|
$500M reduction for initial open season TransCanada, ExxonMobil say better terms for Alaska gas pipeline project include lower rate of return, slower recovery by pipeline Kristen Nelson Petroleum News
Alaska Pipeline Project partners TransCanada and ExxonMobil have filed their open season plan with the Federal Energy Regulatory Commission, making public an estimated cost range for building an Alaska natural gas pipeline as well as projected tariff rates for shipping on the project, which will go either to Alberta or to Valdez, depending on where customers wish to ship their gas.
As Tony Palmer, TransCanada’s vice president for Alaska development, has been at pains to relate, this is information which for any other gas pipeline proposal would be available only to potential shippers under confidentiality agreements.
Under FERC regulations for the Alaska gas line project, however, open season plans are available for public comment; Alaska Pipeline Project plans are on the FERC Web site and the pipeline’s Web site, www.thealaskapipelineproject.com.
Because TransCanada applied for a license under the Alaska Gasline Inducement Act, the company’s initial plans were also publicly available and analyzed by both the State of Alaska’s departments of Revenue and Natural Resources before a license was recommended and by the Alaska Legislature before the license was approved.
Competitors, Palmer says, have known what TransCanada was proposing since its AGIA application was made public and now know what the pipeline’s open season proposal is.
Sweetening the deal With a goal of getting commitments as early as possible, the State of Alaska included provisions in AGIA which would benefit producers committing to ship gas on the line in the initial open season.
TransCanada and ExxonMobil have sweetened the deal for shippers committing in an initial open season by an estimated $500 million a year, by reducing the pipeline’s rate of return from an estimated 14 percent in the AGIA application to 12 percent and by designing the tariff to recover only 80 percent of the capital cost of the line over the initial shipping term, which has been shortened from 25 years to 20 years.
Details became public Jan. 29 when the Alaska Pipeline Project filed its open season plan with FERC.
Palmer and Paul Pike, senior project manager for the project, an ExxonMobil Development Co. employee, reviewed the open season filing in a teleconference that day.
There is a 60-day FERC review period for the plan, including a 30-day public comment period.
Once FERC has approved the plan, the open season will be held May through July.
Palmer said a separate Canadian process for the Alberta option will be conducted at the first time.
He said following the open season negotiations are expected with potential shippers to resolve conditional issues, a process expected to be completed by the end of 2010 if resolution can be reached.
Cost estimates Pike said the cost estimates are $32 billion to $41 billion for the Alberta project and $20 billion to $26 billion for the Valdez option. The Alberta option takes gas to Canada where there are existing lines on which customers could move gas into the Lower 48. The Valdez option would ship gas for customers who wish to liquefy it and ship it to markets as liquefied natural gas; the Valdez costs do not include liquefaction facilities or ships, which would be the responsibility of the shippers.
Pike said the range of cost estimates is normal at this stage of the project, and reflects more than a quarter of a million hours of work since the AGIA license was signed in December 2008. While substantial work has been completed to date, the majority of the engineering work for the project lies ahead, Pike said.
The better commercial terms offered for the initial open season — pegged at a savings to shippers of $500 million a year — would save customers $12.5 billion over the course of a 25-year contract, Palmer said.
The first-gas date is set at 2020, which is later than TransCanada originally proposed, but Alaska’s commissioners of Revenue and Natural Resources said in a statement that the updates to the project cost and schedule “are in line with the analysis done by the AGIA technical team as part of the AGIA license review,” and validate the economic analysis the commissioners relied on in the AGIA findings.
First gas in 2020 Pike said that when TransCanada made its AGIA application it focused on the pipeline and made it clear that while it would build the gas treatment plant, it was looking for others with expertise in that area to build and own the plant.
ExxonMobil brought GTP expertise to the project, Pike said.
A line to Point Thomson was also added to the project, available if Point Thomson gas owners want to move their gas to market.
Palmer said that in addition to cost increases since TransCanada filed its AGIA application there have been changes in the world, including “an epic financial crisis” and shale gas development in the Lower 48. But based on the latest U.S. Department of Energy gas price forecast, there is still a margin of $3 to $4 per million Btu to be split between governments and shippers, he said.
Pike said the North Slope GTP was a factor in the 2020 first-gas timeframe; he said the 2020 date is a refinement of the estimate provided by TransCanada in its AGIA application based on further understanding of what it takes to develop and construct a project of this size.
Three sealifts Palmer told Petroleum News that the work TransCanada had done on the gas treatment plant for its AGIA application “was conceptual in nature rather than the details that we had developed on the pipeline,” and said TransCanada has learned a lot as a result of working as a team with ExxonMobil, including that the two sealifts TransCanada had in its application were too few because of the short weather window at Prudhoe Bay.
The addition of a third sealift is “a significant part of the reason for the shift in the in-service date,” Palmer said.
They looked at using more barges, or larger barges, but went with barges of a tonnage that has been used to get into Prudhoe Bay in the past. The tonnage of the barges affects the dredging needed at the docks, and with the sizes of the modules, “some of the largest modules in the world,” Palmer said they didn’t want “to have technological challenges” in addition to the magnitude and weight of the modules.
Throughout the project, “we’ve tried to use accepted and standard technology as opposed to cutting edge,” he said, because there are already sufficient challenges on the project without “trying to go with cutting-edge technology that hasn’t been used elsewhere.”
And it’s not just the sealift, Palmer said, but also the construction of the modules and the equipment needed for them.
The “time-critical factor is not the pipeline; it’s the gas treatment plant at the moment,” he said.
When Palmer presented the open season information to the Alaska Legislature’s Senate Resources Committee Feb. 1, he was asked why tariffs for in-state transportation of gas, about a third of the distance to Alberta, were not a third of cost of the Alberta tariff.
Palmer said that primarily it was because there was a “very large” GTP common to all customers and that number doesn’t change. He said that when you look at the pipeline the tariff is relatively related to mileage, but the GTP is approximately a third of the cost on the Alberta option in round numbers.
Conditional bids Palmer said it is typical in large pipeline projects that customers have conditions when they respond in an open season. It is difficult to predict what the conditions may be, but some of those may be outside the control of the pipeline company.
The desire of potential shippers to resolve fiscal issues with the State of Alaska, for example, would be outside the control of the Alaska Pipeline Project, he said.
The pipeline company will work with potential customers through the end of the year on conditions that the company can address, Palmer said.
Denali Denali, the competing BP-ConocoPhillips gas pipeline project, has said it will submit its open season plan to FERC in April, so that information will probably become available just after the FERC concludes its 60-day review of the TransCanada-ExxonMobil open season plan.
Bud Fackrell, president of Denali, said in e-mail comments that the TransCanada-ExxonMobil open season filing does not affect Denali’s plans.
“Everything we are doing is focused on Denali’s open season process, which will start in April of this year,” he said.
“We’ve been working hard on developing an updated cost estimate for the project, and have spent $130 million on that effort so far.
“I am confident that we will have an attractive commercial offer for our potential customers,” Fackrell said.
As to the success of a Denali open season, Fackrell said Denali is “concerned that shippers may hesitate to make the financial commitments needed to support the project due to issues outside of Denali’s control.”
He listed increased gas supply in the Lower 48, legal issues around the status of Point Thomson leases and “the lack of a long-term fiscal regime for North Slope gas production.”
Fackrell said potential shippers on Denali “have publicly indicated that resolution of these issues will be important in their decision to make the multibillion dollar commitments necessary to move the project forward.”
| 