Areawide leasing on Alaska's North Slope

Abstract

North Slope oil and gas leasing on State lands was expanded significantly with the implementation of ‘areawide’ (AW) leasing in 1998. This paper examines the oil industry's response to AW leasing. Under AW leasing, all unleased State lands within a broadly-defined geographic sale area are offered instead of lands in specific locations nominated by industry. In addition, AW leasing introduced greater frequency and regularity in State oil and gas lease sales, and simplified the lease sale authorization process. Fifteen North Slope and Beaufort Sea AW sales have been held since 1998 out of a grand total of fifty North Slope and Beaufort Sea sales since 1964. While the overall number of bids received per leased tract diminished, the participation of independent oil companies increased markedly under AW leasing, possibly in response to inplied lower effective entry costs. Empirical results suggest that the composition of bidding groups is an important determinant of bidding behavior.

Notes

¹State of Alaska boundaries extend three miles offshore under the federal Submerged Lands Act of 1953 (as per 43 USC §1301–1314). Tracts between 3 and 6 miles offshore are federal tracts. The state shares royalties derived from these federal tracts under provisions of the Outer Continental Shelf Lands Act Amendments of 1978 (Section 8.G) as per 43 USC §1331-1356.

²Of the 50 North Slope and Beaufort Sea lease sales held, records for 47 were available for this study. Beaufort Sea Sale 68 (1992) and North Slope 57 (1993) resulted in zero tracts leased (i.e. no bids received or accepted). Records for five tracts leased in North Slope Sale 86A (1996) are not available.

³Under AS 38.05.180(f) the sliding-scale royalty rate is based on “…the volume of production or other factors…” For example, the sliding-scale royalty rate for leased tracts for Sale 86A (October 1996) is based on the level of oil prices.

⁴The term “winners curse” arose in connection with oil field bidding in the 1950s, to describe the winning bidder's tendency to overpay. See Thaler, 1992.

⁵These fourteen net-profit-share tracts are excluded from the database due to measurement incompatibility with the cash bonus (see table 2, note b for details). The remaining offshore tracts were offered and leased under variable cash bonus and fixed sliding-scale royalty terms.

⁶Under current leasing statutes and regulations, a best-interest finding and determination is required once every ten years, rather than prior to each and every lease sale, as was required under the prior system of leasing with nominated tracts. See Division of Oil and Gas (1997).

⁷Areawide leasing was implemented during a period of depressed global oil prices and fiscal tightening. See Goldsmith (1989).

⁸The five lease sale regions and their designated sale months are: North Slope (October), Beaufort Sea (October), Cook Inlet (May), North Slope Foothills (February), and the Alaska Peninsula (February).

⁹Three-fourths of these fixed royalty leases were set at a 12.5% royalty share; one-fifth was set at 16.67%.

¹⁰Not included are approximately 1800 unleased tracts that were also offered in the 35 North Slope and Beaufort Sea lease sales preceding areawide leasing but for which no competitive bid was forthcoming. Presumably, bids were not received because the tract's expected net present value was non-positive.

¹¹The average high-bid net profit share amount offered for these fourteen excluded tracts is 68%, with a maximum of 93% and a minimum of 22%.

¹²The Alaska Lands Act under Alaska Statutes §38.05.180(i) authorizes the Commissioner of Natural Resources to encourage exploratory drilling on state-owned land under a system of earned credits based upon the footage drilled, geophysical assessment, and the region in which the well is located. A credit may not exceed 50% of the cost of the drilling or geophysical work. Credits may be applied against royalty and rental payments to the state, or taxes payable under AS 43.55. A second program was adopted in 1994, and allows the Commissioner of Natural Resources to grant an EIC for exploratory drilling, the drilling of a stratigraphic test well, and for geophysical work on land in the state, regardless of whether the land is state-owned.

¹³Federal off-shore tracts in Gulf of Mexico, by comparison, are of equal size and distributed uniformly on a grid.

¹⁴Lease sale records held by the Division of Oil and Gas include the physical location of leased tracts, as well as tract-specific information about lease terms, bidding results, and participant identification. These records have been compiled into the database used for this study. See ADNR (2007).

¹⁵The frequency distribution for the number of bids received for nominated versus areawide leasing indicates a greater concentration of uncontested, single-bid leased tracts (87%) under areawide leasing. By comparison, more than 60% of tracts offered and leased under nominated leasing received two or more bids; approximately 7% of leased tracts under nominated leasing received more than five bids; and no leased tracts under areawide leasing received more than five competing bids.

¹⁶The number of contested tracts during the tract nomination system (1965–1997) was 1195 out of a total of 1775 leased tracts (67.3%). The number of contested tracts under areawide leasing was 119 out of 933 leased tracts (12.8%).

¹⁷Production at Prudhoe Bay peaked at 1.6 million barrels per day in 1987; production at the Kuparuk field peaked at 0.3 million barrels per day in 1992 (Division of Oil and Gas 2006: 3-3 to 3-5).

¹⁸Two super major North Slope producers have virtually pulled out of North Slope leasing in recent years.

¹⁹CERA (2001).

²⁰Coiled-tubing and extended reach drilling, and large scale enhanced oil recovery methods were pioneered on the North Slope. Also, the design and scale of well pads and related facilities was scaled down significantly during the 1980s and 1990s. Division of Oil and Gas (1999: Appendix E) and McCarty (2001).

²¹Thomas (2007: 54?55).

²²Independent oil companies have expressed concerns about facility access asymmetries and other potential entry barriers in Kaltenbach et al. (2004).

²³In 1976 the federal government banned the seven largest petroleum companies from consortium bidding for OCS leases. In general, joint bidding is permitted on federal OCS and Alaska State lands.

²⁴Lease Sale 43 in 1984. The winning bid was $27,892 or $13.23 per acre.

²⁵Also see Tremblay (1995).

²⁶The oil and gas industry experienced significant consolidation beginning with the BP's acquisition of Amoco in December 1998. Much of this consolidation was driven initially by the oil price collapse of 1998?1999, which resulted in undervaluation of assets and reserves. This wave of consolidation could also affect the make up of bidding consortia. Other recent examples of M&A activity involving companies with interests in Alaska include:

• Exxon and Mobil combined in November 1999;

• BP acquisition of ARCO in April 2000;

• Alberta Energy Company and PanCanadian Energy merged to become Encana in April 2002;

• Phillips Petroleum and Conoco merged in August 2002;

• Chevron and Texaco combined in October 2002;

• Pioneer Natural Resources acquired Evergreen Resources in September 2004;

• ChevronTexaco acquired Unocal in August 2005;

• ConocoPhillips acquired Burlington Resources in March 2006;

• Anadarko acquired Kerr-McGee in August 2006.

²⁷Major producers include integrated oil companies with more than a billion barrels of oil equivalent in petroleum reserves worldwide. The ‘independent’ producer is engaged in petroleum extraction but not in the transportation, refining, or marketing of petroleum products. Independents receive all revenues from production at the wellhead and include non-integrated, large producers (with assets exceeding $500 million) and small producers (assets less than $500 million). See Pulsipher et al. (1998) and EIA (1995).

²⁸They are (1) Anadarko Petroleum Corp: Jacobs ladder Unit and Colville River Unit (minor working interest owner with ConocoPhillips Alaska, Inc.); (2) Pioneer Natural Resources Alaska, Inc: Oooguruk Unit (in partnership with ENI US Operating Co., Inc.), Cronus Unit (in partnership with AVCG, LLC), and NE Storms Unit (with ConocoPhillips); (3) Kerr McGee: Nikiatchuk, (recently acquired by ENI); (4) James A. White: Arctic Fortitude Unit; and (5) FEX: in National Petroleum Reserve ? Alaska (NPR-A).

²⁹The cost structure and risk profile of independent producers may differ from the majors, as well as the national oil companies. This may help to explain the general industry-wide trend of greater independent oil company investment in the later stage of the basin's life cycle after the mega fields achieve peak production. See EIA (1995), Pulsipher (1995) and Wadood (2006).

³⁰The Common Value model, as distinct from the Independent Private Values model, is based on the notion that the object offered for sale has common but unknown true value. As the number of bidders’ increases, the ‘pure’ Common value strategy suggests that firms lower bids to avoid winner's curse.

³¹Under the presumption of a recursive system, estimation of a follow-on, second equation for the winning bid is unnecessary and, therefore, not undertaken here.

³²Under the first-price, sealed-bid auction system used to lease state lands, the bids received for a given tract are unknown (hence, quasi). The minimum bid varies from zero to $10 per acre.

³³The inflation adjustment is based on the US Bureau of Labor Statistics, producer price index for industrial commodities (BLS 2007).

³⁴A 36-month moving average is substituted to remove the irregular component and smooth the OILPRICE time series to better represent company expectations regarding the cyclical nature of oil markets.

³⁵The composition of TAPS ownership is: BP Amoco (46.9263%), ConocoPhillips (28.2953%), ExxonMobil (20.3378%), Koch Alaska Pipeline Co. LLC (3.0845%), Chevron (1.3561%). Source: Division of Oil and Gas, special tabulations, Alaska DNR (2007).

³⁶Note: a binary variable for net profit share tracts is excluded because tracts leased under NPS bidding are excluded from this database. (See table 2: note a.)

³⁷Over the 42-year period of North Slope leasing, the average size of joint bidding consortiums declined from 1.93 pre-Areawide to 1.45 post-Areawide. This suggests that other factors coincident with but not directly related to Areawide leasing are captured in the model. Further model specification considerations may be in order to isolate the effects of changing industry structure and of basin development from the effects of Areawide leasing.