Schedule slipping on pre-FEED work, critical agreements

  • Gov. Bill Walker smiles after signing legislation to buy out TransCanada’s interest in the Alaska LNG Project. With the state now a full 25 percent owner in the project, major agreements among the producers and with the state remain unresolved. Photo/Michael Penn/Juneau Empire

State officials say they are worried that the schedule for the big Alaska LNG Project could slip because of delays by North Slope producers in reaching key agreements.

However, the state itself is contributing to some of the delay, as well as part of the cost increase of the pre-front end engineering and design, or pre-FEED, sources familiar with the project say. 

Gov. Bill Walker had hoped to have the agreements earlier this fall in time for legislative approval in a special session of the Legislature held in late October, but that did not happen.

The governor did present a proposal that the state buy out the interests of TransCanada Corp. in the project, which lawmakers approved.

Several big issues remain, however.

“We’re not making progress on the commercial agreements needed and this could be costly to the project timeline,” Alaska Natural Resources Deputy Commissioner Marty Rutherford said in a recent briefing to legislators.

The Alaska LNG Project involves an 800-mile, 42-inch pipeline from the North Slope to a large gas liquefaction plant in southern Alaska, along with a large gas treatment plant on the North Slope that would mainly remove carbon dioxide from the produced gas.

AGDC is the state corporation that represents Alaska’s 25 percent interest in Alaska LNG Project.

The project has been given federal approvals to export up to 20 million tons of LNG yearly. Construction costs are estimated between $45 billion and $65 billion.

Frequent changes in the state’s gas negotiating team by Walker have created uncertainty for the industry negotiating partners, the sources said, who asked not to be identified.

The governor has made three changes of his lead negotiator since earlier this year. Rutherford, at DNR, was the lead of the gas team until late spring, when Walker requested that Audie Setters, an experienced, retired Chevron LNG official, take over the role.

Setters had been working as a consultant for the state. He was replaced in the summer by Rigdon Boykin, a retired California attorney who now lives in South Carolina, and who had worked with the governor in prior years on the Alaska Gasline Port Authority, a group Walker headed.

Boykin was sent home to South Carolina by Walker the week of Nov. 9.

Boykin’s departure was not announced and no replacement was named but sources told the Journal that key decisions on the negotiations are now being made by three officials: Attorney General Craig Richards, Revenue Commissioner Randy Hoffbeck and Rutherford.

Timeline slipping

The schedule is slipping in other ways. It looks now that preliminary engineering now underway will not be complete until mid-2016, instead of late 2015 or early 2016 as was hoped earlier.

Part of that delay is due to Walker, too. Late in the summer the governor requested the Alaska LNG Project team to reevaluate the use of 48-inch diameter pipe rather than 42-inch pipe.

Industry partners had earlier concluded that 42-inch pipe was optimal for shipping the known gas reserves, and that the pipe could be manufactured by several suppliers including steel mills in North America.

Walker argued, however, that there will eventually be much more gas found on the North Slope and that building in extra capacity, with bigger pipe, will be more efficient in the long run than handling expansions by building more compressor stations.

Industry partners in Alaska LNG agreed, some reluctantly, to the reassessment of the bigger pipe, which is adding $30 million to the pre-FEED cost and delaying its results.

The analysis of 48-inch pipe against 42-inch pipe is to be finished by March with the final evaluation to be done by May, according to sources.

The decision on the pipe size must be made before the decision to move to front-end engineering and design, or FEED, which is currently estimated to cost the project partners a combined $2 billion, of which the state would be responsible for a quarter, equivalent to its ownership stake.

All that means the FEED decision could be delayed to late 2016, Rutherford told legislators in the briefing.

However, industry partners in the gas project may also wait to see the outcome of the November 2016 state general election. That’s when voters will decide whether to approve a necessary constitutional amendment to allow the state to enter long-term fiscal agreements with the producers for the gas project.

Dan Fauske, CEO of the Alaska Gasline Development Corp., or AGDC, told its board in a briefing Nov. 12 that while the hoped-for schedule is slipping it is still within an overall timeline laid out by the partners, which calls for beginning of FEED no later than July 2017.

This could still allow a final investment decision in 2019 and project completion in 2025, which is the current plan.

Rutherford said the most critical agreements the governor wants by early December are a gas balancing agreement among North Slope producers BP, ConocoPhillips and ExxonMobil, who are partners with the state in the project, and a separate agreement to cover contingencies over a partner withdrawing from the project, she said.

Withdrawal, gas-balancing agreements

The partner withdrawal agreement has been requested by Walker, who is concerned that if a partner pulls out of the project it could stymie others in proceeding.

Rutherford said the governor is pushing the producers to have the gas balancing and withdrawal agreements by Dec. 4, the date on which the project members are to vote to approve the 2016 budgets for completing the preliminary engineering.

“Meeting this goal will be a significant challenge,” Rutherford said.

AGDC Operations Vice President Joe Dubler said the balancing agreement is proving to be complex because gas for the project will come from two North Slope fields, Prudhoe Bay and Point Thomson, and there are differing percentages of ownership by the producers.

“They’ll get there, but it is taking time,” Dubler said in the Nov. 12 briefing to AGDC’s board.

Agreements for withdrawn partners are normal in big projects but Walker wants an added provision that guarantees that the withdrawing party will commit gas to the project, meaning that it would agree to sell to a buyer.

That is proving to be very difficult in the negotiations because it essentially involves an agreement to sell gas to an unknown buyer for an unknown price.

One option is that the state itself could buy the gas now owned by a withdrawing partner, but that could entail huge financial risks for the state, advisors to the Legislature have warned lawmakers.

Dubler told AGDC’s board Nov. 12 that the partners are working hard on an agreement and hope to have it by the governor’s Dec. 4 deadline.

Fauske said the Alaska LNG Project partners could vote on the 2016 pre-FEED budget without the withdrawn parties and gas balancing agreements but that the governor prefers to have them done. The state itself will vote on the budget, as a partner.

Deadline for amendment looms

Meanwhile, Rutherford said a hard deadline the project faces is June 24, 2016. That is the day a proposed constitutional amendment on fiscal terms must be sent to the Division of Elections to appear on the November general election ballot.

By that that time Legislature must also have ratified the agreement between the state and North Slope gas producers that will fix state tax and royalty terms for a period of years, presumably the length of long-term contracts to sell Alaska LNG.

To be legal, the fiscal agreement will require an amendment to the state constitution. The constitution currently forbids the Legislature approving a guarantee that state taxes won’t change.

North Slope gas producers say the fiscal term deal is a “must-have” because of Alaska’s past record of frequently changing state taxes on oil production.

However, fiscal terms deal is proving to be another big sticking point in current negotiations, the governor has said in recent briefings. At least one Slope producer is pushing to have it cover taxes on crude oil as well as gas, Walker said. The state is pushing back on that.

Assuming the fiscal terms deal agreement is eventually concluded it will have to be ratified by the Legislature next spring, most likely in an April or May special session following the end of state lawmakers’ regular 2016 session.

A constitutional amendment requires a two-thirds vote of both the state House and Senate and that must be done by June 20. 

“If we don’t meet that the entire project schedule begins to slip,” Rutherford said, because the next general election for ratification of the amendment is November 2018, which would effectively delay the project two years.

ASAP update

In other developments, managers of AGDC told its board that work is continuing to complete a supplemental environmental impact statement, or SEIS, on the state’s backup pipeline plan, the 36-inch Alaska Stand Alone Project, or ASAP.

This is important because while ASAP itself is on hold (it is a backup in case the larger Alaska LNG Project doesn’t go) the work being done for the SEIS and the U.S. Army Corps of Engineers Section 404 wetlands permit is transferable to the larger project.

Dave Cruz, an AGDC board member who heads the board’s technical committee, said there are no indications of any delay in the Corps of Engineers issuing the final supplemental EIS, its Record of Decision, as well as the Section 404 permit and other permits by fall 2016, most likely October.

A right-of-way across 100 miles of federal lands would also be issued by the U.S. Bureau of Land Management as a part of the other federal documents.

“Those permits are transferable to Alaska LNG even though there is a six-inch difference between the 36-inch pipe (of ASAP) and the 42-inch pipe (of Alaska LNG),” Cruz told the board.

What’s important is that the physical footprint of the two pipeline projects, including the space needed for construction equipment, are similar, which should be the case for 36-inch or 42-inch pipe, he said.

“There’s still some debate on this but it shouldn’t be a problem,” for the regulatory agencies, Cruz said.

However, 48-inch pipe may be a different matter, he acknowledged. If 48-inch pipe is decided on and the Federal Energy Regulatory Commission, which is lead agency on the federal EIS for Alaska LNG, decided that the larger pipe represents a “substantial” change, at least some of the work on the 36-inch SEIS won’t be usable.

A critical factor, however, is that the routes of the two projects, ASAP and Alaska LNG, have been exactly aligned from Prudhoe Bay to a location in the Matanuska-Susitna Borough where the bigger pipeline would veer off toward a Cook Inlet crossing to the Kenai Peninsula. 

ASAP would end in the Mat-Su Borough where it would connect with existing regional pipelines.

Meanwhile, AGDC is finishing up other parts of the ASAP project that will be useful to Alaska LNG. This includes a fine-tuning of information gathered to support final engineering on the ASAP project including a c“works package” of equipment needed for construction,

AGDC Engineering Vice President Frank Richards told the board that information is available from a Request for Information the state corporation had sent out to vendors for estimates equipment packages. Material sites for construction were also identified.

“They have been looking at equipment, parts, camps, pads–those early activities that will need to be done well in advance of construction. There will also be development of material sites and the opening of access roads,” AGDC spokesman Miles Baker said.

This information will be useful to the Alaska LNG project, he said. “There may be some differences in equipment due to the differences in pipe size, 36-inch instead of 42-inch, but the civil works side of the project will be roughly the same,” for both ASAP and the larger Alaska LNG Baker said.

Moving to 48-inch pipe would require heavier equipment and more updated information, however.

“We would have four mainline contractors (on different parts of the 800-mile route) using similar equipment and working simultaneously to build the pipeline, and we need to make sure they are serviced and supplied,” Baker said.

Tim Bradner can be reached at [email protected].

11/18/2015 - 3:45pm