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Two pipelines move planning forward Denali, TransCanada update Alaska Oil & Gas Congress: TransCanada seeks alignment; Denali to complete cost estimate this year Kristen Nelson Petroleum News
The 5th Annual Alaska Oil & Gas Congress heard updates in mid-September from the two groups proposing to build a natural gas pipeline from Alaska’s North Slope to market: the state-licensed Alaska Gasline Inducement Act project being developed by TransCanada and ExxonMobil, the Alaska Pipeline Project, and Denali – The Alaska Gas Pipeline, the joint venture being developed by BP and ConocoPhillips.
Tony Palmer, TransCanada vice president Alaska Development, told Petroleum News that “the two companies seek alignment with other partners. … We want that; we think that’s the right way to do the project and we’ll continue to do that.”
The Denali project update was presented by Kris Fuhr, vice president, mainline project manager, who said a successful project means jobs and business opportunities; access to new gas supplies; new exploration and development of both oil and gas; extended economic life for North Slope resources; major new revenue streams for Alaska and Canada; and a secure domestic natural gas supply for North America.
Details emerge Palmer said TransCanada and ExxonMobil are now working on two alternatives for the gas treatment plant on the North Slope. That’s because the Alaska Pipeline Project will ship gas either to Canada for sale in the Lower 48, or to Valdez for liquefaction and shipment as liquefied natural gas.
Palmer said the LNG option requires a lower amount of CO2 coming out of the gas treatment plant than does the option for gas going to Canada.
For the LNG option “you have to remove more CO2; you have to engineer it slightly differently,” he said.
So the Alaska Pipeline Project is providing engineering to meet the LNG specs or the specs for the project going to Alberta.
Palmer said the gas treatment plant for the 3 billion cubic feet a day to Valdez for LNG would be smaller than the plant for the 4.5 bcf a day project to Alberta.
The TransCanada-ExxonMobil proposal also includes a line to Point Thomson which is outside of AGIA.
Asked if the Denali plan includes a line to Point Thomson, Fuhr told Petroleum News in an e-mail: “If there is interest from customers to build a line to Point Thomson, we will consider including it in our service offer.”
Cost estimates Fuhr said Denali expects “to complete our cost estimate work around the end of this year, and we will be initiating our open season before the end of 2010.”
Palmer said the TransCanada-ExxonMobil team will have its preliminary cost estimate done at the end of the first quarter of 2010 and expects to complete its open season at the end of July 2010.
TransCanada contracted with Northern Economics, with the University of Alaska’s Institute of Social and Economic Research at the University of Alaska Anchorage as subcontractor, for the required in-state gas demand study.
“That work is well under way, a comprehensive analysis,” Palmer said. The work will be complete this fall and it will be made public, he said.
Withdrawn partners TransCanada has had questions over the years about the withdrawn partners issue — companies that invested in and then withdrew from an earlier effort to build a North Slope to market gas pipeline, the Alaskan Northwest Natural Gas Transportation Co., and were promised compensation for their investment, with interest, if that project was ever built. Most of the partners withdrew; TransCanada owns the two remaining partners.
Early this year FERC accepted surrender of the conditional certificate ANNGTC received in 1977 for an Alaska gas pipeline project.
Although TransCanada did not believe the concerns were valid, Palmer said, the company “went out and sought mutual releases from all the withdrawn partners and we now have them all, 100 percent, and we got them all at no cost to TransCanada.”
By last spring TransCanada had all but one of the releases and over the summer it got the last release, he said.
Gas treatment plant Fuhr said in his presentation that the gas treatment plant for the North Slope would be the largest gas treatment plant of its kind in the world. It will include the largest sealift modules in the history of North Slope development, more than 8,000 tons.
“We are still working on the total number of modules that will be required. However, we estimate that we will have about six modules which will weigh in excess of 8,000 tons,” Fuhr told Petroleum News in an e-mail. “In the history of North Slope sealifts, the largest modules have been around 5,000 tons,” he said.
In his presentation Fuhr called the gas treatment plant a megaproject in its own right and a schematic of the plant showed a temporary construction camp for 1,600 workers.
Fuhr said in his presentation that initial screening suggests U.S. fabrication cost is competitive for the sealift modules and said Alaska fabrication yards are expected to be fully utilized for pipeline and compressor station construction.
“Within road limitations, our intention is to modularize as much of the compressor station construction as possible. Nominally, the modules will be in the 100-ton range,” he told Petroleum News.
In addition to the GTP construction camp, there will be a number of camps required for the pipeline and compressor station work, Fuhr told Petroleum News.
“Our current estimate is that in any given construction year, we will have five to eight 250-bed camps for the compressor stations and about seven 1,200-bed camps for mainline construction.
“We will look for options to combine camps as schedule and execution allows,” he said in an e-mail.
Open season Palmer detailed plans for the next year, including filing open season materials with the Federal Energy Regulatory Commission at the end of January, first of February. FERC has to approve those materials, he said, and there is a 60-day public comment period. After that FERC has 30 days to act.
Based on that schedule, Palmer told Petroleum News, the open season would begin around the first of May and run for 90 days, ending at the end of July.
“We could get no responses; we could get totally clean responses — unconditional bids. Those two are unlikely,” Palmer said.
“What we’re more likely to get is bids with conditions.”
Palmer said the bids will include “volume, by customer, by receipt and delivery point.” They will also include the term of service, when the customer wants to begin shipping and how long the customer wants to ship.
A conditional bid will contain a list of conditions and if all those conditions are met it becomes a binding contract. What typically happens on large projects is that pipeline companies work with potential shippers to resolve the issues on the list.
“Now sometimes you resolve them and sometimes you don’t; sometimes the customer says OK, I’ll remove that; sometimes the pipeline company says, I can meet that; sometimes the guy says I’m out of here,” Palmer said.
And this doesn’t happen in a day or two. TransCanada’s AGIA application specified that the company has 100 business days after the end of the open season for its announcement of results, he said.
TransCanada will try to resolve issues as quickly as it can, Palmer said, “because we want to resolve them. We want to know if we have had a success or a failure.”
He said he wants people to know that there likely will not be an announcement of open season results on the first of August.
And while the company works through issues potential customers put in their conditions, “the project will be continuing to FERC application,” he said, because that is the requirement in AGIA: That whatever the results of the initial open season, the company continues through the process and obtains a FERC certificate.
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