Senate Bill 138, Gov. Sean Parnell’s enabling legislation for state equity participation in a North Slope liquefied natural gas project, is in House Resources, its first stop of three committee assignments in the House.
Resources co-Chair Eric Feige, R-Chickaloon, said in a press availability March 20 that the committee would be meeting almost every day, with the goal of moving the bill April 4. The bill then goes to House Labor and Commerce before it reaches the Finance Committee.
Resources co-Chair Dan Saddler, R-Eagle River, said they’d been studying the bill prior to receiving it from the Senate. House Resources held hearings on the memorandum of understanding and heads of agreement while SB 138 was in the Senate.
The bill passed the Senate March 18; House Resources held its first hearing on the bill March 19, and beginning the week of March 24 has met every day, taking testimony from the administration, Legislative Budget & Audit consultants and the administration’s consultants.
TransCanada a big concernA big concern aired in House Resources was the value to the state of partnering with TransCanada, rather than going it alone to finance and manage its approximately 25 percent share of the proposed Alaska LNG Project.
The MOU and HOA presented by the governor in January, and enabled by SB 138, propose that the state would take its royalty and production tax in kind rather than in value, giving the state a 20-25 percent ownership in natural gas from the Prudhoe Bay and Point Thomson fields, the variation based on the production tax imposed on natural gas. The state would then take a comparable equity share in the project, which includes a gas treatment plant on the North Slope, a gas pipeline from the North Slope to Nikiski and a liquefied natural gas plant at Nikiski.
TransCanada has been involved with the state through AGIA — the Alaska Gasline Inducement Act — and a license which TransCanada took under that legislation for a pipeline into Canada to deliver Alaska North Slope natural gas to the contiguous United States. New natural gas development in the Lower 48 made that project uneconomic, and Parnell asked the North Slope producers and TransCanada to collectively consider an LNG project to take natural gas to Asian markets, while also providing natural gas for use within the state.
Parties representing the state — the departments of Natural Resources and Revenue and the Alaska Gasline Development Corp. — then negotiated with the North Slope producers — BP, ConocoPhillips and ExxonMobil — and TransCanada, producing the two agreements which would be ratified by SB 138, the heads of agreement or HOA and the memorandum of understanding or MOU.
Going it aloneThe MOU provides the basis for the state and TransCanada to exit the AGIA agreement, with TransCanada holding the state’s equity interest in the gas treatment plant, or GTP, and the pipeline; the Alaska Gasline Development Corp. would hold the state’s interest in the liquefaction facility.
The MOU provides that the state could buy back up to 40 percent of the GTP and pipeline interests from TransCanada, leaving TransCanada with minimum interests of 14 percent in those portions of the project. In committee discussions in both the House and Senate consultants have told legislators that the state will likely have opportunities to sell part of its interest in the LNG facility as it negotiates the sale of its gas, since LNG buyers frequently want to hold an equity position in the project.
If the state were to back out of the MOU it would be faced with exiting AGIA, and could face arbitration and possibly litigation over the issue of whether the project is uneconomic; it would also have to pay TransCanada for information that company has developed which would be contributed to the AKLNG Project if the MOU is signed.
If the state goes it alone it would have to fully fund its participation in the pre-FEED, pre-front-end engineering and design portion of the project, estimated at $104 million and $486 million for FEED, as well as fully funding its share of construction costs, some $12 billion (estimates by enalytica, the LB&A consultants) and at $108 million and $450 million, respectively for pre-FEED and FEED (estimates by the administration’s consultants, Black & Veatch) and an estimated $13.2 billion in construction costs.
If the project did not continue beyond pre-FEED, the state would owe TransCanada some $50-60 million for work done to that point, and if the project were abandoned after FEED, the state would owe TransCanada $150-400 million, with the variations — these are from enalytica estimates — based on whether the state allows TransCanada to carry all of its GTP and pipeline interest, or buys back 40 percent of that interest.
Both consultants have said that all numbers at this early stage of the project are certainly wrong, and are useful for showing direction.
Advantages of TransCanadaEstimates from enalytica show that state equity leads to higher government take on average, with the state taking a larger proportion than the producers combined, due to its dual role as equity participant and sovereign — the state would still collect corporate income taxes and property tax — and the fact that the state would not pay federal income tax. These estimates show the state taking up to 35 percent at high gas prices while the combined producer take would be less than 30 percent at the same gas price. That was for a 25 percent state equity share, and was higher than the state’s take at 20 percent. Compared to the state’s take in-value, i.e. without an equity stake, at high gas prices the state would take more — although it would take much less at low gas prices — but without state equity participation there might not be a project.
TransCanada’s share of the cash from the project ranges from 1-7 percent, based on enalytica modeling, varying dependent on price levels and the level of buyback which the state exercises. TransCanada’s cash share is lowest with buyback and at high gas prices.
Black & Veatch, the administration consultants, said the economic impact to the state of partnering with TransCanada include TransCanada investing 60-100 percent of the state’s upfront capital costs for the GTP and pipeline (the variable is buyback by the state of up to 40 percent).
Once the project is in operation, the state would pay TransCanada a negotiated tariff for 60-100 percent of the GTP and pipeline capacity used to move state gas, again dependent on whether the state exercises its buyback option.
Black & Veatch concluded that the economic impact to the state from TransCanada’s involvement would be a reduction of some $4 billion in total cash flows. But the firm said the net present value impact would be marginal because upfront money carries more weight than cash flow over 25 years of operation.
Black & Veatch said TransCanada could reduce the state’s investment in the project by $4-7 billion (depending on buyback), said the state might hit debt limits going it alone and also noted TransCanada’s value as a partner, citing experience, keeping momentum going and the pipeline company’s bias toward expansion of the project, something it shares with the state.
TransCanada has committed to a tariff for state gas based on financing, and a change in TransCanada’s ability to get financing could lower its return on equity and net present value, Black & Veatch said.