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Vol. 11, No. 11 Week of March 12, 2006
Providing coverage of Alaska and northern Canada's oil and gas industry

Rutherford: Questions on gas deal

Former DNR deputy commissioner has questions Alaskans should ask about a fiscal contract for an Alaska gas pipeline project

Kristen Nelson

Petroleum News

What should Alaskans look for in a North Slope gas pipeline fiscal contract?

Marty Rutherford provided a detailed list in a Feb. 23 talk at the Pac Com conference in Anchorage.

Rutherford, a former deputy commissioner of the Alaska Department of Natural Resources, is one of six department officials who resigned after former Commissioner Tom Irwin was terminated in a dispute with the Murkowski administration over the negotiations.

Rutherford was constrained by the confidential nature of the negotiations — and the fact that a contract is not yet public, although Gov. Frank Murkowski said Feb. 21 that the administration and the North Slope producers have reached agreement on terms for fiscal certainty for the agreement. Once the contract, and a Department of Revenue best interest finding, are made public there will be a public hearing and public comment period and an opportunity for the administration to re-negotiate with the producers, if necessary.

Then the contract, accompanied by bills proposing amendments to the Alaska Stranded Gas Development Act, will go to the Legislature.

The Legislature is already considering proposed changes to the state’s oil production tax, changes which the administration has said will later be tied into the gas fiscal contract. The Legislature will have to consider the administration’s proposed amendments to the act and then vote up or down on the fiscal contract. The Legislature adjourns May 9. The amendments and contract are expected to require a special session.

Irwin, Myers expressed concerns

Two of the former officials — Irwin and former Director Mark Myers of the Division of Oil and Gas — expressed a number of concerns to an open Republican caucus Jan. 12. Rutherford told the Pac Com audience that she was appearing alone because Irwin had a business conflict and was out of state and Myers is traveling out of the country.

Irwin told legislators in January that they would hear how much the state was going to make from a gas pipeline, but said he worried that they won’t be told how much the state could have made, and asked them to dig into the details when the contract becomes public. The companies will look out for themselves, he said: The Legislature needs to look out for Alaska.

Myers told legislators the state needs to negotiate hard with the producers and said that in his time as division director the state never lost an appeal or a court case because the division did its homework, worked hard and “when we made a deal we made them keep it.”

Myers said the Department of Natural Resources believed that through sophisticated negotiating the state could get a fair deal for all sides. Work commitments, he told legislators, are a crucial part of a contract. Incentives are appropriate if the state wants to accelerate a gas pipeline, but real work commitments are required, he said.

Myers also said that since the state doesn’t control gas production it doesn’t control the flow of gas into the pipeline. That, he said, translates into significant business risk. He said the alternative is for the state to take its gas in value and have the producers use their expertise to market the gas and get the state the best price. Myers said access to the gas pipeline for explorers is also a significant issue because explorers are the most active drillers.

State needs to know value of what it is giving up

Rutherford said there are a number of questions which must be answered satisfactorily to ensure the state is getting a good deal in exchange for the financial concessions included in the contract.

The gas business is more complex than the oil business, she said: Regulatory rules for transporting gas are more complex than for oil, “and gas trades very differently and many more times than oil, creating transportation, marketing and valuation challenges.” These are complexities that allow participants to “game” the system and create extra profit opportunities at the expense of less sophisticated players. The state could lose “billions of dollars due to unnecessarily exposing ourselves to these complexities,” she said.

Rutherford said she wasn’t recommending the state not enter into the contract, but that the contract ensure the state can manage the risks and that the contract limits gaming opportunities for others.

The devil, Rutherford said, will be in the details of the gas contract, and those details will determine the state’s “ability to maximize our future economic opportunity.”

The state will own a percentage of the project. The governor, Rutherford noted, has talked publicly about a 20 percent ownership.

And what does the project include? Not just the gas pipeline from the North Slope to Alberta, but also the gas treatment plant on the North Slope and upstream field developments including in-field transportation pipelines. The state may have the option of participating in other elements of the project, such as a pipeline to the Midwest, if that is developed.

The state will have to make a large initial capital outlay, she said, “and an ongoing and uncertain commitment of capital over time.”

As an owner, the state will also have the same construction cost overrun and completion risks as the producers, she said. The state’s investment in the line will be repaid through the tariff paid by shippers of gas.

Royalty in kind

The state typically takes its royalty in value, Rutherford said, because that allows it to get the highest price received by anyone else selling the state’s oil and gas.

As part of the gas pipeline contract, however, the state will take its royalty share in kind.

Rutherford said that under the state’s current leases it also gets other things of value: it doesn’t pay for storage after production and before shipment; it doesn’t pay for disposal of impurities such as carbon dioxide and sulfur; it receives the benefits of the producers’ marketing efforts; and it receives the “higher-of” value when more than one company is selling resources.

She said these things augment the value of the state’s royalty and, “according to the state’s royalty counsel, were one of the reasons Alaska imposed relatively low royalty rates.”

Rutherford said if the contract changes any of these things, “the value needs to be identified and factored into the trade-offs.”

The Alaska Division of Oil and Gas says in its current five-year lease sale program that fixed royalty rates are generally 12.5 percent or 16.67 percent, although they have been as high as 20 percent. Companies commit when they accept a state oil and gas lease to pay the state a royalty portion of the oil and gas they produce from the lease.

Take-or-pay contracts

Ownership of the line is separate from contracts to ship on the line.

Even though the state proposes to own a portion of the pipeline, it will need to contract for capacity in the pipe so it can ship the gas it takes in value. This requires a long-term contractual obligation, a “take-or-pay” contract for shipping, Rutherford said.

The state, like any other shipper, pays for the space whether it uses it or not. “So obviously we want to make sure we have gas” to put into the pipeline, and a customer at the other end who will pay a good price for the gas, she said. If the state underestimates the amount of capacity it needs it will have to buy more from another shipper, “probably at a premium price.” Conversely, if the state contracts for more capacity than it needs, it will have to sell that capacity, “probably at a low stress price.”

Rutherford said the concern in this area is that, since the state isn’t a producer, it “will never be as well situated (as the producers) to manage production to closely match our shipping commitments.” Which means the state could lose money, as well as not being as competitive as producers in buying and selling capacity positions on the pipeline.

Some basic questions

Rutherford said she believes that before the state signs any contract it needs to ask some basic questions, beginning with are concessions required to make an Alaska gas pipeline project economic.

The price of gas over the next 20-50 years is the key factor, she said. Throughout negotiations the state used a stress or lowest price of $3.50 per thousand cubic feet. EconOne, the research company hired by the Legislative Budget and Audit Committee to analyze the economics of a gas pipeline project estimated the producers would receive an internal rate of return of 20.4 percent at a $5 per mcf price for gas, assuming the producers paid for all of the facilities.

Since the state has been negotiating at a $3.50 per mcf price, Rutherford said that when the discussion becomes public perhaps it would be more realistic to ask to have the economic analysis presented at a $5 per mcf price, given that ConocoPhillips Chairman Jim Mulva said the company’s purchase of Burlington Resources was based on projected future gas prices of $7 to $8 per mcf, with a stress price of $5 per mcf.

Rutherford said EconOne modeling information is available on the Legislature’s Web site; she said the analyst’s modeling was based on the three state models used in commercial negotiations with the Stranded Gas Development Act applicants. (The information is on the Legislative Budget and Audit Committee Web site: http://lba.legis.state.ak.us/.)

Difference: negotiating strategy

Rutherford said the difference in opinion that led to the departure of the Department of Natural Resources team from the negotiations was based on negotiating strategy. She said the governor and his advisors decided to offer the producers incentives so that the Alaska gas pipeline project would make them more money than many other projects worldwide.

“The DNR team looked at our leases and the obligations it places on the producers to sell or produce the gas if it is economic, looked at the economic analysis provided by the consultants and wanted to use the leverage provided by those obligations, along with reasonable incentives, to reach an agreement. I still believe this approach is the way to maximize the state’s interest in this project,” Rutherford said.

Potential cost of concessions

If concessions are appropriate, Rutherford asked, do we know the potential cost of what the state is giving up?

And is the state willing to contractually limit its right to change its tax structure and fix the management of its royalty share for 50 years?

Rutherford said the contract will also determine whether Alaska has dozens of oil and gas exploration and production companies — a situation like that in Alberta — or whether a handful of companies are allowed “to create a commercial environment that may result in a gas pipeline, but could seriously deter new companies from investing in Alaska’s gas resources.”

That could be the result, she said, of allowing the producers “to control and limit access to the gas pipeline transportation system through inadequate pipeline expansion requirements and high tariffs.”

That, she noted, is the path Alaska chose with the trans-Alaska oil pipeline: a high tariff on the oil pipeline and uncertain and costly access to North Slope facilities have been a barrier to new companies.

Commitment to build

There are a number of provisions that should be in the contract, Rutherford said.

A firm commitment to build the pipeline within a certain timeframe if the project is economically viable within specific parameters should be linked to “enforceable work commitments” such as development of the Point Thompson unit and corporate sanction of the project by specific dates. And the state should be able to get out of the contract if a pipeline is not built within a specific time.

The interests of explorers — independent oil and gas companies who don’t yet have defined gas reserves — must be protected through non-discriminatory pipeline access spelled out in the contract. Mandatory expansion requirements must also be included, she said.

The debt to equity ratio should be no greater than 75 percent debt to 25 percent equity because the Federal Energy Regulatory Commission allows 12 percent to 15 percent rates of return on the equity portion of the investment, and the higher the equity portion, the higher the tariff structure. A higher tariff, Rutherford said, is a barrier to non-owner shippers on the line.

If the state owns upstream pipelines and facilities, it must ensure tariffs do not re-capture sunk costs it has already paid through previous royalty deductions.

A single Alaska zone for all in-state gas deliveries should be included in the contract, ensuring Alaska gas is not charged for pipeline shipping tolls beyond the actual distance.

The state will be a 20 percent partner in the pipeline corporation, and it should ensure its 20 percent ownership cannot be outvoted on issues of significance to the state, such as pipeline expansion.

And, Rutherford said, the contract should not commit the state to pay for costs it is not currently required to pay such as disposal costs for impurities, storage fees for gas and upstream cost allowances for field development costs.

State has choices

The state has choices, she said, and if those choices had been seriously considered “they could have provided the state with negotiating leverage.” Those choices need to be considered now, Rutherford said.

The contract can be amended and should be to include adequate protections, she said.

The state could also pass legislation requiring such protections as a project start date, adequate pipeline expansion requirements and a reasonable tariff, and making such a package available to any company or consortium capable of building a pipeline, including the producers.

She also said the public should be allowed to consider the alternative commercial deals the state has been offered from the Alaska Gasline Port Authority, TransCanada Pipeline Co. and MidAmerican Pipeline Co.

“This would ensure the public can fairly determine if the commercial deal presented in the proposed producer contract is the best the state could attain,” Rutherford said.

And, the state could take steps “to exercise our lease prerogative” requiring the producers “to develop the resource when the resource is reasonably economic.”

This, she said, is “truly critical” at Point Thomson, where the companies have failed to produce oil and gas for 30 years, “but continue to warehouse the resources.”

Rutherford said several of these alternatives could be pursued simultaneously.



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