The draft fiscal certainty contract for an Alaska North Slope natural gas pipeline negotiated by Gov. Frank Murkowski’s administration with the North Slope gas pipeline proponents — BP, ConocoPhillips and ExxonMobil — contains lease and regulation provisions which worry consultants hired by the Legislative Budget and Audit Committee to evaluate the contract.
Exhibit D of the contract is a list of the leases that may produce gas, or oil, and are entitled to fiscal certainty under the contract. The Department of Revenue said in the preliminary fiscal interest finding that “new leases may be added if a sponsor obtains the lease at a state, federal, or private lease sale.” There are time constraints for the added leases: those acquired at state lease sales must deliver gas to the line within 15 years or be removed from the contract; leases acquired at federal or private lease sales have 20 years to deliver gas to the pipeline.
Jim Eason, a former director of the Alaska Division of Oil and Gas, and now a legislative consultants, said in a June 3 memo to the Legislative Budget and Audit Committee: “With a suite of documents this complex and this voluminous, should the contract be approved, I fully expect the Parties on both sides to discover all of the implications years from now.”
Eason said he confirmed with the Department of Natural Resources that the list of leases in Exhibit D of the draft contract “includes all North Slope leases currently owned” by BP, ConocoPhillips and Exxon, and that future leases they may obtain will be added to the list. If a proposed uniform upstream fiscal contract is signed by other North Slope lessees, leases that those companies hold would be added to the list of leases under the contract in exchange for a commitment by those companies to deliver gas to the line.
Eason said he is concerned about lease rights the state would give up under the proposed contract, specifically terms of the contract which change “existing rights and obligations under the Department of Natural Resources … statutes, regulations, lease terms and unit agreement terms, and the increased risks and fiscal consequences which those terms collectively impose upon the State.”
“The scope of those risks and fiscal effects is unprecedented in the history of the State’s management of its royalty interests,” he said.
Regulatory changes under contractHouston-based oil and gas attorney Jim Barnes, a partner in Barnes & Cascio, said in a May 29 letter to Legislative Budget and Audit that Alaska oil and gas arrangements “are managed and controlled through comprehensive regulation,” which the state is considering altering to better compete with other oil and gas jurisdictions.
Barnes discussed Article 41.2 of the contract, which provides: “After the Effective Date, any right, privilege or obligation of a Party in a lease, other agreement, regulation, rule, order or decision (“Document”) is amended for the Term only to the extent necessary to conform to the provisions of this Contract. If there is a Dispute regarding whether this Contract and another Document create conflicting rights, privileges or obligations, the Parties shall attempt to resolve the Dispute in good faith by attempting to harmonize them, giving reasonable effect to both. If the Parties cannot harmonize them, this Contract controls.”
He said that because the fiscal contract “is so broad in its scope and specifically refers to so many entities, leases, properties, assets, and types of activities, the impact of this conforming provision on the State’s regulatory regime would be very far reaching and will probably have many unintended consequences.”
The Stranded Gas Development Act says a fiscal contract may “modify the timing and notice provisions of leases and unit agreements pertaining to the State’s rights to receive its royalty in kind or in value …” but, Barnes said, “does not appear to contemplate that any right, privilege or obligation of any Participant in all leases, agreements, regulations, rules, orders and decrees would be modified to conform to a fiscal contract.”
Shift to arbitrationBarnes said that while the existing regulatory regime resolves disputes in administrative proceedings or state courts, under the fiscal contract “all disputes, even administrative and regulatory disputes, would be resolved by arbitration.”
The contract “would suppress the State’s regulatory regime as it pertains to the Project and the properties and activities of Participants for the duration of the Fiscal Contract,” he said.
The contract requires the state: “to endeavor to avoid (Regulatory Commission of Alaska) jurisdiction and to indemnify the Participants from losses arising from RCA jurisdiction; to relinquish its presumption of correctness in interpreting the application of the State’s regulatory regime; to conform all rights, privileges and obligations under any lease, agreement, regulation, rule, or order to the Fiscal Contract; to resolve all regulatory disputes by arbitration; and to waive any defenses based on the State’s sovereignty.”
Barnes said specific effects of the measures on the state’s regulatory regime “cannot be accurately predicted.”
“From the perspective of the State, however, the general effect that these measures would have on the State’s regulatory regime with respect to activities under the Fiscal Contract would likely be pervasive and chilling.
“The determination of whether and to what extent the State may be willing to suppress its regulatory regime is a matter of policy for the State,” Barnes said.
Merchantable, free of field costsEason focused on rights the state now has, but would lose under the contract, including its right to receive “its in kind share in merchantable quality and free of any ‘field costs’ incurred to make it so.” He said there are exceptions to this general rule such as a settlement agreement for Prudhoe Bay oil which allows a 96 cent- per-barrel field cost allowance and 22 cents per thousand cubic feet for gas. The Alaska Legislature revised the state’s oil and gas leasing statutes in 1978, requiring that royalty share be free and clear of unit expenses, he said.
Under the contract the state gives up this right and agrees to pay an upstream cost allowance of 22.4 cents per mcf on state gas, “defined under the contract to include impurities” which, Eason said, have been estimated to be as much as 12 percent at Prudhoe Bay; the state also pays for disposal of impurities.
“Currently,” he said, “the State has no obligation to pay upstream costs for non-Prudhoe Bay Unit royalty gas, tax gas or for impurities anywhere on the North Slope.”
Under its leases the state is also protected if a purchaser refuses to take the state’s royalty share, he said, something the state has given up under the contract by assuming “full responsibility for organizing and implementing the downstream transportation, marketing and delivery of its royalty and tax gas — all of which are currently the responsibility of the State’s lessees at no cost to the State.”
And when the state takes oil or gas in value it gets the “higher of” price when multiple sales are made, another thing it loses by taking gas in kind under the contract.
Eason said the contract is also silent on ownership and valuation of the state’s share of liquids in the gas, the natural gas liquids recovered at an extraction plant, and whether or not the state will share in any revenue from sale and use of substances such as carbon dioxide removed from the gas.
“Absent some prior and explicit agreements on these issues, it is very likely that disputes will arise,” Eason said.
In kind could be taken at AECO HubEason said it is his recollection that in testimony before the Legislature when the Alaska Stranded Gas Development Act was first passed, “the sole focus on royalty-related changes that might be required were changes to provide the producers long term certainty related to the frequency and duration of the Department of Natural Resources’ decisions to go from in kind taking to in value taking, and vice versa.” That statute expired without an application.
The second version of the bill allowed the commissioner of Revenue to develop terms related both to the state’s timing and notice of taking royalty in kind or in value and to royalty value, but, Eason said, “appears to have limited that authority” by specifying that the state not take royalty in value or in kind for longer than the term of purchase and sale agreements, whereas the proposed in-kind taking is for the term of the contract and “is unrelated to the term of any purchase and sale agreements.”
The producers want greater certainty on whether the state takes in kind or in value. Eason said that concern could be resolved by shifting the point of taking gas in kind “from its currently proposed locations — as far upstream as possible — to a point as far downstream as possible, the AECO Hub in Alberta.”
The state would be responsible for transportation costs to move its gas to Alberta, but “would not, however, have the increased risk and exposure that flows from the capacity management responsibility of the current proposal, nor would it need the expanded bureaucracy and a host of consultants” to manage the capacity of royalty and tax gas sales, he said.
Eason said that another way to address concern about the state switching from taking its gas in kind to in value could be resolved by the state committing to leave its gas in value for the term of the contract.