A new cost estimate for the Alaska LNG Project puts the required capital investment at about $45 billion, which is in the lower range of a previous estimate of $45 billion to $65 billion, an ExxonMobil Corp. manager heading preliminary engineering for the project told an Alaska legislative committee Aug. 24.
“We’ve made a lot of progress in driving down costs,” but it isn’t enough to make the project economic at current energy prices, Steve Butt, the project manager, told members of the House and Senate Resources committees in Anchorage.
Preliminary engineering for the project is now 95 percent complete and will be finished in mid-September, but under its current ownership structure Alaska LNG will not proceed into more costly final engineering, which was scheduled for 2017, Butt said.
As currently configured, Alaska LNG involves an 800-mile, 42-inch high-pressure pipeline from northern to Southcentral Alaska, a large gas treatment plant on the North Slope that would mainly remove the 12.5 percent carbon dioxide in raw gas from the Prudhoe Bay field, and a large liquefied natural gas, or LNG, plant at the southern terminus of the pipeline at Nikiski, on the Kenai Peninsula south of Anchorage.
License issued
The U.S. Department of Energy has issued a license to the North Slope producers, currently the main owners of Alaska LNG, to export up to 20 million tons of LNG yearly.
Butt said the Alaska project has its advantages and disadvantages. “Its resource risk is low. We know the gas is there. There are structural advantages, mainly being close to the market (in Asia) but also structural disadvantages,” mainly the 800-mile pipeline needed from the North Slope to the LNG plant at Nikiski, in Southcentral Alaska.
“We’re not there yet (on the economics) but we know how to get there,” based on the work to date, Butt said. It would be one of the largest LNG projects in the world and also one of the most expensive.
The project partners, BP, ConocoPhillips and ExxonMobil, who are also major North Slope producers, are spending about $600 million on preliminary engineering with $150 million of this spent by the state of Alaska as a one-fourth partner.
In addition the three producers spent $106 million earlier on conceptual engineering, Butt said. Final engineering, or front end engineering and design, is expected to cost about $2 billion.
The existing partnership between the producers and the state allows one party to continue working on the project if others bow out, Butt said, and the companies have agreed to let the state-owned Alaska Gasline Development Corp., or AGDC, develop an alternative project structure that would allow the project to be more competitive.
Tax exempt status studied
Keith Meyer, president of the state gas corporation, said his group was studying possible advantages of tax-exempt status for which a state-owned project might qualify or a project owned by a third-party investor group that would ship gas and make liquefied natural gas under a “tolling” or contract arrangement with the Slope producers and the state for its royalty gas.
The producing companies are “cooperating” with the state, he said.
Meyer told the legislators that AGDC would aim for a decision to do final engineering in late 2018. That schedule, assuming a gradual improvement in energy markets, could still allow for a construction decision and project completion near the 2025 target now envisioned by Alaska LNG, Meyer said.
How the project would be commercially reconfigured is still to be determined. Meyer said he hopes the producing companies will stay with the project in some form. “They should be our best customers,” as shippers of gas. But if they opt not to be customers, for example by selling gas at the well-head (field), “we’ll work to bring in other customers,” or buyers of the gas, he said.
The current four-way partnership has the three major Slope producers and the state owning percentages of the project equal to each party’s ownership of gas; the state would take its royalty and tax share in kind, or as gas.
This arrangement, which currently exists only for the work through preliminary engineering, would result in an equitable sharing of risks, and rewards, of the huge project if the current arrangement were extended.
Not currently economic
But one partner - ConocoPhillips - has already said it will not stay with the project if it proceeds to FEED. ExxonMobil and BP have not stated their intentions but all parties agree the project is not currently economic and have agreed to let the state explore advantages like tax-exempt status it could bring to project under state ownership.
Those advantages could be substantial, a consultant to Wood Mackenzie, the international consulting firm, told the legislators. In a study commissioned by BP, ExxonMobil and the state’s AGDC, Wood Mackenzie found that as currently structured Alaska LNG is the least-competitive of major world LNG projects under development, even if energy prices recover to the equivalent of $70 per barrel (they are now about $45 per barrel).
But alternative ownership structures could reduce the project’s cost of supplying LNG to the point that the project might be able to compete even at current prices, David Barrowman, a Wood Mackenzie consultant who supervised the study, told the legislators.
As currently structured Alaska LNG would deliver LNG to Asia for about $12 per million British thermal units, assuming a project cost in the $45 billion range, according to the Wood Mackenzie study. If project costs escalate the cost would be more, approaching $15 per million Btu.
“Not only will the project not make sufficient returns for investors at current LNG prices but it may struggle to make returns even under a $70 per barrel oil price,” Barrowman said.
“However, there are certain levers that could be used to improve the competitiveness of the Alaska LNG Project and potentially improve the competitiveness compared with other jurisdictions,” with LNG projects, he said.
Third-party ownership
One option is a project owned by a third-party investor group, such as pipeline company and eventually equity investors or pension funds, Barrowman said. These groups might accept a lower return on investment, in the range of 8 percent, compared with a 12 percent return the producer/investors would likely require for the current ownership structure.
This could reduce the cost of LNG to a range of approximately $7 per million Btu, which might compete even at oil prices of $45 per barrel, he said. Another option, full state ownership and tax-exempt status, could reduce the cost of service to the $6 per million Btu range, he said. It is not known whether the U.S. Internal Revenue Service will approve a tax-exempt status for the project but exemption from state property and corporate income taxes would help.
Legislators cautious
Legislators were cautious in their appraisal of the new plan. Sen. Anna MacKinnon, R-Eagle River, who co-chairs the Senate Finance Committee, asked if the state administration would be seeking a change to Senate Bill 138, the enabling legislation passed in 2014 that authorizes the framework for Alaska LNG, including the partnership with industry.
“It is my understanding that no change in SB 138 is needed,” Meyer told the committee.
“That would be interesting,” MacKinnon said, indicating skepticism.
Meyer said SB 138, “contemplated a joint venture (between state and industry) but one that applied to the ‘pre-FEED’ (preliminary engineering, now underway). We’re now at a decision point” at the end of pre-FEED, in which a new arrangement may be needed, he said.
Hugh Short, a member of AGDC’s board who was with Meyer at the presentation, said, “It’s premature to say what legislative changes are needed. The board has not been able to spend enough time with this.”
Rep. Geran Tarr, D-Anchorage, expressed concern for the new plan. “It has always been stressed to me that there are big advantages to the (commercial) alignment under the current arrangement. This is a different mode, and it’s not clear what the alignment advantages would be,” she said.
The House and Senate committee hearings continued Aug. 25.
