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New gas partnership ConocoPhillips, BP form company to build Alaska natural gas pipeline Kristen Nelson Petroleum News
The prospect for an Alaska gas pipeline ratcheted up several notches April 8 with an announcement by ConocoPhillips and BP that the two were beginning work on a North Slope gas pipeline, a project they are calling Denali — The Alaska Gas Pipeline.
Jim Bowles, president of ConocoPhillips Alaska, and Doug Suttles, president of BP Exploration (Alaska) said at a joint press conference that the companies expect to spend $600 million through an open season in late 2010, early 2011.
In a joint statement issued earlier that day the companies said the project would move some 4 billion cubic feet of natural gas per day to markets and would “be the largest private sector construction project ever built in North America.”
An open season is planned to begin within 36 months. Following a successful open season the companies said they plan to obtain Federal Energy Regulatory Commission and National Energy Board certification and move forward with construction.
“The Alaska gas pipeline will be an historic project and we are pleased to be working with ConocoPhillips to move it forward,” Tony Hayward, BP Group Chief Executive, said in the prepared statement.
Jim Mulva, ConocoPhillips chairman and chief executive officer, said: “ConocoPhillips is pleased to be working with BP on this project; our companies have a long history of successfully developing projects on Alaska’s North Slope, in Canada, and around the world. The time is right to start moving this project forward.”
The companies said the project consists of a gas treatment plant on the North Slope and a large-diameter pipeline to Alberta.
If additional pipelines are required into the Lower 48, “BP and ConocoPhillips will seek other equity partners, including pipeline companies, who can add value to the project and help manage the risks involved,” the companies said.
Staff have been assigned to the project; project headquarters will be in Anchorage; and a new company will be formed to manage the project.
Gas in as little as 10 years “It’s an important event — probably the most significant event for BP since the discovery of oil at Prudhoe Bay in 1968 and the decision to develop our North Slope oil fields,” Suttles said at the Anchorage press conference.
“We will begin work immediately — gas could be flowing in as short as 10-years time,” he said.
Suttles said field work will begin this summer, along with “critical engineering cost estimating and permitting planning work,” with an open season beginning in late 2010 or early 2011.
The new company, Denali, will have 150 employees by the end of 2008, he said, and 500 employees and several thousand contractors within three years.
“For years North Slope gas has been utilized to increase recovery out of Prudhoe Bay,” Bowles said, resulting in recovery of billions of additional barrels because of gas reinjection. “But the time has come now, with the value of gas increasing and the need in the United States for that valuable commodity, for us to find a way to bring that gas to market.” The 4 billion cubic feet a day the line will carry “represents upwards of 6 to 8 percent of the entire U.S. demand,” Bowles said.
BP and ConocoPhillips have been major operators on the North Slope for more than 30 years, he said, and bring years of Arctic experience “as well as a vast amount of pipeline experience” to the project, and a collective market capitalization of more than $300 billion, “so we have the financial wherewithal to see this through,” he said.
What about fiscal certainty? Fiscal certainty from the State of Alaska will need to be addressed before an open season, the companies said, but is not a requirement for the project to move forward.
Late last year ConocoPhillips proposed a gas project to the state and asked for negotiations on fiscal issues up front.
Bowles said the companies are not asking for anything from the state now. “This project is moving forward on its own.”
The governor asked in February that “before any discussion on a fiscal framework takes place that both ourselves and the state better understand what the costs of this project might be,” he said. Bowles said that is what the companies are doing now, with the expectation that a fiscal discussion with the state will take place before open season.
Suttles said BP has been “encouraged by the number of people who have spoken out and recognized that there are fiscal issues to sort out.” That, he said, has given BP “the confidence that we can now actually move it forward and that people will work with us to solve the issues to get this gas moving.”
Bowles said that fiscal certainty is something pipeline owners expect to be necessary to “give future shippers confidence to make that 20- or 25-year shipping commitment.”
The pipeline needs “to put together a project which will attract customers,” Suttles said, “because without customers there won’t be a line and there won’t be the ability to build a line.” That will require the most efficient project.
“I think our customers are going to be looking for a number of things to make sure that they’re going to get an adequate return and I expect the fiscal issues to be part of that,” Suttles said.
“We’re pretty confident — or we wouldn’t be doing this — that over the next three years, between now and an open season, people will work that issue. If we didn’t actually believe that, we wouldn’t be doing this,” he said.
The shipping commitment will probably be in excess of $100 billion, Bowles said, and “any group of companies before making that type of commitment would want to understand that they’ve got a very predictable fiscal framework in front of them.”
Bowles said “predictability of future fiscal issues” is probably the key thing, and noted that the governor’s original proposal of 10 years of fiscal certainty when the Alaska Gasline Inducement Act was introduced was probably a good start.
Why now? Bowles and Suttles said the companies have talked off and on about a gas pipeline project through the years, but the joint venture proposal came together over the last two months.
Bowles said it was in the last two months that the companies put together the idea for the new company Denali — The Alaska Gas Pipeline.
“Both of our companies, I think, since day one on the North Slope, have tried to figure out how to maximize the value of this gas,” Suttles said.
The gas has been used to produce more oil, but over that time the companies have tried to figure out what happens next, he said.
A lot of things have changed over the last few years, Suttles said, including the price of energy and energy security, “and so for the last several years we’ve been working very hard trying to figure out how to unlock this.” Sometimes those discussions didn’t go anywhere, he said, “sometimes they have, and over the last couple of months I think we both came to the realization we have to find a way to unlock this thing. We can’t continue to wait. This is such an important project for Alaska, for America and for us.”
For BP, Suttles said, North Slope natural gas is the company’s “single biggest undeveloped gas resource in the world.”
Over the last five or six years BP’s “outlook on energy and the outlook on energy prices” have “changed dramatically,” he said. The company wouldn’t be making the commitment and spending the money if it didn’t believe it could deliver an economic project, Suttles said. “But fundamentally the big thing I think for BP that’s changed over the last five or six years has been the outlook on energy and energy prices.”
Where’s ExxonMobil? BP and ConocoPhillips are major North Slope natural gas owners — but so is ExxonMobil, a major Prudhoe Bay working interest owner as well as the unit operator at the contested Point Thomson unit.
ExxonMobil is not part of the Denali partnership.
Bowles said ConocoPhillips and BP “do see other players potentially coming into this as we move forward. And Exxon is certainly a company that we would like to see in the project if that’s something they would like to join. It’s obviously nice to have a matchup between the big resource owners and the pipe ownership.”
Suttles said there had been discussions with Exxon, and “a partnership document” between BP and ConocoPhillips was shared with ExxonMobil. “They’re aware of what we want them to do and it’s out there and I would anticipate we will have future discussions with them.”
Margaret Ross, a spokeswoman with Exxon Mobil Corp. public affairs, said in an e-mail that the company was invited to participate.
“However, ExxonMobil was only made aware of the ConocoPhillips-BP plan a few days prior to the announcement,” she said. “We need to better understand their approach to ensure that it will lead to a commercially viable development on a cost and schedule basis that will deliver maximum benefits to the State of Alaska, the producers and consumers in the United States and Canada.”
She said the company “remains committed to commercializing North Slope gas resources,” and is continuing “to evaluate all options for pursuing an Alaska gas pipeline including the State of Alaska’s consideration of a project under the AGIA process.”
Commercializing North Slope gas “has the potential to increase ExxonMobil worldwide gas production by 10 percent and add over 1 billion oil equivalent barrels of proved reserves nearly enough to replace a full year of our worldwide production.”
“Given the significant value to our company, we are keen to be part of a project that commercializes the gas,” Ross said.
She also noted that the project — moving North Slope gas to markets in Canada and the Lower 48—“will be among the largest, costliest and most complex projects ever undertaken. Ensuring that a quality project planning and execution approach is in place from the outset is critical to protect the interests of the State of Alaska, the producers, and consumers in the United States and Canada,” Ross said.
What about Point Thomson? With a 4-bcf a day line, “we believe that Point Thomson gas is going to be critical to the success of that line. And what’s important is that there be a clear owner of that gas at open season,” Suttles said.
The State of Alaska and the Point Thomson Unit working interest owners are in litigation over the state’s termination of the unit last year; unit operator ExxonMobil proposed a new plan of development earlier this year and a determination by the Department of Natural Resources on whether to terminate the unit is in process after a March hearing.
Suttles said Point Thomson gas will be necessary both to fill the line and “manage the recovery of oil as well from the oil fields where the gas exists.”
Prudhoe Bay natural gas is being reinjected to produce more oil.
A natural gas takeoff rate for Prudhoe Bay was set when the field went into production.
That rate, 2.7 bcf a day, includes gas used for fuel.
The Alaska Oil and Gas Conservation Commission, which regulates gas offtake rates, held Prudhoe Bay gas offtake hearings “and concluded that the current offtake allowable of 2.7 bcf per day is appropriate until such time as the operator applies to us with adequate technical justification for an increased allowable,” AOGCC Commissioner Cathy Foerster told Petroleum News in an April 9 e-mail. Forester said “the ball is in BP’s court,” to file a request for a higher Prudhoe Bay offtake rate. BP is the Prudhoe Bay operator.
The commission’s “study work is still fairly fresh. I think we can still rely heavily on that but, as always, the burden will be on BP to demonstrate why a higher allowable is justified.” Foerster also said that “a substantial amount of the technical justification will likely be introduced into the public record.”
“Unless they’ve done something vastly different that requires a new, hard look from us, then the hearing process should be about normal,” she said.
The commission began looking at Prudhoe offtake rates in 2005 and wrapped up its study last year.
The TransCanada conundrum TransCanada, a major pipeline company, has been working on advancing a North Slope gas pipeline for as long as the North Slope producers — it and companies that are now its subsidiaries were involved in competing plans to commercialize North Slope natural gas in the late 1970s and early 1980s.
TransCanada has continued to work on an Alaska Highway gas pipeline project since.
It holds permits for the Canadian section of the pipeline, and maintains that those permits give it the right to be the first pipeline to move Alaska North Slope natural gas through Canada.
The company is also the surviving bidder under the Alaska Gasline Inducement Act to receive incentives from the State of Alaska to build a North Slope to market natural gas pipeline. A decision from the commissioners of Natural Resources and Revenue on whether to recommend awarding the AGIA license to TransCanada is expected May 19; the Alaska Legislature would then have to approve that license.
“TransCanada has sought for several years and continues to seek alignment” with the North Slope gas producers and the State of Alaska, TransCanada spokeswoman Shela Shapiro told Petroleum News in an April 9 e-mail. TransCanada is “encouraged that two of the three producers are ready to advance the project and get Alaskan gas to markets in the Lower 48 states. We see this as positive news for consumers across North America as well as Alaskans,” she said.
“TransCanada believes that it is the best independent pipeline company for the project,” she said.
On issues related to permits the company holds in Canada, Shapiro said: “We hold valid NPA (Canada’s Northern Pipeline Act) permits for the Canadian section of the project which means that TransCanada has the rights to be the first pipeline project to move gas through Canada.”
Project looks to NEB process “Are there going to be people who will challenge what we’re going to do?” Suttles asked. “Yes. There will be many challenges on this project as we go forward,” and the TransCanada permits could be one of those challenges.
“That’s part of doing something like this,” he said.
He said with both energy costs and energy security at play, he hopes “people will have a will to get this project done, both in Canada and in the United States.”
“With regard to any permits that TransCanada may hold in Canada,” Bowles said, “Canada does have a federal process to pursue for any new pipelines. Just as the United States has the FERC process, Canada has the NEB or the National Energy Board process. That’s the process that we would pursue through Canada and it’s a viable process that we think applies.”
The NEB process is different than the Northern Pipeline Act under which the Alaska Highway pipeline permits were issued.
Suttles said Denali is a new project and the companies are “not relying on elements from previous projects to make this work.”
As for possible competition between a BP-ConocoPhillips project and a TransCanada project, Suttles said there are many examples in the U.S. “of competition going into open season and we’re happy to do that.”
Suttles said Denali is separate from the AGIA process.
“We’re open to the idea of pipeline companies or other third parties joining this project,” he said. “What we look for, of course, is what value they bring to the project.”
Bowles said while the partners are “leaving the door open to how this partnership could change over time,” they “want to get this project moving ahead, not lose a summer’s worth of field work or another year of making this pipeline a reality.”
Work this summer Field work will begin this summer, the companies said.
The new company will be registered soon, Suttles said, and within two months will open an office in Anchorage.
“We have already let some contracts out as far as some of the field work,” Bowles said.
So work is starting, he said, and the companies anticipate spending $100 million over the next 12 months.
“This is not an announcement to build a plan,” Suttles said: “This is an announcement to start the project.”
While the project will be built by the Denali joint venture, the companies have split up whose company’s processes will be used. “BP will take the lead role at least initially at the gas treatment plant on the North Slope,” Bowles said, and ConocoPhillips will take the initial lead for the pipeline from the North Slope to Alberta. BP would take the lead on a pipeline from Alberta to the Lower 48.
Suttles had noted in opening remarks that a pipeline into the Lower 48 would only be constructed “if required.”
With Canadian natural gas production in decline, it is generally expected that by the time a gas pipeline from Alaska reaches Alberta there will be capacity available on existing pipelines to move the gas into Lower 48 markets.
The companies listed near-term Alaska programs in a slide packet, saying they will make available $30 million to fund: job training programs; in-state gas feasibility; and infrastructure upgrade studies of roads, bridges, ports, etc.
Bowles said the $30 million would be used to study in-state offtake points and in-state gas needs, “so with that effort right there we’ll be in a much better position as far as how the state needs can best be served with those takeoff points.”
$600 million to start
The companies cited a figure of $600 million to get to open season, $100 million of which is expected to be spent in the next 12 months.
Board sanction would be required for commitment of gas to an open season, Bowles said, and for monies for a final design, another billion dollars or more.
Suttles said actual construction wouldn’t be sanctioned until after the project has FERC and NEB certificates, probably five years into the project.
“But between now and then we’re going to spend several billion dollars and they’ll obviously want to approve that spending as we get to each of those steps,” he said.
The total cost isn’t known, but the last cost estimate the companies did for a project to the Midwest was $20 billion in 2001.
“Since 2001 steel prices have doubled; collectively between both of our companies we now see that price in excess of $30 billion, but we need to do the work necessary to really see what the price will be,” Bowles said.
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