LEGAL DEVELOPMENTS IN 2006 AFFECTING THE OIL AND GAS EXPLORATION AND PRODUCTION INDUSTRY
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Crowe & Dunlevy
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Oklahoma City, Oklahoma
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Each year, a variety of legal developments occur in the major oil and gas-producing states that affect those involved in the business of exploring for and producing oil and natural gas. This paper will summarize the key legal developments that occurred during 2006 (and the latter part of 2005) in the states indicated below. In an effort to use the limited amount of space available for this article in a way that will maximize the number of developments covered in this report, the case and development summaries below include a reduced number of footnotes and citations to quotes from the applicable cases and other authorities.
I. ALASKA
A. Legislative Developments
President Bush is considering whether to rescind the "Executive OCS Leasing Withdrawal" applicable to federal waters off Alaska's Bristol
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Bay.2 For years, a Congressional moratorium has prohibited offshore oil and gas development in this region of the nation's Outer Continental Shelf.3 The Congressional moratorium was lifted in fiscal year 2004,4 but the Presidential action remains in effect.
In 2006 TSSLA ch. 34, the Legislature repealed Alaska's former oil production (severance) tax5 and gas production tax6 and replaced them with a net profits tax on oil and gas, referred to as the Petroleum Production Tax ("PPT").7 The former production taxes were based on a percentage of gross value of production.8 The new PPT is based on a percentage of the net profits yielded from production.9 The new PPT includes tax benefits for additional capital investment by producers in hydrocarbon production infrastructure.10 These tax benefits transfer a significant portion of the cost of development to the State of Alaska.11
Under Alaska's former oil and gas production taxes, the amount of tax due the state was computed by taking the greater of an amount per unit volume (bbl or mcf) or a percentage of value and multiplying that figure by an economic limit factor ("ELF").12 The value of the oil or gas for most tax purposes was computed using a net-back method.13 Transportation charges were subtracted from the delivery price to arrive at the field price on which the tax was based.14 The ELF was an adjustment to the nominal tax rate to adjust for the productivity of a particular field.15 The ELF allowed for lower or no severance tax on smaller fields and higher severance tax on larger fields.16
In 2006 the Alaska Department of Revenue identified what it considered to be several shortcomings with the former tax system, i.e., that it did not provide an incentive for oil and gas companies to reinvest in
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Alaska, that the tax was outdated when compared to other countries with progressive production taxes which were seeing huge cash influxes at the then sky-high oil prices, and that the maturing North Slope fields were seeing less and less production resulting in declining tax revenue.17 To address these concerns, and to facilitate a natural gas pipeline contract, Alaska Governor Frank Murkowski's administration proposed the adoption of what ultimately became the new PPT.
The PPT did away with separate severance taxes for each Alaska oil and gas field, and replaced them with one combined tax based on a producer's net profits from all of its production of oil and gas in Alaska.18 The PPT rate is equal to the greater of either (a) 22.5% of the production tax value of the taxable oil and gas plus an additional variable amount of up to 25% depending on the price of oil, or (b) the minimum tax provided for under AS 43.55.011(f).19 A producer's total tax liability is based on the combined production of all oil and gas produced from each lease or property in the state, less any oil and gas that is exempt from taxation or which constitutes a landowner's royalty interest.20 The PPT contains special provisions which will allow Cook Inlet oil and gas production to continue to pay at the same severance tax rate as the prior ELF based system for the next 15 years.21
After several years of negotiations, Governor Murkowski presented the Alaska legislature with a proposed Fiscal Contract,22 which had been negotiated pursuant to the Alaska Stranded Gas Development Act ("SGDA"),23 in an effort to provide the fiscal certainty necessary to allow the construction of a massive (over $20 billion construction cost, 4.5 BCF per day) natural gas pipeline from Alaska's North Slope through Canada to Chicago. Because of concerns that this Fiscal Contract might have included provisions which were beyond the existing authority in the SGDA, various amendments were proposed and subjected to extensive hearings before the Alaska legislature over three, one month long, Special Sessions.24 But the amendments never were enacted, and Governor Murkowski was not re-elected. Alaska's new governor, Sarah Palin, has
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publicly stated that her administration intends to consider all proposals for the transportation of gas from Alaska's North Slope.25
In Legislative Resolve 29, the Alaska legislature recognized the growing natural gas demand by residents and businesses in Southcentral Alaska and announced its support for the construction of a natural gas spur pipeline between Fairbanks (through which a gas line from the North Slope would pass) and the Nenana Basin and Southcentral Alaska.26
B. Judicial Developments
In National Audubon Society v. Kempthorne,27 ("NPA Decision") the United States District Court for the District of Alaska considered the final United States Department of the Interior ("DOI") Environmental Impact Statement ("EIS") for leasing in the Northeast Planning Area ("NPA") of the National Petroleum Reserve-Alaska ("NPRA").28
In a prior case, the same court upheld the decision of the DOI to lease portions of the Northwest Planning Area ("NWPA").29 The NPA Decision enjoins oil and gas leasing in the NPA because the NPA EIS lacks an analysis of the cumulative impacts of oil and gas development in the NPA and the NWPA.30
In Allen v. Alaska Oil and Gas Conservation Commission,31 Allen was the owner of an overriding royalty interest in several leases that were located near Alaska's most productive gas field -- the North Cook Inlet Unit (NCIU). The leases were in danger of automatically terminating as no oil or gas had been produced from them. Allen petitioned the Alaska Oil and Gas Conservation Commission ("Commission") for a unitization order combining his leases into the NCIU and thus entitling him to a share of royalties from the NCIU. The Commission denied the petition. The Commission found, among other things, that the leases did not contain any portion of the productive reservoir of the NCIU, that unitization would not advance the management of NCIU reservoirs, and that "[n]one of the
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statutory requirements" for compulsory unitization had been met.32 Allen appealed the Commission's decision to the Superior Court and sought a trial de novo. The Superior Court denied the trial de novo request and affirmed. Allen then appealed to the Alaska Supreme Court.
The appeal raised three main questions: (1) Was the owner entitled to a trial de novo as provided in AS 31.05.080; (2) did the Commission apply the proper statutory standard to the unitization petition; and (3) did the Commission breach any statutory duty.33 The court held that the owner was not entitled to a trial de novo,34 that the Commission applied the proper statutory standard to the petition,35 that the Commission's factual findings were supported by substantial evidence,36 and that the Commission did not breach any statutory duty to the owner.37
C. Administrative Developments
In 2006, the Federal Energy Regulatory Commission ("FERC") submitted to Congress the first reports describing the progress made in licensing and constructing an Alaska natural gas pipeline pursuant to section 1810 of the Energy Policy Act of 2005.38
The first report identifies three potential projects being considered for bringing Alaskan natural gas from Alaska's North Slope to the Lower 48 states.39 The report describes the progress made in advancing each of the projects, including actions taken by the project sponsors, the FERC, and other federal and state entities, and potential impediments to each of the projects.40
The second report discusses several events: An agreement on components of a draft contract between the State of Alaska and the Producer Group; the execution of the Federal Agency Memorandum of Understanding among 15 federal departments and agencies, which establishes a cooperative project management framework for the approval of an Alaska natural gas pipeline; and the nomination of a Federal
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Coordinator for Alaska Natural Gas Transportation Projects.41 It also addresses the fact that the United States energy market is moving forward to make arrangements to obtain adequate natural gas supplies to satisfy future demand through the development of infrastructure to support liquefied natural gas projects.42
On November 27, 2006, the Alaska Department of Natural Resources ("DNR") Commissioner ruled that the Point Thomson Unit ("PTU"), an 8 TCF gas field on Alaska's North Slope, was terminated ("Commissioner's Decision").43 This was the final decision stemming from the appeal of an October 27, 2005 decision of the Director of the Alaska Division of Oil and Gas ("Director's Decision") rejecting the 22nd Plan of Development ("POD") for the PTU submitted by the PTU operator, ExxonMobil Corporation ("ExxonMobil"), and placing the PTU in default for failure to submit an acceptable plan of development.44
Effective October 1, 2005, the Director...
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