska gasline. Recently Canada's Mackenzie Gas Project marked its own step forward with the completion of a review panel's document (see NGI, Jan. 4). While some have viewed the Mackenzie project and an Alaska gasline to be mutually exclusive, at least in the near term, Palmer said that is not the case. "We don't think that one precludes the other or there is any interrelationship in that fashion," he said.

The open season plan, which has been expected since last summer (see NGI, Aug. 3, 2009) is posted and can be reviewed on the Federal Energy Regulatory Commission and (FERC) Alaska Pipeline Project websites, and members of the public can provide comment through February. If FERC approves the plan, the Alaska Pipeline Project will finalize its open season offering and provide it to potential shippers at the end of April for their assessment during the 90-day period through July 2010.

The open season process initiated with FERC applies to the U.S. portion of the project. A separate but coordinated open season for the Canadian portion of the project is to be conducted concurrently with the U.S. open season. The results of the open seasons will determine the preferred development option.

Information about the project and open season is available at

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