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Alberta Energy, Anadarko looking for space in gas pipeline
Companies want to purchase a portion of state’s North Slope royalty gas to ensure product to ship before they have gas of their own to put into pipeline Kristen Nelson PNA Editor-in-Chief
Anadarko Petroleum Corp. and Alberta Energy Co. Ltd. subsidiary AEC Oil & Gas (USA) Inc. have 3 million acres of North Slope exploration acreage between them — a combination of state, federal and Arctic Slope Regional Corp. lands, much in the gas-prone foothills — and a correspondingly large interest in gaining access to any gas pipeline from the North Slope.
The companies have been talking to the state about the state’s royalty North Slope gas, and told a meeting of the Alaska Royalty Oil and Gas Development Board Nov. 13 that they support a state North Slope royalty gas sale.
Both Mark Hanley of Anadarko and Alan Sharp of AEC Marketing said access to a gas pipeline was a requirement for continuing exploration on gas-prone acreage in Alaska.
If the companies were simply to nominate shipping space with pipeline owners in open season they could end up paying $150 million to $200 million a year for the space if they were not ready to ship gas when the pipeline started up. With 30 trillion cubic feet of proven reserves on the North Slope, a 4 billion cubic foot a day pipeline could be at capacity for 20 years if the explorers do not nominate space in the open season.
If they purchase state royalty gas, they can then commit to pipeline space and use that space to ship state royalty gas until they have gas of their own ready for the pipeline.
AEC says no risk for state Anadarko and AEC are partners in acreage and are interested, AEC’s Sharp told the board, “in purchasing state royalty gas to backstop, if needed, any potential nominations for capacity during an open season.” The companies would nominate space in a pipeline separately, but make a joint bid for state royalty gas.
Sharp also said that with the volumes of discovered gas, neither new explorers nor the existing producers would need to explore for 20 years.
AEC has 1.1 million acres in the foothills — state and Native lands — and is looking for non-associated gas (gas that is not part of an oil field) in the area, Sharp said.
Because existing gas would fill the pipeline for 20 years, he said, AEC is concerned that if it doesn’t nominate space in the first open season, it might never be able to acquire pipeline capacity.
“Without some assurance concerning pipeline capacity, continued investment in new Alaska gas exploration is unlikely,” he said.
“We believe,” he told the board, “the state should leverage its gas volumes of tomorrow to support gas exploration projects of today. The state has no risk, as this is a natural hedge.
“If the pipeline does not proceed, the state would have no obligation to deliver contracted future royalty gas volumes under those circumstances.
“The benefits are greater exploration and greater revenues…”
Encourage exploration Anadarko’s Hanley told the board that holding a state royalty gas sale will encourage additional exploration. Anadarko, he said, has 1.9 million acres of state, federal and Native land on the North Slope, is shooting seismic over the gas-prone foothills and hopes to do gas drilling next winter.
Transportation of gas is crucial for us, he said, if we can’t get pipeline capacity, we can’t spend money to find oil.
The risk for Anadarko, if it just took gasline space in an open season, is that based on an estimate of one-half billion cubic feet it could be charged $150-$200 million a year for the space if it had no gas ready to ship — and that could be for a 20-year contract.
“A $200 million a year risk without any gas would be a huge risk,” Hanley said.
“If we don’t have gas, we night not nominate — it’s a huge risk and I can’t say we’d take it — it’s a fairly watershed event for us.”
And without pipeline capacity, Anadarko might not go forward with exploration in the foothills sales area, he said.
State wouldn’t see all its royalty gas Bonnie Robson, deputy director of the Division of Oil and Gas, said the state wouldn’t sell all of its North Slope royalty gas. It needs to take some of the gas in value to establish a base price — royalty-in-kind gas, by law, must be sold for more than royalty in value brings in — and would also want to have some gas available for instate sales and for purchasers who aren’t ready to come forward now. The state would probably be interested in selling 50-80 percent of its royalty gas, Robson said, although she noted that at the end of the sale process the decision may be to sell no gas at all. For a 4 billion cubic foot pipeline, the state’s one-eighth would be 500 million cubic feet, so 50 percent of its gas would be 250 million cubic feet a day.
The state is looking at a three-part sale price including the base price, which can’t be less than the royalty-in-value price. Robson said the second part would be a bonus bid, a fixed dollar amount, probably $1 per thousand cubic feet. For a three-year supply, she said, this would come out to 1/10 of a cent per thousand cubic feet — for a 15-year supply, it would be 1/50 of a cent per mcf. So the amount, she said, would be fairly small on an mcf basis, but would cover the cost of the sale and would ensure that only serious bidders participated.
The third part of the bid would be a premium, and the bidder would decide what premium to offer. Robson said examples of a premium include an extra cent per mcf, instate investment or a floor rate for the price.
Miscellaneous additional terms Additional terms that the state is looking at include flexibility to renegotiate some of the specifics if gas markets or the gasline develop in ways other than what we now anticipate, Robson said. The state might require a security for payment of any future price adjustments. Robson said the final royalty-in-value price may be higher after audits or litigation, requiring an increase in the royalty-in-kind price. In the past the state has had a problem with its royalty-in-kind oil sales — by the time the royalty in value is finally determined buyers are unable or unwilling to pay the additional amount to the state. A security for payment would be one solution to that problem, or the contract might provide an incentive for full payment of the royalty in value either through extra interest or payment of state’s attorney fees if the buyer challenges the price.
Other provisions could prevent the state from being locked into a contract if the gasline is not built by a certain date, or if an open season is not held within two years or if the pipeline does not go to the Lower 48. Mid-December goal for contract Robson said that the public comment period ends Nov. 30 and that the state’s goal is to have a final best interest finding and solicitation for bids out in mid-December. Bidders will have 30 days to submit bids, which will be opened in public in mid-January.
If there is an open season in progress when the bids are opened, the state will accelerate a work on the bids, which may need negotiation before going to the royalty board and then to the Legislature, which will need at least one month and probably two to hold hearings and consider the bids.
Because there are a number of variables, the state needs the right to negotiate and nail down terms but, Robson said, the bidders won’t have the right to improve their bids.
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