The proposed gas fiscal contract is a bad deal for the state, former Department of Natural Resource officials Tom Irwin and Marty Rutherford told Petroleum News following a Commonwealth North presentation on June 9 in Anchorage.
Rutherford, a former DNR deputy commissioner, said they believe the state should back away from the Stranded Gas Development Act under which the administration of Gov. Frank Murkowski negotiated the gas fiscal contract.
“It was a law that was passed when the price of gas was very low and its time has passed,” she said. Projections for gas prices and demand are much different than they were four years ago. The gas is no longer stranded, she said, and a natural gas pipeline is viable without economic incentives.
The state might still decide it wants to offer incentives, Rutherford said. “We could do what the federal government did: we could pass a law of general application that is available to anyone who wanted to build the project with very clear, very quantifiable incentives available across the board.” Such incentives might include no property taxes until gas flows, reduced property taxes, reduced production taxes or even a direct subsidy. Such incentives, she said, would be “clear and concise with nothing hidden and nothing that will become obvious as a problem over time.”
And those incentives could be tied to completion of a project: 100 percent would be available for a line completed in 2017, but only 80 percent if the completion date fell to 2019.
Economic without subsidies“My whole background’s in economic development,” said Irwin, who was DNR commissioner until Gov. Murkowski dismissed him last fall after Irwin raised concerns about negotiations for a fiscal contract under the Alaska Stranded Gas Development Act. Six department officials, including Rutherford and Mark Myers, then director of DNR’s Division of Oil and Gas, quit in protest.
Irwin said he did the economics on a North Slope gas project himself and “I am strongly and absolutely convinced this is an economic project” (without incentives). The DNR team working on the project reached the same conclusion, he said, as did Econ One, a firm hired by the Legislature to look at the project.
Read the contract, he urged the audience, and then approach it from a business perspective.
He said his conclusion is that the companies got a good deal, but not the state.
“The state gets no deal,” Irwin said. First, the producers can get out of the contract in 60 days — the state has no way out short of proving that the producers did not meet a diligence standard to move ahead with the project. Studying gas prices could meet that test, he said. “It’s a good deal for them. We have no deal.”
The contract also removes the state’s sovereign authority, he said: “Would you, with your company, remove your authority in a contract?”
Irwin said he believes that giving up the state’s option to take royalty in kind or royalty in value is “an absolute mistake” and creates significant cost and risk issues for the state, putting the state “in a position of weakness in getting capacity in the lines” and in competition with the best marketers in the world to sell the gas. We’re now told, he said, that another company will sell the gas for us. But we don’t pay for that now, and we get the highest price any of the sellers gets.
And if the state is going into this as a business, Irwin said, Alaskans need to see the real costs, “not the political feel-good” cost. He said in presentations it appears a higher gas price is used in discussing revenues — without costs deducted — and a lower price when discussing supports needed for the project. In business both parties use a range of prices, he said.
The facts need to be out on the table, he said, so that everyone can answer the question: “Would you sign this if it was your business?”
Rewrite of state’s positionRutherford said there are more than incentives in the contract. “This contract is a total rewrite of our entire oil and gas relationship with the producers,” turns the existing oil and gas leasing program on its head and “largely surrenders the power of all three arms of government, our sovereign powers, to the producers.”
The Legislature loses its power to tax the producers for up to 45 years; the “executive branch loses its right to manage and regulate the producers’ oil and gas leases and the ability to ensure those leases are adequately and appropriately developed” for up to 45 years; and the “judicial branch loses the ability to oversee the contract enforcement for up to 45 years.”
Forty-five years is a long time, “and that alone, in my mind, is an unacceptable risk. Nobody thought that when ... the ELF (economic limit factor on the state’s production severance tax) was passed 15 years ago, that we were implementing a flawed taxation structure on our oil and gas leases. And yet, within 15 years, that’s what we discovered: it is a flawed structure.”
The period of time the contract is locked in “is far too great a risk for us to accept,” she said.
The cost of contract subsidiesRutherford said the contract sets up a system that is “a total destruction of our normal, competitive environment” for oil and gas leasing, allowing the producers to lock up some 500 leases on the North Slope for the term of the contract, “for 45 years, if they meet that weak diligence standard ... which does not require building a pipeline or doesn’t require significant investment into a pipeline.”
The state also loses its ability “to ensure that leases are developed in a timely manner should they be economic,” she said, and creates a two-class system that discourages investment by companies who don’t have these advantages.
Rutherford said Econ One has found that with no state incentives and the producers owning 100 percent of the project under the current fiscal system, if natural gas sells for $4 the producers have a 17.2 percent rate of return; at $5, it’s 20.4 percent. She said this compares to a 15 percent rate of return oil companies generally use as a benchmark.
Then there is a $13.25 billion cost to the state to sign the contract, “independent of its own investment in the pipeline,” Rutherford said, which at a $4 gas price is a direct subsidy to the producers, independent of the state’s ownership position, worth “over half the value of the state gas.” At $3 gas, the state’s position is negative. “So we are writing a check in order to produce our gas.”
Compare that to the status quo, she said: If the price of natural gas goes below the transportation cost — but the state is taking its gas in value, rather than in kind — “we don’t get a check, we pay zero, but we don’t actually go negative.”
The risk at low prices is one that would alarm any company, she said.
Upstream cost allowance: $5.45 billionThe $13.25 billion comes from several subsidies, the first of which is the upstream cost allowance.
The state made “a bad decision” in 1980, Rutherford said: it agreed to pay upstream costs it was not obligated to pay under its leases on royalty oil and gas at the Prudhoe Bay field. Later court decisions confirmed the state did not need to pay these costs, but in 1980 it agreed to pay them to accelerate a royalty in kind sale for Prudhoe Bay oil.
The contract expands that payment across the North Slope, she said, not just for royalty gas but for all of the state’s gas.
Rutherford described the contract as “a repeat on a much larger scale of what happened in 1980,” a mistake, she said, that has already cost the state $2 billion on oil alone.
The upstream cost allowance in the contract, less what the state agreed to pay at Prudhoe in 1980, is a subsidy of $5.45 billion over the life of the contract, she said.
Upstream credit: $4 billionThe proposed production profits tax involves a subsidy of another $4 billion, she said, with credits against operating costs and capital costs in the field, even though the state doesn’t get a profits tax on gas, just a flat 7.25 percent of the tax taken in kind. Once you net out the royalty share it’s actually 6.8 percent.
Although the state gets no profits tax from gas, “we still pay all those development costs,” she said. And because there is a credit but “no upstream uplift or bump to the state in terms of its percentage,” that credit is worth about $4 billion.
Rutherford said the $4 billion is based “on very conservative capital costs on the upstream. It may be far greater than that ...” in which case it could be “a much higher number.”
She said gas that needs to be developed for the project includes Point Thomson and the National Petroleum Reserve-Alaska, as well as other fields, and will require significant capital investment in upstream gas development. The state would get less gas than it would under the present system, “where it makes zero investment,” but through its credits would pay for 40 percent of the development.
Midstream pipeline and gas treatment plant: $2 billionThe 100 pages recently added to the contract include a 35 percent credit for upstream pipelines leaving the unit boundaries and going to the gas conditioning plant, and a 35 percent credit for the gas conditioning plant, Rutherford said.
Those costs will include a big gas pipeline from Point Thomson and as many as a dozen other pipelines to move the additional 30 trillion cubic feet of gas needed, she said.
“We hope they get built,” Rutherford said. “But under this contract the state pays 35 percent in direct cash credit to the producers for the cost of those lines. Then on top of that we have agreed to pay 20 percent of that infrastructure as an owner.”
Rutherford said what it comes down to is the state pays 48 percent of the cost and gets 20 percent ownership in the midstream pipelines and the gas treatment plant, which has an estimated cost of $2.6 billion to $2.8 billion. By paying 48 percent of the costs and only having 20 percent of the ownership the state bears “far more proportional cost overrun risk than any of the producers,” she said.
The $2 billion midstream subsidy is independent of the state’s 20 percent investment as an owner, she said.
Processing subsidy: $440 millionThe state will also pay a processing subsidy, Rutherford said.
Under the present system if the state takes royalty-in-kind gas it takes it ready to go into the pipeline. And that’s not how it comes out of the ground, she said. Prudhoe Bay gas contains some 12 percent CO2, carbon dioxide, some H2S, hydrogen sulfide, and a lot of water and it “costs money to remove those products,” Rutherford said. As part of the state’s lease agreements, in exchange for taking only 12.5 percent royalty, the state does not pay to remove and dispose of those products.
The cost to remove them isn’t in the contract; it will have to be negotiated. There’s another cost: the liability of taking the gas includes the “physical liability to move it,” which means insurance and liability issues, she said.
Conservatively it will cost the state some $440 million over the life of the contract, for something the state now gets for free.
Selling the gas: $1.4 billionSince the state will take its gas in-kind, rather than in-value, it will have to sell the gas. And it loses the “higher-of” it got when it took gas in-value and the producers sold it — and delivered to the state a check reflecting the highest value any of them got.
It was another compromise the state made for its 12.5 percent royalty, Rutherford said.
So what will it cost to sell the gas?
She said she’s heard the producers talk about half a cent to market it. “That’s ridiculous: You can’t even cover your insurance liability for that and the DNR looked hard at those marketing costs,” Rutherford said.
“And we used outside experts,” she added.
The equivalent of having producer marketing and skill, and the value of the “higher-of” provision came to about $1.4 billion, Rutherford said.
Other costs and risksThe subsidies add up to $13.25 billion, she said: $5.45 billion in upstream cost allowance, $4 billion in midstream pipeline and gas treatment subsidies; $2 billion from the 35 percent credit; $440 million for the processing; and $1.4 billion for marketing.
But there are other costs and risks the state wouldn’t bear if it took its gas in-kind.
Rutherford said the big one is the take-or-pay capacity the state will have in the gas pipeline over 25 years or so, whatever the pipeline sets for firm transportation commitment. If the state doesn’t have enough gas, it still pays the transportation fees; if it has too much gas, “it’s a distressed seller on the slope and has to find a buyer on the North Slope.” He characterized the protections in the contract as “weak” and said “they don’t really work.”
The exposure over the life of the contract is billions of dollars, Rutherford said. There are inefficiencies in any system, and the state will have some 900 million cubic feet a day of gas to deliver to the pipeline. “So even if you’re only 10 percent inefficient (in the slope pipelines and the gas processing facility) on this, there are $3 (billion) or $4 billion ... of risk that we’re going to bear there.”
That’s because the state won’t be able to tell the producers to produce more or less gas.
Irwin said he’s heard many times that the state is getting into the gas pipeline so it can be like the producers. “We will never be like them: ... We don’t own any wells, we don’t own any valves, so do not buy the story we will be like them.”
The producers, he said, have flexibility: they can expand the field if they don’t have enough gas; they can trade reserves; for a short time, they can allow one producer to over or under produce. The state, he said, doesn’t have those options.
“What happens is the state is a disadvantaged minority owner in a system where it doesn’t control the upstream.”