The Murkowski administration — including the governor — was out in full force Sept. 19 and 20, describing as much as they could of the confidential negotiations for a contract for an Alaska North Slope natural gas pipeline project.
The governor had said earlier in the month that the state sent the North Slope producers a proposal and expected an immediate answer.
Sept. 20 he told the American Conference Institute’s “Alaska Oil & Gas” conference in Anchorage: “We presented; they presented in response to us; we’ve presented our response … that’s where we are.”
“Everybody’s operating in good faith,” said Alaska Gov. Frank Murkowski.
“This is a big deal … they don’t get any bigger,” he said.
Alaska Commissioner of Revenue Bill Corbus, speaking at the same conference Sept. 19, reviewed the three applications the state is considering under the Stranded Gas Development Act: “a pipeline built by the owners of the gas; second, a pipeline that would be an independent pipeline (built) by a company that has no interest, no ownership position, in the gas on the North Slope; and third a non-profit corporation that proposes to send gas to market via tanker.”
A contract under the act would be for 25 to 35 years, he said, and “would provide the applicant … the assurance that they’re going to have a stable fiscal regime during the period they have need to recover their investment.”
Fiscal regime reorganization
The developer of a project would get fiscal certainty from a Stranded Gas Development Act contract, he said, but the state is also seeking certain things. “First of all, if we’re going to offer somebody fiscal certainty, we want to make sure that everything is done that is possible to construct the pipeline: we don’t want to enter into an agreement and then find out that nothing is going to go forward.
“So that’s the first thing we need, is we want certainty that the pipeline will proceed.”
Corbus said the governor set six specific goals for the negotiations, including a fair share of revenues to the state from a project which, over 25 years and with gas at $3.50 a million Btu, could bring in a total of $213 billion. The cost of operating has to come out of that, the commission said, and costs for construction. “But after that money comes out, then the question is, what is the state’s fair share” as opposed to a fair share to the owners of the gas?
Corbus said that in connection with the negotiations the state is also, “in discussions about reorganizing the fiscal regime which is at present a regressive front-end loaded tax system.” What that means, the commissioner said, is that the state takes more of the value of the resource when prices are low. The goal, he said, it “to take more of the income when prices are high.”
The state’s system is also front-end loaded, meaning, he said, that “taxes are higher in early stages of the project vs. in the latter years.”
The goal of discussions to reorganize the fiscal regime is that “the state will come out whole,” he said.
State forecast similar to Econ One
Mark Myers, director of the Alaska Division of Oil and Gas, told the conference Sept. 19 that the state has done its own forecast, and feels “very comfortable” with “a market price sustained over $4, typically $5.”
The state’s model is confidential, he said, but an Econ One study done for the Alaska Legislature using publicly available data reached a similar price forecast conclusion.
Myers noted that the governor’s six principles (a fair share of revenues to the state; gas for in-state use; pipeline availability for others; an economically expandable pipeline; equity ownership for the state; and jobs for Alaskans) “dramatically affect the style and approach the state has used in negotiations with all parties.”
In addition to its proposal to the producers, the state has negotiated contract provisions with TransCanada and worked with the Alaska Gasline Port Authority “on issues involving the use of state gas.”
Access, expandability important
Access to the pipeline and expandability are important issues, Myers said.
The pipeline needs a reserve base of 50 trillion cubic feet, and only some 35 tcf are known at Prudhoe Bay and Point Thomson. More gas must be found, but if explorers don’t have certainty of access, “they can’t invest the capital to explore,” he said.
The state’s proposal includes the rolled-in tariff structure allowed by the Federal Energy Regulatory Commission, so that costs of pipeline expansions are spread across all shippers.
But some expansion proposals, he said, may be too small to be of interest to a producer-owned line, “so we suggest that that risk be borne by those that want to expand it, particularly for in-state use of gas.” The state has “proposed a capital-contribution in aid of construction format” in those cases, where smaller shippers or end marketers, particularly for in-state use, would bear the cost of a small expansion, allowing the gas to get to market.
For explorers who would want to put larger volumes in a pipeline, early expansion is crucial and “is really an issue for the state,” Myers said. The reason is simple: with gas production from Prudhoe Bay and Point Thomson, “you’re about as year 12-plus … before you start to see any real space in that pipeline,” 2024-2026, “before space would be available” on a 4.5 billion cubic foot a day pipeline.
Explorers, he said, would have to wait “multiple lease lifetimes” before they would invest capital “if they weren’t assured up front that the pipeline would be user friendly to them…”
