The transportation of oil in common carrier pipelines is also subject to rate regulation. The Federal Energy Regulatory Commission, or the FERC, regulates interstate oil pipeline transportation rates under the Interstate Commerce Act. In general, interstate oil pipeline rates must be cost-based, although settlement rates agreed to by all shippers are permitted and market-based rates may be permitted in certain circumstances. Effective January 1, 1995, the FERC implemented regulations establishing an indexing system (based on inflation) for transportation rates for oil that allowed for an increase or decrease in the cost of transporting oil to the purchaser. A review of these regulations by the FERC in 2000 was successfully challenged on appeal by an association of oil pipelines. On remand, the FERC in February 2003 increased the index slightly, effective July 2001. Intrastate oil pipeline transportation rates are subject to regulation by state regulatory commissions. The basis for intrastate oil pipeline regulation, and the degree of regulatory oversight and scrutiny given to intrastate oil pipeline rates, varies from state to state.

Historically, the transportation and sale for resale of natural gas in interstate commerce have been regulated pursuant to the Natural Gas Act of 1938, the Natural Gas Policy Act of 1978 and regulations issued under those Acts by the FERC. In the past, the federal government has regulated the prices at which natural gas could be sold. While sales by producers of natural gas can currently be made at uncontrolled market prices, Congress could reenact price controls in the future. Deregulation of wellhead natural gas sales began with the enactment of the Natural Gas Policy Act. In 1989, Congress enacted the Natural Gas Wellhead Decontrol Act which removed all Natural Gas Act and Natural Gas Policy Act price and non-price controls affecting wellhead sales of natural gas effective January 1, 1993.

The production of oil and natural gas is subject to regulation under a wide range of local, state and federal statutes, rules, orders and regulations. Federal, state and local statutes and regulations require permits for drilling operations, drilling bonds and reports concerning operations.

The eight units comprising the Red River units are located along the Cedar Hills Anticline in North Dakota, South Dakota and Montana and produce oil and natural gas from the Red River “B” formation, a thin, continuous, dolomite formation at depths of 8,000 to 9,500 feet. The Bakken formation is widespread and relatively uniform in development throughout the Montana and North Dakota portions of the Williston Basin. The Bakken formation consists of three lithologic members—the upper shale, middle member and locally a lower shale.

The Company’s principal property in the Big Horn Basin, the Worland field, produces primarily from the Phosphoria formation. The Company has 44 additional proved undeveloped drilling locations in the Worland field. As of December 31, 2005, the Company owned approximately 109,000 gross (28,000 net) undeveloped acres in the Washakie Basin in Carbon and Sweetwater Counties, Wyoming. The Company’s objective is the Lewis Shale, a shale formation up to 1,500 feet thick with thin interbedded and discontinuous siltstones and sandstones.

The Company’s principal producing properties in the Mid-Continent region are located in the Anadarko Shelf of western Oklahoma and the Illinois Basin. The Company has also acquired acreage in three unconventional resource plays: the Woodford Shale, New Albany Shale and Floyd Shale.

The Company’s wells within the Anadarko Basin produce from a variety of sands and carbonates in both stratigraphic and structural traps. The Company’s wells within the Illinois Basin produce primarily crude oil from units comprised of shallow sand formations under water injection.

During the three months ended December 31, 2005, the Company’s average production from the Gulf Coast properties was 91 net Bbls of oil and 5,293 net Mcf of natural gas per day. The Company’s principal producing properties in this region are located in South Texas and Louisiana.

Exploration expense decreased from 2004 to 2005 as a result of a reduction primarily in dry hole expense from $9.5 million in 2004 to $1.4 million for the year ended December 31, 2005.

The depreciation, depletion and amortization (DD&A) rate per Boe decreased from $7.02 per Boe for the year ended December 31, 2004 to $6.50 per Boe for the year ended December 31, 2005.

The Company recorded a $6.2 million impairment for the year ended December 31, 2004 compared to a $2.5 million impairment for the year ended December 31, 2005 on producing properties.

Interest expense declined from $23.6 million for the year ended December 31, 2004 to $14.2 million for the year ended December 31, 2005.