Three oil and gas companies working on natural gas development in northern Alaska are worried they will be shut out of a proposed 4.5 billion cubic feet per day gas pipeline.
They have asked the state of Alaska to sell them royalty gas as part of a plan to assure capacity if the pipeline is built. The state opened bids for North Slope royalty gas Feb. 1.
North Slope gas producers who are part of the consortium planning the pipeline, however, are opposing the idea.
"The way this is being done creates a major economic uncertainty for the gas project. It's a clear step in the wrong direction," said Ken Konrad, gas manager for BP Exploration (Alaska) Inc., one of three producers involved in the pipeline group.
Anadarko Petroleum Corp. and Alberta Energy Co. have submitted a joint proposal to buy 350 million cubic feet/day of state royalty gas that would become available if the pipeline is built. Chevron USA Inc. submitted its own competing proposal for 375 million cubic feet/day of state-owned gas.
The three companies are not part of the consortium of BP, ExxonMobil Production Co. and Phillips Alaska Inc. studying feasibility of the $17 billion gas pipeline from Alaska.
Anadarko and Alberta Energy are exploring for gas in the foothills region of the North Slope, and the state fears that if access to the pipeline isn't assured for new gas discoveries, the exploration venture will be abandoned. Chevron owns gas reserves at the Point Thomson field on the Slope and is similarly worried about access to the pipeline for its gas.
The three firms are concerned about access to the pipeline because they are not part of the consortium planning the project, according to Mark Meyers, director of Alaska's Division of Oil and Gas.
At the urging of Anadarko and Alberta Energy, the state solicited bids during December for its one-eighth royalty share of gas in the existing Prudhoe Bay and Point Thomson fields on the North Slope.
When bids were opened Feb. 1 there were proposals from the two companies as well as bids from Chevron, Williams Energy and Alaska Power Co., a small Interior Alaska utility.
Alaska Power wants to switch its diesel-based generating plants to gas. Williams is studying the feasibility of a gas-based petrochemical plant near Fairbanks, where the company now operates an oil refinery.
The producer consortium is criticizing the royalty sale, however.
Mike Hurley, spokesman for Phillips, told a state legislative panel in Juneau on Feb. 5 that the proposal would dampen the economics of the project.
"We believe the proposed royalty sale further burdens an already economically challenged project," Hurley told the Oil and Gas Committee of the Alaska House of Representatives.
The claim was challenged, however, by Meyers of the Division of Oil and Gas.
"We've asked the producers to show us their numbers. They haven't done so. They told us to run numbers ourselves. We did that and came to a different conclusion," Meyers told the legislators.
The state's assessment is that the sale of royalty gas does no economic harm to the pipeline project itself, although it would impose some costs on gas producers like Phillips, Meyers said.
But there are ways those can be mitigated, he said.
If Anadarko and Alberta Energy, or Chevron, win in their effort to buy state gas, they would be able to participate if an "open season" for nominations of gas volumes is declared by gas producers' pipeline consortium, or any consortium building the pipeline, Meyers explained.
Gas pipelines are typically organized as contract carriers. An open season for gas volume nominations is declared, and the pipeline is built to handle the volumes of gas committed.
Once a shipping commitment is made it must be paid for whether there is gas or not. A purchase contract with the state gives these companies an assured supply of gas to ship until they can ship their own gas, Meyers said.
Phillips' Hurley said what troubles his company as well as BP and Exxon Mobil is that the royalty gas buyers can cancel the contract as soon as they develop their own supply, giving the royalty gas back to the state. The terms of Alaska's oil and gas leases give the state the right to switch back and forth with six months' notice between taking its royalty in-kind, selling it to others, or leaving it with the producers to market.
That leaves the producers with the obligation, under the state lease, to sell the royalty gas, shipping it through their own space on the pipeline, Meyers said.
This affects the producers adversely, Hurley said. If Anadarko and Alberta Energy can discover and ship their own gas, the producers would be required to reduce their own shipments to make room for the returned state royalty gas, because of the pipeline's limited capacity.
The reduction in producer-owned gas throughput could cost BP, ExxonMobil and Phillips "several billion dollars" in reduced cash flow over 15 years, Hurley said.
The alternative is to build extra capacity into the pipeline at the start. But this could add "several billion" to the front-end capital cost, he said.
This expense was disputed at the legislative hearing by Alan Sharp, of AEC Marketing, a division of Alberta Energy. Sharp said there should be relatively little cost of designing the pipeline at the start to handle an extra 200 million to 300 million cubic feet per day of throughput.
The royalty sale is important to Alberta Energy, he said, because the cost of reserving capacity for 350 million cubic feet/day in the big pipeline project could be around $150 million per year. To make that commitment, the security of having the state's gas to ship is critical as a backstop, he said.
Sharp also disagreed with Phillips and others in the pipeline consortium that the Federal Energy Regulatory Commission will assure fair access to the pipeline.
In a Jan. 15 letter to the state filing an appeal of the decision to hold a royalty gas sale, the three companies said FERC can compel pipeline expansions in certain circumstances.
"We disagree with their interpretation of FERC authority," Sharp said. Alberta Energy worries that once the initial open season on the pipeline passes it will be full with the three producers' gas for many years.
"If there are additional open seasons for expansions they could be structured by the producers in ways that are onerous. We need some kind of backstop," he said.
