A roundtable discussion of the draft gas pipeline fiscal contract will continue after the Legislature begins its second special session.
Sen. Ralph Seekins, chairman of the Senate Special Committee on Natural Gas Development, said the committee would continue the roundtable in the special session, in addition to working on legislation. The committee started work July 13 on the administration’s production profits tax and on a bill amending the Stranded Gas Development Act.
Gov. Frank Murkowski’s administration has said it is working on concerns about the fiscal contract raised in public comments, including things that need better explanations and others that may result in changes in the contract.
The roundtables were held July 6 in Fairbanks and July 7 in Anchorage, with participation by representatives of the administration and BP, ConocoPhillips and Exxon, as well as legislative consultants.
Roger Marks, a petroleum economist with the Department of Revenue, reviewed the proposal that the state take its royalty and tax gas in-kind (a total of 20 percent of the gas) along with a matching 20 percent equity interest in the project.
The high cost of the project, long construction period and long distance to market mean this project has a low rate of return compared to other projects around the world. The project’s most prominent feature is its size, he said, with cost overrun risks magnified because of the size. Another risk is the future price of natural gas, something Marks called “utterly unknowable.”
What the contract does
The contract creates fiscal stability for the gas pipeline project and increases the rate of return. Marks said the state believes that because of the risks, the project will need a high rate of return to be feasible.
Under the status quo the state could take its gas in-value (producers sell the gas and the state receives a check) or in-kind. With in-value gas the producers pay for 100 percent of the pipeline but only own 80 percent of the gas. The state pays its share through tariff deductions, but the time value of money reduces the rate of return to the producers because they have to account for 100 percent of the project costs upfront, against only 80 percent of the gas.
If the state owned 20 percent of the pipeline but took its gas in-value it would insist on a firm transportation commitment from the producers for shipping the state’s in-value gas, Marks said. Because that commitment is a long-term liability the producers would have to capitalize it upfront — it would be no different for them than paying for 100 percent of the line.
If the state takes its gas in-kind and the producers own 100 percent of the project, the producers get a firm transportation commitment from the state and that offsets 20 percent of the cost. From a firm transportation commitment, it’s a small step for the state to ownership, Marks said.
With state ownership of 20 percent and gas in-kind, the state gets a seat at the table and there is a 2-2.5 percent improvement in the rate of return. State ownership and taking its gas in-kind has the same economic significance as if the state took no royalty or taxes under the status quo, but by taking an equity position and its gas in-kind, “the state gives up no revenues,” Marks said.
Jim Clark, the governor’s chief of staff and the state’s lead negotiator on the contract, said the reverse is not true: the state can’t negotiate owning pipe but not take gas in-kind. It was taking gas in-kind that led to ownership, he said.
A third alternative
Bill McMahon of ExxonMobil told the committee that as the companies negotiated with the state sometimes both sides were able to move a bit on an issue and sometimes groups of items were traded.
In the area of in-kind state gas ownership, he said, the problem was solved in a third way, without taking either the state’s or the producers’ original positions but by coming up with a third alternative.
The producers, he said, were looking for lower state take to make the project economic and were also looking for a way to value gas for royalty and production tax to reduce disputes.
When the state proposed taking its gas in-kind, that allowed the producers to drop their request for lower state take because it improved the economics, McMahon said. It also solved the valuation issue because the state would sell its own gas.
In-state gas use
Marks said there are risks associated with the state’s position: completion, reserves, force majeure and marketing, but said the state does not believe those risks are incredibly large — and in exchange it gets a gas pipeline and can sell gas in-state.
There has been criticism of the contract for no guarantee of in-state gas sales, he said, but the state would be financially indifferent between selling gas in-state and selling it in Chicago. With the short distance to Fairbanks — and a correspondingly low mileage-sensitive tariff — Fairbanks would have the lowest priced gas in the country, he said.
Bob Loeffler, a partner in Morrison and Foerster, and counsel to the state, said the administration has been “listening carefully about serving in-state needs” and is looking at policies for pricing that gas. The thinking, he said, is that there would be a pricing formula where the state would be economically indifferent between in-state and long-haul sales. He also noted that the Alaska constitution requires that such a sale be in the best interest of all Alaskans.
Clark said this is a more complicated issue than it would appear, but it is not a contract issue: It’s a policy issue that the administration is looking at discussing in the fiscal interest finding. Policy, he said, would be developed by the administration and the Legislature after the contract, but before the open season.
Clark said pricing choices for in-state sales include: netback plus transportation; netback plus transportation plus a bidding rate (the state would put the gas out for bid); and a Henry Hub price such as is being used in Southcentral Alaska.
Loeffler said he thinks some existing in-state users of natural gas, such as Enstar, could probably be ready for an in-state open season. He said while you have to commit to take capacity in an open season and demonstrate creditworthiness, it would be a number of years before gas would flow, providing time to build out infrastructure. The open season is probably a year and a half to two and a half years out, and payments wouldn’t start until gas is flowing, he said.
Another concern about in-kind gas is the marketing issue.
Clark said the Minerals Management Service is taking gas in kind and finding that they make money on the upside, a 1-2 percent increase over taking gas in-value.
Deputy Commissioner of Natural Resources Ken Griffin said based on a recent MMS report on its in-kind program the costs the state attributed to marketing in its model were “probably quite conservative.” MMS benefits from marketing a relatively small amount of gas, Griffin said, larger volumes are more meaningful to the market and the state will have some 800 million cubic feet per day going into a marketing center. If the state took its gas in-value, he said, it would be dependent on the companies to market that gas and their marketing strategies, organizations and activities are very different, and the state would be captive to a very aggressive or a very conservative risk-taking strategy. By taking gas in-kind, he said, the state will develop its own risk profile.
In-kind also eliminates valuation disputes. Over the years those have been hard- fought and have created frictions that make it difficult to function effectively as partners, Griffin said, and make it difficult for the state to encourage developments on the North Slope.
Clark said the state is looking at developing an in-state team with expertise similar to that of the permanent fund, and to use them to manage a group of outside marketers. The state would keep those that had the best results and replace others.
Griffin said DNR is studying ways to manage the marketing and making contacts.
