JUNEAU — State legislators are continuing their review of the state’s proposed deal with North Slope producers and TransCanada Corp. on a major natural gas project.
Legislation that would allow state participation in the project is before the House Resources and Senate Resources committees, which held several days of hearings last week.
The proposal is for the state to become a partner in the project in ways that reduce risks for the industry participants but also enhance the state’s share of future revenues.
Black and Veatch, a consulting firm working for the state, estimates potential profits to the state of $3 billion a year by 2024 from its share of the project.
The agreement also provides terms under which the pipeline can be expanded if other companies, which do not own a share of the pipeline, find new gas supplies.
Legislators are examining two documents, the Heads of Agreement with all the parties including the state and TransCanada, and a separate Memorandum of Understanding between the state and TransCanada that spells out terms of the partnership between those entities.
Under the proposal, TransCanada would make the investment in, and own, a share of the North Slope gas treatment plant and pipeline sufficient to transport the state’s gas share, while the state would invest directly in, and own, a share of the LNG plant in Nikiski sufficient to convert the state gas into LNG for sale. The state would have an option to purchase part or all of TransCanada’s share of the project at certain points.
BP’s Dave Van Tuyl, representing his company in a “roundtable” discussion held with the Senate Resources Committee Feb. 7, said the Legislature is being asked to take a first step this year with decisions in three areas: whether to participate in the project, the rate of participation and setting the overall share between 20 percent or 25 percent, and agreeing to the next steps.
Tony Palmer, representing TransCanada on the panel, said that if the Legislature approves the enabling legislation this year he anticipates a “Precedent Agreement,” this summer between the state and his company. A Precedent Agreement is the first step in a long-term, binding transportation agreement for the state’s gas share to be shipped by TransCanada through its share of the pipeline.
The Precedent Agreement would be followed by a Firm Transportation Service Agreement (the shipping contact itself) that would be ready for legislative approval in 2015, Palmer said.
This is the big step for the state because it is binding, but Palmer also said there are “off-ramps” for parties including the state, at different stages in the process, even at advanced points. These are covered in sections of the state-TransCanada MOU that cover “termination of participation,” and includes provisions for repayment to TransCanada of its costs with 7.1 percent interest, Palmer said.
The state’s negotiation of the Heads of Agreement was pursued after the results of a consulting study were received from Black & Veatch.
The firm outlined some major findings of the study for the Senate Resources Committee Feb. 10. In the study, Black & Veatch had focused on two main objectives in the study, one to find a way for the state to protect its royalty interest and a second to find a way that the state, as a landowner, could provide incentives for the project to move forward.
“The bottom line is that we feel the project is feasible with some changes to the fiscal framework,” said Deep Poduval, who led the study team.
Black and Veatch found this could be achieved most effectively by the state taking on some of the costs of the project by becoming a partner and by modifying the present terms of the oil and gas leases that give the state the ability to switch between taking of royalty from royalty in-kind to in-value at six months’ notice.
The “Heads of Agreement” as it now stands, with the producing companies and TransCanada, provides for the state to take both its royalty and tax share in kind to achieve a 20 percent to 25 percent overall share of the gas production and to take a corresponding share of the project itself, but partnering with TransCanada Corp. on the gas treatment plant and the pipeline.
Poduval said the state’s other options to alter the fiscal framework include simply lowering the state’s royalty and tax, but that the taking of gas in-kind and equity partnership approach seemed better because the state would benefit far more in the long run. The industry’s objective is also for the state to benefit from the project so that the interests are aligned.
“It’s a better way to achieve the objective,” she said.
Another state objective achieved under the equity arrangement is the ability to assure third-party access to the “midstream” of the pipeline, for explorers who discover other gas.
Last week, legislators heard from the state’s potential new partners in a wide-ranging discussion in the Senate Resources Committee held Feb. 5.
Sen. Hollis French, D-Anchorage, asked about concessions the five parties had made to each other in reaching the Heads of Agreement. One difficult area, several on the panel said, was to agree on principles for expansion of the pipeline and how costs for expansion would be shared.
Palmer, of TransCanada, said the final agreement does have a “pro-expansion” bias, though not as far as TransCanada would have preferred. Bill McMahon Jr., representing ExxonMobil, said a difficult area was in determining what would be agreed on in the initial HOA document and how much would be left to negotiate later.
Pat Flood, of ConocoPhillips, said the companies had to come to grips with dealing with the state on a commercial basis and yet keeping the state’s role as a regulator in mind.
“This was new territory for us,” in a commercial agreement, he said.
Palmer said some terms relating to pipeline return on equity in the HOA are more beneficial to the state than was the case under the state’s AGIA license agreement with TransCanada. He didn’t elaborate on the point, however.
Pipeline return on equity, which is regulated by the Federal Energy Regulatory Commission, is important because it affects the pipeline tariff, or shipping cost, which in turn affects the revenues to gas shippers including the state.
Sen. Fred Dyson, R-Eagle River, raised a question that was not fully answered: If there can be no legal limit to the state’s tax authority, what if the state later decided to increase its gas production tax?
Because the state would be taking its tax in-kind, would this increase the share of the state’s gas and therefore the state’s volume of gas to be shipped? ExxonMobil’s McMahon said, “That would be the result.”
ConocoPhillips’ Pat Flood said, “The HOA as it is (agreed on) contemplates the state’s participation to be the same as its share of gas.”
Dyson did not pursue the question further, but a state official familiar with the agreement said this is one of several important loose ends that have to be nailed down as the deal moves through future stages.
If the state can increase its gas tax and its gas volume at the whim of the Legislature it would have practical effects on the project, because pipeline capacity is designed to handle a set volume of gas. It could also detract from the gas shares of the other shippers.
Members of the panel also said that the agreement makes no change in the current state property tax or corporate income tax. However, the agreement also provides for a PILT, or payment-in-lieu-of-tax, on property taxes to local governments, while the project is in construction.
In its overall analysis of the project Black and Veatch used a cost basis for the project of $39 billion to $54 billion, but that this differs from the estimates published by the industry team of $45 billion to $65 billion.
That’s because the companies included Point Thomson production facilities and pipeline, while Black and Veatch looked only at the North Slope Gas Treatment Plant, the pipeline and the large Southcentral liquefied natural gas plant, said Peter Abt, another member of the Black & Veatch team.
Based on those estimates, the study team calculated a “break-even” price for delivery of gas to customers, as LNG, of about $12.30 per million British Thermal Units, Abt told the Senate committee.
Abt warned the committee, however, that cost escalation represents a key risk for the project. Costs have escalated sharply for major energy projects worldwide, particularly LNG.
“We expect costs under continued pressure as this goes forward,” Abt said.
However, the consultants also concluded that the efficiency gain of having the LNG plant located in a northern climate, on the Kenai Peninsula, was worth the equivalent of an extra 3 million tons of LNG per year in value gain, compared against competing LNG projects with their liquefaction plants located in warmer climates.
The consulting firm identified an LNG supply “gap” in world markets, mostly Asia, of 250 million tons to 300 million tons of LNG per year by 2025, but that Alaska also faces significant competition from other projects that have lower costs. Compared against those, Alaska now appears “out of the money,” in being able to compete without changes in fiscal structure and state participation.