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Vol. 11, No. 22 Week of May 28, 2006
Providing coverage of Alaska and northern Canada's oil and gas industry

Consultants speak

LB&A hears about lack of control in gas line contract, misaligned interests

Kristen Nelson

Petroleum News

Alaska got two different views on the proposed gas fiscal contract as the Legislature wrapped up almost two weeks of presentations from the administration and also heard from its own consultants.

The state got an impressive number of tax concessions in the gas fiscal contract, consultants for Legislative Budget and Audit said May 21 at a meeting organized by the committee’s chairman, Sen. Gene Therriault, R-North Pole. But they said they are concerned that the state may have given up too much control by becoming a partner in the project, especially since interests of the producers and the state are different on issues such as expansion of the pipeline.

Pedro van Meurs, the administration’s primary contract consultant, defended the contract in the administration’s wrap-up May 23, noting that the gas fiscal contract isn’t a production sharing contract to develop a new prospect, but a business negotiation with companies who already have a legal right to the resource under state leases.

Talking ourselves out of the deal

Commissioner of Revenue Bill Corbus said at the conclusion of the administration’s 11-day presentation that what is before the state in a draft released May 10 “is a business deal set forth in the contract that will bring us a gas pipeline.” The project is on the same order of magnitude as Prudhoe Bay, he said: a gas line moving 4.3 billion cubic feet a day of gas would be the equivalent of 700,000 barrels per day of oil; a 6 bcf a day pipeline would be the equivalent of a million bpd of oil.

But unlike the oil pipeline, “the state’s not going to be just a tax collector, we’re going to be a partner with the three producers,” he said, telling legislators that they need to look at the contract as a whole “as anyone can nitpick any particular section or issue.”

“One of the bigger risks we face is talking ourselves out of this deal,” Corbus said.

The administration will review comments from the public process and recommendations from the Legislature, he said, “and if practical will attempt to renegotiate portions of the contract” before the final fiscal interest finding and the contract are submitted to the Legislature for approval. If the contract is approved the governor will sign it and within 90 days the state will begin project planning with our partners, Corbus said, warning legislators that Alaska needs the revenues from a gas line. “Our greatest risk is that the producers don’t make the investment necessary to bring us a gas line.”

How much of a work commitment?

Rick Harper, formerly in charge of all of Atlantic Richfield’s North American natural gas activities, and now a member of the Econ One team, said at the May 21 Legislative Budget and Audit Committee roundtable that the contract seeks to redefine the state’s legal, regulatory, administrative, taxation and other rights to a business relationship. Harper said he thinks the contract is effective in achieving that objective, but wasn’t necessarily in full agreement with some of the specifics, beginning with the fact that there is no timeframe for expiration of the draft contract, indicating it may be an irrevocable offer. He also said that because the contract is effective on the date executed by all parties, should one fail to execute that could be an issue because there are no remedies until all of the parties have signed.

Harper said he doesn’t see a work commitment in the contract and does not equate diligence with a work commitment. He said the contract uses a different diligence standard than he is used to seeing in the industry, which would typically be due diligence or a prudent operator standard, whereas this contract refers to what is prudent under the circumstances with some specific exclusions such as errors in judgment.

Arbitration is called for in the contract, which Harper said is foreign to oil and gas, and because it is all inclusive would probably include arbitration for payment issues.

International perspective

Houston-based oil and gas attorney Jim Barnes, whose oil and gas experience includes stints with Florida Gas Co., Tenneco Oil Co. and British Gas, compared international production sharing contracts with the fiscal contract.

In a PSC, he said, the host government would be the granting party and regulator and typically a national oil company would participate in the deal as an entrepreneur. The area in a PSC is usually a single block, he said, and fiscal and commercial terms have “ring fencing,” limiting them to the area of the block. A PSC would also contain a relinquishment clause: if the block is not developed within a specific amount of time it must be relinquished. In contrast, he said, all of the producers’ North Slope leases and units are included in the agreement, more can be added so the agreement is not ring fenced.

And there is no relinquishment.

A PSC typically has a primary term of four to eight years, with a minimum work commitment which has to be completed to determine whether or not the prospect is commercial. If the investor declares the prospect to be commercial, the investor would develop a plan which would be approved by the host government. Such a plan would typically allow 20 to 30 years for oil development and 35 to 40 years for gas development.

Barnes said there are basically two types of fiscal certainty or stabilization used internationally: a standstill version, which requires that a legislature prohibit future legislatures from acting and usually has constitutional implications; and a renegotiation or re-opener whereby economic equilibrium is maintained by renegotiation to restore economic equilibrium if fiscal laws change. Barnes said the contract has the most sophisticated stabilization provision he has ever seen.

Van Meurs on stability

Van Meurs said May 23 that there are three ways to assure fiscal stability used in international agreements.

A method using exemptions and offsets is what is in the fiscal contract, he said.

But that’s not the most commonly used system. Most production sharing agreements are between private oil companies and the state oil company, and these contracts have pay-on-behalf clauses, van Meurs said, which means the national oil company will pay all taxes on behalf of the private party. That option was not available in Alaska because there is no state oil company, he said.

The third is a fiscal balance agreement, but that doesn’t occur very much because of problems. It requires that if changes are made in taxation unilaterally then the parties agree to renegotiate the terms of the contract to reestablish fiscal balance. Van Meurs said the reason it isn’t used very much is because it does require renegotiation, which adds a level of uncertainty to the contract.

No commitment to develop

Barnes said the fiscal contract has no commitment to develop within any primary term, and the initial period will end when the mainline entity declares the project has been sanctioned. While Alaska will be a participant in that decision, it will be focused as a member and its alignment and orientation are likely to be different than the state as a regulator, he said.

And the mainline entity LLC can modify the qualified project plan, without any approval by other parties and with no state approval. The state’s only remedy is if participants fail to act with diligence, and the state can establish that, then it can terminate the fiscal contract. In a PSC what usually happens is that the government will impose a reasonable best-effort deadline for what needs to be accomplished. Toward the end of that period, if something has taken place to slow the process, “you manage an extension on an exception basis rather than trying to stop it on an exception basis,” Barnes said.

He also commented on take-in-kind provisions. Under a PSC the national oil company takes hydrocarbons in marketable condition, bearing only transportation and marketing costs, whereas in the fiscal contract the state takes gas with impurities and will have to pay gathering, treatment, impurity removal and disposal costs, in addition to transportation and marketing.

Commitment different than PSC

Van Meurs said the work commitment required in the fiscal contract is a real one.

He said this contract is the only large project contract in the world that actually has a very detailed qualified project plan that describes what will be done, year by year. This is the only contract in the world, van Meurs said, requiring implementation of the work plan within 90 days of the contract being signed.

He contrasted the fiscal contract with production sharing contracts, noting that countries can negotiate return of resources for non development in cases where exclusive rights are not owned by the companies. If this was a contract from scratch, and Alaska owned the exclusive right to the gas, you’re in a stronger position, he said. But that typically doesn’t happen in Europe, North America and Australia, which operate on a lease or license system where companies keep the license or lease as it is under production.

“That puts countries on PSC in stronger position to insist on work,” he said.

How much alignment?

Alignment of interests — along with economics — has been the primary driver behind the state’s negotiations with the North Slope producers for a fiscal contract for a gas pipeline.

But do the goals of the state and the producers align?

There is alignment on the desire for a gas pipeline, said Don Shepler, an attorney with Greenberg Traurig who worked with LB&A on comments on proposed Federal Energy Regulatory Commission open season regulations.

But the state also wants a pipeline which can be rapidly expanded to serve explorers who would find and develop additional reserves of North Slope natural gas. That, Shepler, opined, is not a goal the producers share, pointing to their legal challenge to a FERC open season regulation which says the commission will look at size issues in a certificate application for an ANS gas pipeline, and require changes in the design if it does not adequately provide for additional volumes and expansion.

Since the producers have appealed that section of the FERC finding, and since the contract does not require them to withdraw that appeal, Shepler said the Legislature may end up having that component of the FERC package eliminated if the court rules for the producers.

Rolled-in vs. incremental pricing

Another issue is the FERC’s presumption in favor of rolled-in pricing for pipeline expansions. Expansions of the pipeline up to 6 bcf can be done relatively inexpensively, he said, and whether you do rolled-in or incremental pricing in those cases the cost goes down. But to take the pipeline from 6 bcf a day to 7 bcf a day would require looping. If that were done on incremental pricing, where new shippers pay for the expansion, it would be so expensive that the expansion would never happen.

FERC-mandated expansion requires that eight conditions be met, and the contract adds at least 10 more criteria before a state-mandated expansion could occur, including that the expansion not require a shipper to pay a higher rate than it would have to pay without the expansion, he said.

Shepler said FERC has said it favors rolled-in pricing for expansion. Since the contract provides for no rate increase an expansion certificate would be filed based on incremental pricing. If the FERC insists on rolled-in pricing, he said, the project entity could reject an expansion certificate requiring rolled-in pricing.

Shepler also said he shared the concern of the other consultants that annual updates are contemplated for the project plan and there seems no provision for the state to agree to material changes in the project plan.

Implications of in-kind taking

Consultant Jim Eason, a geologist who is a former director of the state’s Division of Oil and Gas, said in-kind taking of the state’s gas is an irrevocable commitment under the contract, for both royalty and gas in lieu of taxes.

Existing leases and unit agreements give the state the option to take gas in-kind or in-value, and when the gas is taken in-kind it is taken in merchantable condition, free of lease expenses. But under the contract the state always takes gas in-kind and very far upstream, Eason said, which means the state takes the responsibility for lease expenses, as well as the traditional transportation and marketing costs.

The contract also changes how gas is defined: under the contract it includes hydrocarbons and impurities, so the state receives less gas and also assumes the cost of disposal of the impurities. Disposal is not a regulated activity, he said, but will have to be negotiated.

Importance of RIK

Van Meurs said the importance of the state taking its royalty in-kind is tied to rate of return for the project, which is tied to the shipping commitment for the state’s gas. Shell told the governor earlier this year that it would be interested in marketing the state’s gas — if Shell were to buy the state’s gas on the North Slope it wouldn’t change the project dynamics, he said, because Shell would then have to make the shipping commitment.

The rate of return for the pipeline sponsors would be the same, because what matters is taking the liability off their books for the shipment of the state’s gas. To build the pipeline “you have to sign a $60 billion contract” for shipping the gas, and the value of that contract has to be reported on a sponsor company’s books, van Meurs said, so removing the shipping commitment for the state’s share of the gas makes a difference in the rate of return.

The state, he said, could still own part of the pipeline, but let someone else take the shipping commitment.

But van Meurs said he wasn’t advocating that: based on the experience of the Minerals Management Service, he said, the state would probably do better by setting up its own organization and selling its own gas in the market.

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