HOME PAGE SUBSCRIPTIONS, Print Editions, Newsletter PRODUCTS READ THE PETROLEUM NEWS ARCHIVE! ADVERTISING INFORMATION EVENTS PAY HERE

Providing coverage of Alaska and northern Canada's oil and gas industry
August 2006

Vol. 11, No. 32 Week of August 06, 2006

Gas pipeline contract 'not ripe'

Alaska Sen. Gene Therriault, chair of LB&A, says gas fiscal deal negotiated by governor with North Slope producers needs work

By Kristen Nelson

Petroleum News

Sen. Gene Therriault, R-North Pole, believes that the draft gas fiscal contract negotiated by Alaska Gov. Frank Murkowski’s administration with BP, ConocoPhillips and ExxonMobil “is not yet ripe for consideration or execution.”

Therriault, who is chairman of the Alaska Legislature’s Joint Legislative Budget and Audit Committee, said he compiled the July 24 comments on the gas fiscal contract based on reports and presentations made by consultants retained by LB&A (Don Shepler and Philip Gildan of Greenberg Traurig; Barry Pulliam, Tony Finizza, Jeffrey Leitzinger and Rick Harper of Econ One Research; Daniel Johnston; Jim Eason; and Jim Barnes of Barnes & Cascio), but said the conclusions and recommendations are his own.

Those conclusions and recommendations come from a legislator who has probably been as involved as anyone outside the administration and the producers in working the issues involved in commercializing Alaska North Slope gas.

Therriault said the contract “fails to address critical issues and represents an unbalanced set of commitments and obligations among the parties,” with the state on the losing end of the deal.

While the state provides considerations to the producers in the contract, what the producers offer the state “lacks certainty and substance.” The state provides fiscal surety, he said, but the producers’ commitments do not provide assurances to the state that the contract will result in a gas pipeline.

“The overarching problem with the contract is that it is not an agreement to develop the stranded gas resources of Alaska. Rather, it is an agreement to study development, with no commitments to construct a pipeline or commit to ship gas on the pipeline.”

Material terms unknown

Therriault provided two lists of items he said were required before the contract would be ready for consideration.

“A contract requires the parties’ agreement on all material terms, or the contract is null and nothing more than an unenforceable agreement to agree,” he said.

The draft contract leaves too many “material terms” unknown, specifically: the limited liability agreement for the mainline entity; the Canada entity agreement; coordination agreements between entities; parent company guarantees of affiliates’ obligations and performance; plan for obtaining Canadian regulatory approvals and coordination of those approvals with the mainline project; commitments by the producers to submit for sufficient shipping capacity in the pipeline to obtain project sanction; a marketing entity for the state’s gas; a pricing policy for in-state deliveries of state gas; and off-take rates for Prudhoe Bay and Point Thomson approved by the Alaska Oil and Gas Conservation Commission.

Therriault also said the contract relies on future negotiation and agreement on other essential agreements: those creating the Alaska project entities and the various state entities; governance agreements controlling relationships among interest holders; operating agreements of each Alaska project entity; the agreement with a Canadian entity creating the Alaska to Alberta entity and governance agreements; agreements coordinating operations between and among the Alaska and Canadian project entities; ship-or-pay and marketing arrangements for the state’s gas; investment obligations and financing arrangements for project and state entities; and undertakings by the state and the parent companies of the producers concerning financial performance guarantees for the subsidiaries and coordination of the U.S. and Canadian regulatory processes.

These unknowns are relevant, he said, because without them it isn’t possible to determine whether the project plan can be implemented and meet the requirements of the Alaska Stranded Gas Development Act and they are needed to understand how the project will be implemented, including understanding the rights and obligations the state would have with respect to the project.

That the state and producers are having “apparent difficulty” in finalizing the draft of the entity agreement for the mainline project, and were not able to submit a draft with the contract, “underscores the material importance of the terms and conditions” of the mainline entity agreements, Therriault said, “and the lack of ripeness” in considering the contract without the agreements in place.

Contract term

Therriault said locking in contract terms for at least 35 years after commercial operations begin is another issue. “Presentations made during the public hearings and roundtable discussions suggested that once the gas pipeline is placed in operation, the need for fiscal certainty will evaporate,” he said. He called locking in taxes and regulatory matters “antithetical to our form of representative government,” and said fiscal regimes in the 30 member countries of the Organization for Economic Co-Operation and Development “do not grant stability in any form.”

He noted that the Stranded Gas Development Act “precluded consideration of oil taxes and concessions” in the contract, and said that while modernizing the state’s oil tax regime should be given fair consideration on its own, “no convincing argument has been raised to tie such modernization to development of a gas pipeline under the SGDA.”

He said nowhere else in the world has such “retroactive” stability on existing production been granted. “In fact, Dr. Pedro van Meurs stated in a memo dated July 19, 2005, that he knows of no other case where fiscal stability was granted to petroleum that was external to the contract.”

Therriault disagreed with the argument that the state would use dissatisfaction with the gas fiscal bargain to raise taxes on oil: he said that claim “fails economic logic. Higher oil taxes will discourage development of new oil reserves and, therefore, the associated gas reserves that are needed to fill the gas pipeline in the out years,” and asked why the state would raise taxes “on a nearly depleted set of fields in such a way that it would prevent badly needed investment to bring in badly needed reserves?”

Leases shouldn’t be locked in

Therriault said oil and gas leases and properties included in the contract become immune to state regulation and the contract does not require that the producers do anything to those leases, “no production commitments, no investment commitments, no commitments at all,” and said the contract should be limited to leases and properties “necessary to secure gas supplies to meet shipping commitments on the initial capacity of the pipeline.” The contract includes all oil and gas leases held by the producers on the North Slope.

He singles Point Thomson out as a particular problem, saying that until the Alaska Oil and Gas Conservation Commission determines whether gas cycling at Point Thomson (production of liquids from the condensate field and re-injection of the natural gas) is necessary to maximize hydrocarbon recovery, commitment of Point Thomson gas to the project “is premature.”

On the regulatory side: “The SGDA does not appear to contemplate that any right or privilege of any Participant in any lease, agreement, regulation, rule, order, or decree would be modified to conform to a Fiscal Contract. Nonetheless the Contract contemplates that the rights and privileges of the State would be modified to a disturbing degree.” And because of the very broad scope of the fiscal contract, and its reference to so many leases and 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 effect of the many measures in the contract that “suppress the State’s regulatory regime as it pertains to the Project and the properties and activities of Participants for the duration” of the contract “cannot be accurately predicted” but “would likely be pervasive and chilling,” he said.

Is gas stranded?

Therriault said the commissioner of Revenue’s finding that Alaska North Slope gas is stranded “relies on serious factual errors, incorrect understanding of shipping commitments and unfounded fears regarding the purported threat posed by LNG.”

He said the analyses of costs of delivering LNG to the United States, and the cost of getting ANS gas to market, “rely on a set of erroneous assumptions.”

Costs of transporting LNG from Qatar are pegged at $1.25 per million Btu, but Therriault said that is only the cost for shipping: liquefaction is 80 cents; regasification is 40 cents; and access to the pipeline system is 10 cents. “All told, LNG transportation costs from Qatar to the United States amount to approximately $2.50. Including the other associated costs of production and returns for the exporter, the landed cost of LNG is closer to $3.25” in 2005 dollars.

ANS costs are based on a project to Chicago, resulting in a tariff of approximately $2.20 per million Btu. But, Therriault said, “it is unlikely that new pipeline construction will extend much beyond the AECO hub in Alberta and very likely won’t go past Gordondale,” and is likely to be delivered “via takeaway capacity from AECO to the Midwest, West Coast and East Coast.”

The finding assumes Chicago because firm transportation commitments would be required to move gas to Chicago, and the finding said those firm transportation commitments would have to be capitalized.

“However, capitalization of a future expenditure does not translate such future costs into current cost of shipping,” Therriault said. “There is no outflow of cash that occurs when an FT commitment is made and no accelerated cost that would be reflected in a transportation cost analysis. Further, debt-rating agencies don’t treat it as an accelerated transportation cost.”

Therriault said evidence in the finding does not support an assumption “that capitalizing FT commitments to move gas from Alberta to Chicago increases transportation costs as between ANS gas and LNG gas.”

If, however, the line were built to Chicago the tariff would be $2.20 per million Btu, “in nominal dollars averaged over 40 years.” In 2005 dollars, he said, the average transportation cost is closer to $1.20 per million Btu.

“Put on an apples-to-apples comparison, no demonstration was made that transportation costs are a barrier to ANS gas reaching the market.”

Therriault said ANS gas has not been developed “because no party has yet constructed the transportation infrastructure necessary to deliver ANS gas to market.” Market dynamics were “significantly different” when the stranded gas act was enacted than they are now, he said.

The principal reason ANS gas has not been brought to market is “because until now its higher and better use has been to be reinjected to optimize oil production,” but that appears to have changed, he said, along with an increasing demand for gas, decline in domestic production and a rise in the price paid for natural gas.

Therriault recommends substantial changes to the contract.






Petroleum News - Phone: 1-907 522-9469
[email protected] --- https://www.petroleumnews.com ---
S U B S C R I B E

Copyright Petroleum Newspapers of Alaska, LLC (Petroleum News)(PNA)Š1999-2019 All rights reserved. The content of this article and website may not be copied, replaced, distributed, published, displayed or transferred in any form or by any means except with the prior written permission of Petroleum Newspapers of Alaska, LLC (Petroleum News)(PNA). Copyright infringement is a violation of federal law.