UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-K

(Mark One)

For the fiscal year ended December 31, 20072008

OR

For the transition period from              to            

Commission File Number: 001-32886

CONTINENTAL RESOURCES, INC.

(Exact name of registrant as specified in its charter)

Registrant’s telephone number, including area code: (580) 233-8955

Securities registered under Section 12(b) of the Exchange Act:

Securities registered under Section 12(g) of the Exchange Act: None

Indicate by check mark if registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.    Yes  ¨x    No  x¨

Indicate by check mark if registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act.    Yes  ¨    No  x

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15 (d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.    Yes  x    No  ¨

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K.  ¨

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer or a smaller reporting company. See definition of “accelerated filer”, “large accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act.

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).    Yes  ¨    No  x

State the aggregate market value of the voting and non-voting common equity held by non-affiliates computed by reference to the price at which the common equity was last sold, or the average bid and asked prices of such common equity, as of the last business day of the registrant’s most recently completed second fiscal quarter. As of June 30, 20072008 aggregate market value was $713,522,464.$3,138,228,490.

As of February 29, 2008,23, 2009, the registrant had 169,073,371169,556,833 shares of common stock outstanding.

DOCUMENTS INCORPORATED BY REFERENCE

Portions of the definitive Proxy Statement of Continental Resources, Inc. for the Annual Meeting of Stockholders to be held May 27, 2008,28, 2009, which will be filed with the Commission no later than April 29, 200830, 2009 are incorporated by reference into Part III of this Form 10-K.

Table of Contents

Glossary of Oil and Natural Gas Terms

The terms defined in this section are used throughout this report:

“AMI.” Area of mutual interest.

“Bbl.” One stock tank barrel, of 42 U.S. gallons liquid volume, used herein in reference to crude oil, condensate or natural gas liquids.

“Bcf.” One billion cubic feet of natural gas.

“Bcfe.” One billion cubic feet of natural gas equivalent with one barrel of oil converted to six thousand cubic feet of natural gas.

“Boe.” Barrels of oil equivalent, with six thousand cubic feet of natural gas being equivalent to one barrel of oil.

“Basin.” A large natural depression on the earth’s surface in which sediments generally brought by water accumulate.

“Completion.” The process of treating a drilled well followed by the installation of permanent equipment for the production of natural gas or oil, or in the case of a dry hole, the reporting of abandonment to the appropriate agency.

“DD&A.” Depreciation, depletion, amortization and accretion.

“Developed acreage.acreage.” The number of acres that are allocated or assignable to productive wells or wells capable of production.

“Development well.well.” A well drilled within the proved area of aan oil or natural gas or oil reservoir to the depth of a stratigraphic horizon known to be productive.

“Dry hole.hole.” A well found to be incapable of producing hydrocarbons in sufficient quantities such that proceeds from the sale of such production exceed production expenses and taxes.

“Enhanced recovery.” The recovery of oil and natural gas through the injection of liquids or gases into the reservoir, supplementing its natural energy. Enhanced recovery methods are often applied when production slows due to depletion of the natural pressure.

“Exploratory well.well.” A well drilled to find and produce natural gas or oil reserves not classified as proved, to find a new reservoir in a field previously found to be productive of natural gas or oil in another reservoir or to extend a known reservoir.

“Field.” An area consisting of a single reservoir or multiple reservoirs all grouped on, or related to, the same individual geological structural feature or stratigraphic condition. The field name refers to the surface area, although it may refer to both the surface and the underground productive formations.

“Formation.” A layer of rock which has distinct characteristics that differdiffers from nearby rock.

“Horizontal drilling.” A drilling technique used in certain formations where a well is drilled vertically to a certain depth and then drilled at a right angle within a specified interval.

“HPAI.” High pressure air injection.

“Infill wells.” Wells drilled into the same pool as known producing wells so that oil or natural gas does not have to travel as far through the formation.

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“MBbl.” One thousand barrels of crude oil, condensate or natural gas liquids.

“Mcf.” One thousand cubic feet of natural gas.

“MBoe.” One thousand Boe.

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“MMBoe.” One million Boe.

“MMBtu.” One million British thermal units.

“MMcf.” One million cubic feet of natural gas.

“NYMEX.” The New York Mercantile Exchange.

“Net acres.” The percentage of total acres an owner has out of a particular number of acres, or a specified tract. An owner who has 50% interest in 100 acres owns 50 net acres.

“PUD.PUD.” Proved undevelopedundeveloped.

“PV-10.” When used with respect to oil and natural gas reserves, PV-10 means the estimated future gross revenue to be generated from the production of proved reserves, net of estimated production and future development and abandonment costs, using prices and costs in effect at the determination date, before income taxes, and without giving effect to non-property-related expenses, discounted to a present value using an annual discount rate of 10% in accordance with the guidelines of the SEC. PV-10 is not a non-GAAP financial measure.measure calculated in accordance with generally accepted accounting principles (“GAAP”) and generally differs from Standardized Measure, the most directly comparable GAAP financial measure, because it does not include the effects of income taxes on future net revenues. Neither PV-10 nor Standardized Measure represents an estimate of the fair market value of our oil and gas properties. We and others in the industry use PV-10 as a measure to compare the relative size and value of proved reserves held by companies without regard to the specific tax characteristics of such entities.

“Productive well.well.” A well that is found to be capable of producing hydrocarbons in sufficient quantities such that proceeds from the sale of the production exceed production expenses and taxes.

“Proved developed reserves.reserves.” Reserves that can be expected to be recovered through existing wells with existing equipment and operating methods.

“Proved reserves.reserves.” The estimated quantities of oil, natural gas and natural gas liquids which geological and engineering data demonstrate with reasonable certainty to be commercially recoverable in future years from known reservoirs under existing economic and operating conditions.

““Proved undeveloped reserves (PUD) (“PUD”).” Proved reserves that are expected to be recovered from new wells on undrilled acreage or from existing wells where a relatively major expenditure is required for recompletion.

““Reservoir.Reservoir.” A porous and permeable underground formation containing a natural accumulation of producible oil and/or natural gas and/or oil that is confined by impermeable rock or water barriers and is separate from other reservoirs.

“Simul-Frac.” Simultaneously fracture treating two or more wells within the same fracture plane in order to create pressure interference between the wells and thereby increasing the stimulated reservoir volume.

“Spacing.” The distance between wells producing from the same reservoir. Spacing is often expressed in terms of acres, e.g., 40-acre spacing, and is often established by regulatory agencies.

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“Standardized Measure.” Discounted future net cash flows estimated by applying year-end prices to the estimated future production of year-end proved reserves. Future cash inflows are reduced by estimated future production and development costs based on period-end costs to determine pre-tax cash inflows. Future income taxes, if applicable, are computed by applying the statutory tax rate to the excess of pre-tax cash inflows over our tax basis in the oil and gas properties. Future net cash inflows after income taxes are discounted using a 10% annual discount rate.

“Unit.” The joining of all or substantially all interests in a reservoir or field, rather than a single tract, to provide for development and operation without regard to separate property interests. Also, the area covered by a unitization agreement.

“Waterflood.” The injection of water into an oil reservoir to “push” additional oil out of the reservoir rock and into the wellbores of producing wells. Typically an enhanced recovery process.

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“Wellbore.” The hole drilled by the bit that is equipped for oil or gas production on a completed well. Also called well or borehole.

“Working interest.” The right granted to the lessee of a property to explore for and to produce and own oil, gas, or other minerals. The working interest owners bear the exploration, development, and operating costs on either a cash, penalty, or carried basis.

Cautionary Statement Regarding Forward-Looking Statements

This report contains “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934, as amended. These forward-looking statements that are subject to a number of risks and uncertainties, many of which are beyond our control. All statements, other than statements of historical fact included in this report, regarding our strategy, future operations, financial position, estimated revenues and losses, projected costs, prospects, plans and objectives of management are forward-looking statements. When used in this report, the words “could,” “believe,” “anticipate,” “intend,” “estimate,” “expect,” “project” and similar expressions are intended to identify forward-looking statements, although not all forward-looking statements contain such identifying words. Except as otherwise specifically indicated, these statements assume no significant changes will occur in the operating environment for oil and natural gas properties and thethat there will be no material acquisitions, divestitures or financings except as otherwise described.

Forward-looking statements may include statements about our:

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All forward-looking statements speak only as of the date of this report. You should not place undue reliance on these forward-looking statements. Although we believe that our plans, intentions and expectations reflected in or suggested by the forward-looking statements we make in this report are reasonable, we can give no assurance that these plans, intentions or expectations will be achieved. We disclose important factors that could cause our actual results to differ materially from our expectations under “Item 1A.—Risk Factors” and “Item 7.—Management’s Discussion and Analysis of Financial Condition and Results of Operation” and elsewhere in this report. These cautionary statements qualify all forward-looking statements attributable to us or persons acting on our behalf.

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Part I

You should read this entire report carefully, including “Risk Factors” and our historical consolidated financial statements and the notes to those historical consolidated financial statements included elsewhere in this report. Unless the context otherwise requires, references in this report to “Continental Resources,” “we,” us,” “our,” “ours” or “company”“ours” refer to Continental Resources, Inc., and its subsidiary.

General

We are an independent oil and natural gas exploration and production company with operations in the Rocky Mountain, Mid-Continent and Gulf Coast regions of the United States. We were originally formed in 1967 to explore, develop and produce oil and natural gas properties. Through 1993, our activities and growth remained focused primarily in Oklahoma. In 1993, we expanded our activity into the Rocky Mountain and Gulf Coast regions. Approximately 82%70% of our estimated proved reserves as of December 31, 20072008 are located in the Rocky Mountain region. We completed an initial public offering of our common stock on May 14, 2007, and our common stock began trading on the New York Stock Exchange on May 15, 2007 under the ticker symbol “CLR”.

We focus our exploration activities in large new or developing plays that provide us the opportunity to acquire undeveloped acreage positions for future drilling operations. We have been successful in targeting large repeatable resource plays where horizontal drilling, advanced fracture stimulation and enhanced recovery technologies provide the means to economically develop and produce oil and natural gas reserves from unconventional formations. As a result of these efforts, we have grown substantially through the drillbit, adding 89.0121.7 MMBoe of proved oil and natural gas reserves through extensions and discoveries from January 1, 20032004 through December 31, 20072008 compared to 0.93.1 MMBoe added through proved reserve purchases during that same period.

As of December 31, 2007,2008, our estimated proved reserves were 134.6159.3 MMBoe, with estimated proved developed reserves of 101.2106.0 MMBoe, or 75%67% of our total estimated proved reserves. Crude oil comprised 77%67% of our total estimated proved reserves. For the year ended December 31, 2007,2008, we generated revenues of $582.2$960.5 million and operating cash flows of $390.6$719.9 million. For the year and quarter ended December 31, 2007,2008, daily production averaged 29,09932,803 and 30,36936,018 Boe per day, respectively. This represents growth of 18%13% and 15%19% as compared to the year and quarter ended December 31, 2006,2007, when daily production averaged 24,70629,099 Boe and 26,503,30,369 Boe, respectively.

The following table summarizes our total estimated proved reserves, PV-10 and net producing wells as of December 31, 2007,2008, average daily production for the three months ended December 31, 20072008 and the reserve-to-production index in our principal regions. Our reserve estimates as of December 31, 20072008 are based primarily on a reserve report prepared by Ryder Scott Company, L.P., our independent reserve engineers. In preparing its report, Ryder Scott Company, L.P. evaluated properties representing approximately 85%83% of our PV-10. Our technical staff evaluated properties representing the remaining 15%17% of our PV-10.

The following table provides additional information regarding our key development areas:

Our Business Strategy

Our goal is to increase shareholder value by finding and developing crude oil and natural gas reserves at costs that provide an attractive rate of return on our investment. The principal elements of our business strategy are:

Focus on Oil.During the late 1980’s we began to believe that the valuation potential for crude oil exceeded that of natural gas. Accordingly, we began to shift our reserve and production profiles towards crude oil. As of December 31, 2007,2008, crude oil comprises 77%67% of our total proved reserves and 82%76% of our 20072008 annual production. Although we do pursue natural gas opportunities, we continue to believe that crude oil valuations will remainbe superior to natural gas valuations on a relative Btu basis.

Growth Through Low-Cost Drilling. Substantially all of our annual capital expenditures are invested in drilling projects and acreage and seismic acquisitions. From January 1, 20032004 through December 31, 2007,2008, proved oil and natural gas reserve additions through extensions and discoveries were 89.0121.7 MMBoe compared to 0.93.1 MMBoe of proved reserve purchases.

Internally Generate Prospects. Our technical staff has internally generated substantially all of the opportunities for the investment of our capital. As an early entrant in new or emerging plays, we expect to acquire undeveloped acreage at a lower cost than those of later entrants into a developing play.

Focus on Unconventional Oil and Natural Gas Resource Plays. Our experience with horizontal drilling, advanced fracture stimulation and enhanced recovery technologies allows us to commercially develop unconventional oil and natural gas resource plays, such as the Red River B dolomite, Bakken Shale and Arkoma Woodford formations. Production rates in the Red River units also have been increased through the use of enhanced recovery technology. Our production from the Red River units, the Bakken field, and the Arkoma Woodford comprised approximately 8,3109,302 MBoe, or 78%77% of our total oil and natural gas production during the year ended December 31, 2007.2008.

Acquire Significant Acreage Positions in New or Developing Plays. In addition to the 465,207513,003 net undeveloped acres held in the Montana and North Dakota Bakken shale and Arkoma Woodford fields, we held 171,475359,120 net undeveloped acres in other oil and natural gas shale plays as of December 31, 2007.2008. Our technical staff is focused on identifying and testing new unconventional oil and natural gas resource plays where significant reserves could be developed if commercial production rates can be achieved through advanced drilling, fracture stimulation and enhanced recovery techniques.

Our Business Strengths

We have a number of strengths that we believe will help us successfully execute our strategies:

Large Acreage Inventory. We own 733,1321,114,445 net undeveloped and 372,329399,825 net developed acres as of December 31, 2007.2008. Approximately 72%78% of the undeveloped acres are foundlocated within unconventional shale resource plays including the Bakken shale in North Dakota and Montana, and the Woodford shale in southeast Oklahoma.and western Oklahoma, the Atoka shale in western Oklahoma and the Texas Panhandle, the New Albany shale in Indiana and Kentucky and the Lower Huron, Rhinestreet and Marcellus shales in West Virginia, Pennsylvania, New York and Ohio. The balance of the locations and undeveloped acreage is foundlocated primarily in other emerging unconventional resource plays including the Woodford and Atoka of western Oklahoma and the Red River of South Dakota as well as more conventional plays

including 3D defined locations for the Trenton-Black River of Michigan, Red River of Montana and North Dakota, Morrow-Springer of western Oklahoma and Frio in South Texas.

Horizontal Drilling and Enhanced Recovery Experience. In 1992, we drilled our initial horizontal well, and we have drilled over 460600 horizontal wells since that time. We also have substantial experience with enhanced recovery methods and currently serve as the operator of 48 waterflood units. Additionally, we operate eight high pressure air injection (“HPAI”) floods in the United States.floods.

Control Operations Over a Substantial Portion of Our Assets and Investments. As of December 31, 2007,2008, we operated properties comprising 93%91% of our PV-10. By controlling operations, we are able to more effectively manage the cost and timing of exploration and development of our properties, including the drilling and fracture stimulation methods used.

Experienced Management Team. Our senior management team has extensive expertise in the oil and gas industry. Our Chief Executive Officer, Harold G. Hamm, began his career in the oil and gas industry in 1967. Our seven senior officers have an average of 2728 years of oil and gas industry experience. Additionally, our technical staff, which includes 2127 petroleum engineers, 1617 geoscientists and 1011 landmen, has an average of 1920 years experience in the industry.

Strong Financial Position. As of February 29, 2008,23, 2009, we had outstanding borrowings under our revolving credit facility of approximately $222.0$474.4 million and available borrowing capacity under our selected commitment level of $178.0$198.1 million. We have elected to set the commitment level at $400$672.5 million, which is below the revolving credit facility note amount of $750.0 million and the established borrowing base of $600 million, in order to minimize commitment fees.$850.0 million. We believe that our planned exploration and development activities will be funded substantially from our operating cash flows and borrowings under our revolving credit facility. Our 2009 capital expenditures budget has been established based on our current expectation of available cash flow from operations. Should expected available cash flow from operations materially vary from expectations, we believe our credit facility has sufficient availability to fund any deficit or that we can further reduce our capital expenditures to be in line with cash flow from operations.

Oil and Gas Operations

Proved Reserves

The following tables set forth our estimated proved oil and natural gas reserves, percent of total proved reserves that are proved developed, the PV-10 and standardized measure of discounted future net cash flows as of December 31, 20072008 by reserve category and region. Ryder Scott Company, L.P., our independent petroleum engineers, evaluated properties representing approximately 85%83% of our PV-10, and our technical staff evaluated the remaining properties. The year-end weighted average oil and natural gas prices used in the computation of future net cash flows at December 31, 20072008 were $82.86$39.69 per barrel and $6.14$4.90 per Mcf, respectively.

		Oil (MBbls)		Gas (MMcf)		Total (MBoe)		% Proved developed			PV-10(1) (in millions)
Rockies:
Red River units		54,917		26,812		59,386		85	%		$	697
Bakken field
Montana Bakken		24,154		24,443		28,228		64	%			240
North Dakota Bakken		14,832		16,047		17,507		52	%			160
Other		5,524		8,255		6,900		99	%			62
Mid-Continent:
Arkoma Woodford		62		184,120		30,749		24	%			184
Other		6,657		56,439		16,062		86	%			170
Gulf Coast		93		2,022		430		100	%			10
Total		106,239		318,138		159,262		67	%		$	1,523

Developed and Undeveloped Acreage

The following table presents the total gross and net developed and undeveloped acreage by region as of December 31, 2007:2008:

The following table sets forth the number of gross and net undeveloped acres as of December 31, 20072008 that will expire over the next three years by region unless production is established within the spacing units covering the acreage prior to the expiration dates:

		2009				2010				2011
		Gross		Net		Gross		Net		Gross		Net
Rockies:
Red River units		—		—		—		—		—		—
Bakken field
Montana Bakken		18,037		10,920		24,557		19,510		57,527		48,367
North Dakota Bakken		156,404		83,394		137,899		59,424		224,552		79,934
Other		49,311		20,334		37,656		20,141		56,662		41,995
Mid-Continent:
Arkoma Woodford		49,015		17,005		23,808		8,801		15,225		6,811
Other		24,848		18,009		207,604		113,643		236,500		157,324
Gulf Coast		3,200		2,443		5		3		29,586		25,692
Total		300,815		152,105		431,529		221,522		620,052		360,123

Drilling Activity

During the three years ended December 31, 2007,2008, we drilled exploratory and development wells as set forth in the table below:

As of December 31, 2007,2008, there were 26117 gross (12.7(40 net) development wells and 42 gross (19.9 net) exploratory wells in the process of drilling.drilling, completing or waiting on completion.

As of February 29, 2008,23, 2009, we operated 157 rigs on our propertiesproperties. Our rig activity during 2009 will be highly dependent on oil and have plans to add additional rigs during the year.natural gas prices and accordingly our rig count may increase or decrease from current levels. There can be no assurance, however, that additional rigs will be available to us at an attractive cost. See “Risk Factors—The unavailability or high cost of additional drilling rigs, equipment, supplies, personnel and oilfield services could adversely affect our ability to execute our exploration and development plans within our budget and on a timely basis.”

Summary of Oil and Natural Gas Properties and Projects

Throughout the following discussion, we discuss our budgeted number of wells and capital expenditures. While the discussion reflects our current intentions, we intend to manage 2009 capital expenditures to be inline with our cash flow from operations. Continued weakness in oil and natural gas prices could cause us to curtail our actual capital expenditures. Conversely, an increase in commodity prices could result in increased capital expenditures.

Rocky Mountain Region

Our properties in the Rocky Mountain region represented 87%76% of our PV-10 as of December 31, 2007.2008. During the three months ended December 31, 2007,2008, our average daily production from such properties was 22,36524,536 net Bbls of oil and 13,40917,041 net Mcf of natural gas. Our principal producing properties in this region are in the Red River units, the Bakken field and the Big Horn Basin.

Red River Units

Our Red River units represented 56%59.6% of our PV-10 in the Rocky Mountain region as of December 31, 20072008 and 58%51% of our average daily Rocky Mountain region equivalentBoe production for the three months ended December 31, 2007.2008. The eight units comprising the Red River units are located along the Cedar HillsCreek 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. Our Red River units comprise a portion of the Cedar Hills field, listed by the Energy Information Administration in 20062007 as the 136^th largest onshore, lower 48 field in the United States ranked by liquid proved reserves.

Cedar Hills Units. The Cedar Hills North unit (CHNU)(“CHNU”) is located in Bowman and Slope Counties, North Dakota. We drilled the initial horizontal well in the CHNU, the Ponderosa 1-15, in April 1995. As of December 31, 2007,2008, we had drilled 185225 horizontal wells within this 49,700-acre unit, with 113128 producing wellbores and the remainder serving as injection wellbores. We operate and own a 98% working interest in the CHNU.

The Cedar Hills West unit (CHWU)(“CHWU”), in Fallon County, Montana, is contiguous to the northern portion of CHNU. As of December 31, 2007,2008, this 7,800-acre unit contained teneleven horizontal producing wells and fivesix horizontal injection wells. We operate and own a 100% working interest in the CHWU.

In January 2003, we commenced enhanced recovery in the two Cedar Hills units, with HPAI used throughout most of the area and water injected generally along the boundary of the CHNU. Under HPAI, compressed air injected into a reservoir oxidizes residual oil and produces flue gases (primarily carbon dioxide and nitrogen) that mobilize and sweep the crude oil into producing wellbores. In response to the HPAI, water injection and increased density drilling operations, production from the Cedar Hills units increased to 10,86911,451 net Boe per day in December 20072008 from 2,185 net Boe per day in November 2003. As of December 31, 2007,2008, the average density in the Cedar Hill units was approximately one producing wellbore per 467420 acres. We currently plan to drill 564 new horizontal wellbores and 52 horizontal extensions of existing wellbores in the Cedar Hills units during the next two years,2009, increasing the density of both the producing and injection wellbores. The reduced distance between wells will allowallows part of the field to be converted from air injection to water injection. This conversion will beginbegan in 2008 and is forecast to lower operating expenses, as water is less costly to inject than air. In 2008,2009, we plan to invest approximately $113$41.3 million drilling and improving facilities in the Cedar Hills units. This expenditure is lower than previously forecast due to the elimination of 25 gross wells from the increased density development program. This adjustment to the plan is a result of reduced commodity prices. The peak rate for the field will be reduced but we expect no reduction in ultimate reserves.

On August 22, 2007 the Hiland Partners, LP (“Hiland”) Badlands gas plant became operational for the processing and treatment of gas produced from the CHNU, and CHWU and Medicine Pole Hills Unit. Under the terms of the November 8, 2005 contract we agree to deliver low pressure gas to Hiland for compression, treatment and processing. Nitrogen and carbon dioxide must be removed from the gas production associated with oil production from the units for the gas production to be marketable. Under the terms of the contract, weWe pay $0.60 per Mcf in gathering and treating fees, and 50% of the electrical costs attributable to compression and plant operation and receive 50% of the proceeds from residue gas and plant product sales. After we deliver 36 Bcf of gas, the $0.60 per Mcf gathering and treating fee is eliminated. During December 2007,2008, we sold 5,3227,800 net Mcf of natural gas per day.day from the Cedar Hills Units.

Medicine Pole Hills Units. The Medicine Pole Hills units (MPHU)(“MPHU”) are approximately five miles east of the southern portion of the CHNU. We acquired the Medicine Pole Hills unit in 1995. At that time, the 9,600-

acre unit consisted of 18 vertical producing wellbores and four injection wellbores under HPAI producing 525 net Bbls of oil per day. We have since drilled 4047 horizontal wellbores extending production to the west with the formation of the 15,000-acre Medicine Pole Hills West unit and to the south, with the 11,500-acre Medicine Pole Hills South unit. All three units are under HPAI. We operate and own an average 77% working interest in the three units. Production from the units averaged 1,2341,391 net Bbls of oil and 409178 net Mcf of natural gas per day during December 2007. We are currently operating one rig and plan to drill 122008. During 2008 we drilled 7 new horizontal wellbores, and four2 horizontal extensions of existing wellbores, during the next 18 months,and 2 horizontal re-entries of vertical wellbores, increasing the density of both producing and injection wellbores. We believe these operations will increase production and sweep efficiency. In 2008,2009, we plan to invest approximately $29.0$3.4 million for drillingcapital workover and facilities in MPHU.

Buffalo Red River Units. Three contiguous Buffalo Red River units (Buffalo, West Buffalo and South Buffalo) are located in Harding County, South Dakota, approximately 21 miles south of the MPHU. When we purchased the units in 1995, there were 73 vertical producing wellbores and 38 injection wellbores under HPAI producing approximately 1,906 net Bbls of oil per day. We operate and own an average working interest of 95% in the 32,900 acres comprising the three units. From 2005 tothrough 2008, we re-entered 4248 existing vertical wells and drilled horizontal laterals to increase production and sweep efficiency from the three units. Production for the month of December 20072008 was 1,9451,670 net Bbls of oil per day compared to an average of 1,162 net Bbls of oil per day for the first half of 2005. We currently plan to drill 5 horizontal extensions of existing wellbores and 25 new horizontal wellbores in the Buffalo Red River units over the next two years. We believe these operations will increase production and sweep efficiency. In 2008,2009, we plan to invest $23$0.7 million for drillingcapital workover and facilities in the Buffalo Red River units.

Bakken Field

We control one of the largest acreage positions in the Bakken field of Montana and North Dakota with approximately 1,155,000 gross (581,000 net) acres as of December 31, 2008. Approximately 17% of the net acreage is producing and 83% of the net acreage is undeveloped as of December 31, 2008. Our properties within the Bakken field in Montana and North Dakota represented 28%35% of our PV-10 in the Rocky Mountain region as of December 31, 20072008 and 35%39% of our average daily Rocky Mountain region equivalentBoe production for the three months ended December 31, 2007. 2008. As of December 31, 2008 we had completed 308 gross (148.5 net) wells in the Bakken field.

The Bakken formation or “ Bakken shale”“Bakken Shale”, as it is often called, has becomeis one of the most actively drilled unconventional oil resource plays in the United States with approximately 5483 rigs drilling in the play as of February 29,December 31, 2008, including 4876 in North Dakota and 6seven in Montana. A report issued by the United States Geologic Survey (“USGS”) in April 2008 estimates that the Bakken Shale contains up to 4.3 billion barrels of recoverable oil using today’s technology and classifies it as the largest continuous oil accumulation ever assessed by the USGS.

The Bakken formation is a Devonian-age shale found within the Williston Basin underlying portions of North Dakota and Montana that contains three lithologic members including the upper shale, middle member and lower shale that combined range up to 130 feet thick. The upper and lower shales are highly organic, thermally mature and over pressured and act as both a source and reservoir for the oil. The middle member, which varies in composition from a silty dolomite to shalely limestone or sand, also serves as a reservoir and locally is thought to be a critical component for commercial production. Recently, theThe Three Forks-SanishForks/Sanish formation found immediately under the Lower Bakken Shale has emerged as another potentialalso proven to contain productive reservoir rock that couldmay add significant incremental reserves to the play. TheseThe Three Forks/Sanish typically consists of interbedded dolomites and shale with local development of a discontinuous sandy member at the top, known as the Sanish sand. All of these reservoir rocks have inherently low porosity and permeability and depend on natural fracturing and artificial fracture stimulation to produce economically. Horizontal drilling and advancedmulti-stage fracture stimulation technologies havetechnology has enabled commercial production from this historically non-commercial reservoir. Generally, the Bakken formation is found at vertical depths of 9,000 to 10,500 feet and drilled horizontally on 320, 640 or 1,280-acre spacing with single, dual or triple leg horizontal laterals extending 4,500 to 9,000 feet into the formation. These wells are fracture stimulated to maximize recovery and economic returns. The fracture stimulation techniques vary but are evolving to a more common practice ofmost commonly utilize multi-stage mechanically diverted stimulations using un-cemented liners and packers which appears to improve rates and recoveries.packers.

Montana Bakken. TheOur Montana Bakken production is located in the Elm Coulee field in Richland County, Montana. The Elm Coulee field is listed by the Energy Information Administration as the 1516^th largest onshore, lower 48 field in the United States ranked by liquid proved reserves. Since drilling our first well in August 2003, we have completed a total of 134156 gross (84(100.2 net) wells in the field as of December 31, 2007.2008. Our daily average production from these wells was approximately 6,3345,727 net Bbls of oil and 4,8143,944 net Mcf of natural gas during the month of December 2007.2008. The field has been developed exclusively with horizontal drilling and has been substantially drilled on 640-acre spacing. During 20072008, we completed 35 gross (25.9 net) wells as we continuedbegan to further develop and expand the field. Two of these wells successfully demonstrated that development ofour acreage in the field on 320-acre320 acre spacing is warranted. These 2and have identified 57 undrilled 320 acre infield locations on our acreage as of December 31, 2008. Out of the 22 gross (1.3(16.2 net) wells we drilled in the field during 2008, 12 gross (10.3 net) were assigned average estimated recoverable reserves of 468 gross MBoe, which exceeded320 acre infield wells. These wells are performing in line with our economicexpected reserve model of 300 MBoe per well. We also successfully demonstrated that 640-acre tri-lateral drilling was an effective technique to expand the economic limits of the field with the completion of 8 gross (6.2 net) tri-lateral wells which were assigned average estimated reserves consistent with our economic model of 250279 MBoe per well.

In December 2008 we also began operations on a one well secondary recovery pilot project to evaluate the potential to increase oil recovery from the Bakken reservoir utilizing CO2 injection. Laboratory tests indicate this technique is feasible and could increase oil recovery from the Bakken reservoir. Using a technique known as the huff and puff method, we began injecting CO2 in January 2009 and expect to complete the injection phase by March 2009. After allowing the CO2 to soak into the reservoir for approximately 30 days, we will flow the CO2 and associated fluids back from the well. Production from the well will be measured and the performance will be analyzed to assess the incremental recovery and economics of the technique.

As of December 31, 2007,2008, we held 86,488131,422 gross (64,536(101,010 net) undeveloped acres in the Richland County, Montana portion ofBakken play within and adjacent to the BakkenElm Coulee field. We currently have three operated rigsrecently suspended drilling in the fieldMontana Bakken due to weakness in oil and plan to invest $48.0 million in thenatural gas prices and will resume drilling of 17 gross (13 net) horizontal Bakken wells in the field during 2008.as prices improve.

North Dakota Bakken.SinceOur 2008 drilling our first well in October, 2004, we have completed a totalprogram significantly expanded the proven extents of 54 gross (21 net) horizontal wells in theour North Dakota Bakken field asacreage along the Nesson anticline. During the year we completed 98 gross (27.2 net) wells and exited 2008 producing at an average daily rate of 5,081net Bbls of oil during the month of December 31, 2007. Our daily average production from these 54 wells was approximately 1,351 net Bbls of oil2008, a 276% increase over the same period in 2007 and 8201,744 net Mcf of natural gas during the month of December 2007. Our drilling to date has been primarily exploratory and step-out2008, an increase of 113% over the same period in nature to evaluate and define areas of economic production for further development on our acreage. As of December 31, 2007, we owned approximately 296,000 net acres preferentially located along the prolific Nesson anticline where fracturing in the Bakken is expected to be enhanced. We accelerated our drilling activity in the field during 2007, completing 38 gross (14.7 net) wells during the year. Twenty seven of these completed wells were located in the central and northern portions of our acreage and were assigned average estimated recoverable reserves of 335 gross MBoe per well, which is in line with our economic model of 315 MBoe per well. 2007.

During the year we modified our horizontal drilling and completion design and now drill primarilydrilled almost exclusively 1,280-acre spaced, long single leg laterals, utilizing uncementedup to 9,000 feet long and fracture stimulated these wells with up to 14 mechanically diverted stages using un-cemented liners and packerspackers. We found this technique provided better wellbore integrity and on average delivered higher initial flow rates. Of significance, we completed 27 gross (10.3 net) Three Forks/Sanish wells during 2008. The Three Forks/Sanish formation which lies immediately below the lower Bakken shale is known to mechanically divertbe productive locally throughout the fracture stimulation.Williston Basin and may add incremental reserves to the Bakken play. Our Three Forks/Sanish completions were strategically located throughout our acreage along the Nesson anticline over a distance of approximately 100 miles north to south. The success of these Three Forks/Sanish wells demonstrates the widespread productive potential of the Three Forks/Sanish reservoir underlying our acreage. Although the results in themselves do not demonstrate the Three Forks/Sanish formation adds incremental reserves to the Bakken play, it is notable that the 20 gross (8.9 net) Three Forks/Sanish completions we operated in 2008 had an average initial production rate of 640 gross Boe per day which is 17% higher than our average operated Middle Bakken completion in 2008.

As of December 31, 2007,2008, we held 553,516865,000 gross (271,667(378,000 net) undeveloped acres in the North Dakota Bakken field. We currently have sixAs of February 23, 2009, we had 10 rigs drilling rigs in the North Dakota Bakken field, three of which areincluding 4 operated by Conoco-PhillipsContinental Resources, Inc, and 6 operated by ConocoPhillips through a joint venture.joint-venture. We plan to add three to five operated rigs to the play and invest approximately $105$71 million in the drilling of 7486 gross (20(20.2 net) horizontal wells in the North Dakota Bakken field during 2008.2009.

Haley Red River.

Our Haley Red River project is located approximately 12 miles northeast of our Buffalo Red River units located in Harding County, South Dakota. The producing reservoir is the same Red River B dolomite that produces in our Red River units. Here the dolomite occurs at a depth of approximately 9,000 feet and averages 4 to 6 feet thick. The dolomite is widely present and oil saturated and, as in our Red River units, must be drilled horizontally to produce at economic rates. Horizontal wells are typically drilled on 640-acre spacing as single leg laterals and completed open hole without stimulation. As of December 31, 2007 we have completed 4 gross (4 net) horizontal wells with initial rates of up to 419 Boe per well per day. Based on our economic model, we expect to recover approximately 250 MBoe per well. We owned approximately 58,000 net acres as of December 31, 2007 and continue to build acreage in the project. We plan to invest approximately $18 million drilling 9 gross (7.7 net) wells during 2008 in the Haley Red River project.

Big Horn Basin and Other Rockies

Our wells within the Big Horn Basin in northern Wyoming and other areas within the Rocky Mountain region represented 4%5% of our PV-10 in the Rocky Mountain Region as of December 31, 20072008 and 4%9% of our average daily Rocky Mountain Region equivalentBoe production for the three months ended December 31, 2007.2008. During the three months ended December 31, 2007,2008, we produced an average of 7671,794 net Bbls of oil and 1,0604,280 net Mcf of natural gas per day from our wells in the Big Horn Basin and other areas within the Rocky Mountain region.

Our principal property in the Big Horn Basin, the Worland field, produces primarily from the Phosphoria formation. We also have several other ongoing projects ongoing in the Rockies including conventional 3D defined Red River and Lodgepole structures in North Dakota and Montana, horizontal Winnipegosis and Fryburg opportunities in North Dakota and the Lewis Shale and Fort Union in Wyoming.

Conventional Red River.The Red River is a well known conventional producing oil and gas reservoir throughout the Williston Basin of North Dakota and Montana. The production can be quite prolific with individual Red River wells producing up to 1.5 million barrels of oil but the productive reservoir is generally confined to structural closures and structural-stratigraphic traps of 320 acres to 640 acres in size. The potential exists to find this type of conventional Red River production underlying any portion of our Bakken acreage in North Dakota and Montana. To identify these Red River traps generally requires 3D seismic. We own or have under license 964 square miles of 3D seismic over portions of our acreage in Montana and North Dakota. As of December 31, 2008 we had interpreted approximately 8% of this data using our proprietary processing techniques and have identified 9 undrilled potential locations. In 2008, we drilled and completed 6 gross (3.1 net) vertical Red River wells with 4 gross (2.2 net) wells completed as producers for a 71% success rate. During 2009, we plan to invest $9 millioncontinue re-processing and evaluating our 3D seismic to identify new potential drilling 11 gross (5.1 net) wells in 2008.locations.

Mid-Continent and Gulf Coast Region

Our properties in the Mid-Continent and Gulf Coast region represented 13%24% of our PV-10 as of December 31, 2007.2008. During the three months ended December 31, 2007,2008, our average daily production from such properties was 1,6132,321 net Bbls of oil and 20,94937,922 net Mcf of natural gas. Our principal producing properties in this region are located in the Anadarko and Arkoma Basins of Oklahoma, the Michigan Basin and the Illinois Basin.

Anadarko BasinArkoma Woodford

Our properties withinThe Arkoma Woodford play in Atoka, Coal, Hughes and Pittsburg Counties, Oklahoma has matured into one of the Anadarko Basinmore active unconventional gas resource plays in the United States with 36 rigs drilling in the play industry wide as of December 31, 2008. We owned approximately 161,000 gross (47,000 net) acres in the Woodford play as of December 31, 2008. Since drilling our first well in February, 2006, we have completed a total of 259 gross (41.4 net) horizontal Woodford wells through December 31, 2008. These Arkoma Woodford wells represent 40%52% of ourthe PV-10 in the Mid-Continent Region as of December 31, 20072008 and 52%41% of our average daily Mid-Continent Region equivalent production for the three months ended December 31, 2007.2008. During 2008, production from our Arkoma Woodford wells grew 213% from an average of 8,428 Mcf of natural gas equivalent per day during December 2007 to 26,380 Mcf of natural gas equivalent per day in December 2008.

We completed 115 gross (23.3 net) Woodford wells during 2008. This drilling consisted of a combination of exploratory, step-out and development drilling designed to secure acreage and delineate areas of economic production for further development. Of significance, we expanded the known extents of commercial production to the western extents of our Ashland AMI and south into our Big Mac Prospect. We also completed our first well in the East McAlester area. As of December 31, 2008, approximately 72% of our net acreage remained undeveloped.

During the year ended December 31, 2008, we began to develop the field on various densities including 320, 160 and 80-acre spacing, to determine the optimum spacing for development. Results indicated that 80-acre development is economically feasible on much of our acreage. We also began simul-fracing wells when possible to more effectively stimulate and produce the Woodford shale while causing minimal disruption to existing production. We also reduced our average cost per lateral foot drilled by 20% compared to 2007 through improved mud systems, bit selections and operational efficiencies. We also successfully demonstrated that we can drill and complete wells across faults that previously limited the length of lateral drilled. To guide our drilling we acquired 49 square miles of 3-D seismic data during the year bringing the total of 3D seismic we own or have under license to 93 square miles.

We plan to invest approximately $56.0 million drilling 63 gross (8.0 net) horizontal wells in the Arkoma Woodford during 2009. We currently have one operated rig drilling in the play and are in the process of acquiring 53 square miles of 3-D seismic to guide future drilling on our East McAlester acreage.

Anadarko Basin

Our properties within the Anadarko Basin represented 27% of our PV-10 in the Mid-Continent Region as of December 31, 2008 and 40% of our average daily Mid-Continent Region equivalent production for the three months ended December 31, 2008. Our wells within the Anadarko Basin produce from a variety of sands and carbonates in both stratigraphic and structural traps. During the year we drilled 19 gross (11.5 net) wells with a 90% gross (84% net) success rate. In 2008,2009, we plan to invest approximately $18$23.0 million in the drilling of 1418 gross (10.5(5.0 net) wells in the Anadarko Basin.

Anadarko Woodford. We owned 189,246 gross (117,665 net) acres in the emerging Anadarko Woodford shale play of western Oklahoma as of December 31, 2008. This includes 144,000 gross (93,000 net) undeveloped acres acquired in 2008 and 44,923 gross (24,586 net) acres held by production. Our acreage is strategically positioned within the window of thermal maturation for natural gas along the eastern flank of the Anadarko basin extending across portions of Grady, Canadian, Blaine, Custer and Dewey Counties of Oklahoma. The Woodford shale underlying this acreage ranges from 75 to 250 feet thick and occurs at depth ranging from 10,000 to 15,000 feet. Industry peers began drilling and completing horizontal Woodford shale wells in Canadian County, Oklahoma in August of 2007 and as of December 31, 2008 there were 17 rigs drilling in the play. Results announced by various operators in the play have been encouraging, with initial daily production rates of up to 8,300 Mcf of natural gas equivalent per well. Based on our economic model, we expect to recover approximately 5 Bcf to 7 Bcf per well. During 2008 we drilled 2 gross (1.9 net) horizontal Woodford wells and both are currently in the process of being completed.

Anadarko Atoka.We owned 44,938 gross (27,566 net) acres in the emerging Anadarko Atoka Shale play of Western Oklahoma and the Panhandle of Texas as of December 31, 2008. Our acreage is focused in Ellis County, Oklahoma and Lipscomb County, Texas and strategically located along trend with the development of the Novi Lime formation. The Novi Lime formation is important as it serves as both reservoir and drilling conduit for the horizontal wellbore through which the surrounding natural gas charged Atoka shales can be fracture stimulated and produced. The Atoka shales range from 75 feet to 125 feet thick and are present throughout our properties. Public records show as of February 23, 2009, 37 horizontal Atoka wells have been completed by industry peers with initial production rates of up to 7,500 Mcf of natural gas per day. During 2008, we drilled 2 gross (2 net) horizontal Atoka wells. The first well, the Shrewder 1-22H (100% WI) completed flowing 1,297 Mcf of natural gas per day from a short, 1,300 foot, horizontal lateral. The second well, the Jones Trust 1-168H (100% WI) was recently fracture stimulated and currently flow testing at a rate of approximately 700 Mcf of natural gas per day.

Illinois Basin

Our properties within the Illinois Basin represent 30%represented 20.6% of the PV-10 in the Mid-Continent Region as of December 31, 20072008 and 21%4.9% of our average daily Mid-Continent Region equivalentBoe production for the three months ended December 31, 2007.2008. We drilled 19 gross (17 net) wells during 2008 developing fields and expanding our reserve base in the Illinois Basin. Our wellsproduction within the Illinois Basin produceis primarily crude oil from units comprised of shallow sand formations under water injection. In 2008, we plan to invest approximately $3 million in the drilling of 21 gross (20.6 net) wells in the Illinois Basin.

Arkoma Woodford

The Arkoma Woodford play in Atoka, Coal, Hughes and Pittsburg Counties, Oklahoma has emerged into one of the most active unconventional gas resource plays in the country with 34 rigs drilling in the play as of February 29, 2008. We owned approximately 145,000 gross (44,000 net) acres in the Woodford play as of December 31, 2007. Since drilling our first well in February, 2006, we have completed a total of 132 gross (16.1 net) horizontal Woodford wells as of December 31, 2007. The majority of this drilling occurred in 2007 with 110 gross (14.8 net) horizontal wells completed during the year. These Arkoma Woodford wells represent 30% of the PV10 in the Mid-Continent Region as of December 31, 2007 and 26% of our average daily Mid-Continent Region equivalent production for the three months ended December 31, 2007. Our drilling has been primarily focused on exploration and step-out drilling to secure leases and delineate areas of economic production for development. This drilling has been conducted primarily on 640-acre spacing but is expected to be ultimately drilled more densely. Recent testing by other operators in the play indicated it may be economic to drill the Woodford on 80-acre and possibly 40-acre spacing.

We plan to invest approximately $93 million in the drilling of 139 gross (19.9 net) horizontal wells in the Arkoma Woodford during 2008. We currently have four operated rigs in the play and plan to add two more rigs by mid-year. Most of our operated drilling activity in 2008 will focus on development and step-out opportunities.

Michigan Trenton-Black River

Our Trenton-Black River project in and around Hillsdale County, Michigan continues to produce excellent results. Guidedresults guided by innovative 3Dour proprietary 3-D seismic techniques,techniques. As of December 31, 2008, we have experienced 100% success completing 3had completed 7 gross (2.5(5.8 net) operated wells in the project. Our initial discoveryplay with 6 gross (4.9 net) of the wells completed as Trenton-Black River producers and 1 gross (1 net) well temporarily abandoned. These 6 producing wells were assigned average estimated recoverable reserves of 490 MBoe per well. Combined, these wells were producing an average of 550 gross barrels of oil per day during the McArthur 1-36 (83% WI)month of December 31, 2008. Three of the wells are capable of flowing in excess of the 200 barrels of oil per day allowable set by the Michigan Department of Environmental Quality and 3 are restricted by natural gas flaring restrictions which will be removed once the wells are connected to a natural gas pipeline. A natural gas gathering pipeline has been assigned gross proved reserves of 824,000installed and processing facilities are under construction to enable these flare restricted wells to produce up to the 200 barrels of crude oil equivalent. Our second well, the Anspaugh 1-1 (83% WI) encountered similar type pay and was flow testing at a rate ofper day allowable rate.

We owned approximately 200 Bopd on March 3, 2008. Our third well, the Wessel 1-6 (83% WI) was flow testing at a rate of approximately 200 Bopd on March 3, 2008. Testing will continue on the Anspaugh 1-1 and Wessel 1-6 to establish reservoir characteristics and estimated reserves. We have also participated in 265,418 gross (0.6 net) non-operated Trenton-Black River tests. The Clark 1-36 (21%WI) is testing very low volumes of oil. The Young 10-34 (42%WI) encountered encouraging shows while drilling and is currently waiting on completion. We own approximately 29,000 gross (23,000(52,110 net) acres in the play and have shot, processed and interpreted 11approximately 40 square milesmile of 3D3-D seismic on the acreage so far. We are currently permitting 5 additional wells and will beginas of December 31, 2008. During 2008, we completed the acquisition of 20 square miles of new 3D3-D seismic on our Chicago/Norad project. Interpretation of the seismic data in March with plansidentified up to acquire additional data later this year.

Other Mid-Continent

During 2007 our geoscientists identified two new14 potential unconventional resource opportunities in the Mid-Continent region. Detailsdrilling locations. Four of these opportunitieslocations have not been disclosed to minimize competition as we are in the process of acquiring leases. As of December 31, 2007 we had acquired 17,000 net acres.selected and permitted for drilling. We plan to invest approximately $20 million drilling 19 gross (7.1 net) wells on these and other emerging opportunities in the Mid-Continent region in 2008.acquire another 6.5 square miles of additional 3D seismic data during 2009.

Gulf Coast

During the three months ended December 31, 2007,2008, our average daily production from our Gulf Coast properties was 330225 net Bbls of oil and 2,0042,341 net Mcf of natural gas. Our principal producing properties in this region are located in South Texas and Louisiana. In 2008, we plan to invest approximately $18.0 million in the drilling of 9 gross (5.4 net) wells in the Texas and Louisiana Gulf Coast.

Production and Price History

The following table sets forth summary information concerning our production results, average sales prices and production costs for the years ended December 31, 2008, 2007 2006 and 2005:2006:

The following table sets forth information regarding our average daily production during the fourth quarter of 2007:2008:

		Fourth Quarter 2008
		Oil (Bbls)		Gas (Mcf)		Total (Boe)
Rockies:
Red River units		12,860		7,187		14,058
Bakken field
Montana Bakken		5,697		4,278		6,410
North Dakota Bakken		4,185		1,296		4,401
Other		1,794		4,280		2,507
Mid-Continent:
Arkoma Woodford		50		19,353		3,276
Other		2,046		16,228		4,751
Gulf Coast		225		2,341		615
Total		26,857		54,963		36,018

Productive Wells

The following table presents the total gross and net productive wells by region and by oil or gas completion as of December 31, 2007:2008:

Gross wells are the number of wells in which a working interest is owned and net wells are the total of our fractional working interests owned in gross wells. As of December 31, 2007,2008, we owned interests in no wells containing multiple completions.

Title to Properties

As is customary in the oil and gas industry, we initially conduct only a cursory review of the title to our properties on which we do not have proved reserves. Prior to the commencement of drilling operations on those properties, we endeavor to conduct a thorough title examination and perform curative work with respect to significant defects. To the extent title opinions or other investigations reflect title defects on those properties,properties; we are typically responsible for curing any title defects at our expense. We generally will not commence drilling operations on a property until we have cured any material title defects on such property. We have obtained title opinions on substantially all of our producing properties and believe that we have satisfactory title to our producing properties in accordance with standards generally accepted in the oil and gas industry. Prior to completing an acquisition of producing oil and natural gas leases, we perform title reviews on the most significant leases and, depending on the materiality of properties, we may obtain a title opinion or review previously obtained title opinions. Our oil and natural gas properties are subject to customary royalty and other interests, liens to secure borrowings under our revolving credit facility, liens for current taxes and other burdens which we believe do not materially interfere with the use or affect our carrying value of the properties.

Marketing and Major Customers

We principallyprimarily sell our oil and natural gas production to end users marketers and other purchasersat major market centers. Other production is sold to select midstream marketing companies or oil refining companies at the lease. We have significant production directly connected to a pipeline gathering system, although the balance of our production is transported by truck. Where the oil that have access to nearby pipeline facilities. In areas where there is no practical access to pipelines, oildirectly marketed is transported by truck, the oil is delivered to storage facilities. the most practical point on a pipeline system for delivery to a sales point “downstream” on another connecting pipeline. Oil that is sold at the lease is delivered directly onto the purchasers’ truck and the sale is complete at that point.

During the fourth quarter of 2007 and various periods in 2008, we were unable to market some of our Rocky Mountain area crude at a price acceptable to us. This resulted in an increaseincreases in our crude oil inventory of 125 MBbls.at various times throughout the year. The priceprices we were offered waswere adversely affected by seasonal demand. We have temporarilydemand and by pipeline constraints. At various times during 2007 and 2008, we shipped some of our Rocky Mountain crude by railcar to help alleviate this situation. We were able to sell the majority of this oil in Januarysituation and February 2008.obtain more favorable prices. Our marketing of oil and natural gas can be affected by factors beyond our control, the effects of which cannot be accurately predicted. For a description of some of these factors, see “Risk factors—Market conditions or operational impediments may hinder our access to oil and natural gas markets or delay our production.”

For the year ended December 31, 2007,2008, oil sales to Tidal Energy Marketing (U.S.) L.L.C., Marathon Oil Company and Suncor Energy accounted for 20%, 14% and 10%, respectively,44% of our total revenue. No other purchasers accounted for more than 10% of our total oil and gas sales. We believe that the loss of any of these purchasers would not have a material adverse effect on our operations, as there are a number of alternative crude oil purchasers in our producing regions.

Competition

We operate in a highly competitive environment for acquiring properties, marketing oil and natural gas and securing trained personnel. Our competitors vary within the regions in which we operate, and some of our competitors may possess and employ financial, technical and personnel resources substantially greater than ours, which can be particularly important in the areas in which we operate. Those companies may be able to pay more for productive oil and natural gas properties and exploratory prospects and to evaluate, bid for and purchase a greater number of properties and prospects than our financial or personnel resources permit. In addition, shortages or the high cost of drilling rigs could delay or adversely affect our development and exploration operations. Our ability to acquire additional prospects and to find and develop reserves in the future will depend on our ability to evaluate and select suitable properties and to consummate transactions in a highly competitive environment. Also, there is substantial competition for capital available for investment in the oil and natural gas industry.

Regulation of the Oil and Natural Gas Industry

Regulation of Transportation of Oil

Sales of crude oil, condensate and natural gas liquids are not currently regulated and are made at negotiated prices. Nevertheless, Congress could reenact price controls in the future.

Our sales of crude oil are affected by the availability, terms and cost of transportation. The transportation of oil in common carrier pipelines is also subject to rate and access 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. 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. Insofar as effective interstate and intrastate rates are equally applicable to all comparable shippers, we believe that the regulation of oil transportation rates will not affect our operations in any way that is of material difference from those of our competitors.competitors who are similarly situated.

Further, interstate and intrastate common carrier oil pipelines must provide service on a non-discriminatory basis. Under this open access standard, common carriers must offer service to all similarly situated shippers requesting service on the same terms and under the same rates. When oil pipelines operate at full capacity, access is governed by prorating provisions set forth in the pipelines’ published tariffs. Accordingly, we believe that access to oil pipeline transportation services generally will be available to us to the same extent as to our similarly situated competitors.

Regulation of Transportation and SaleSales of Natural Gas

Historically, the transportation and sale for resale of natural gas in interstate commerce have been regulated by agencies of the U.S. federal government, primarily 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 and culminated in adoption of the Natural Gas Wellhead Decontrol Act which removed controls affecting wellhead sales of natural gas effective January 1, 1993.

FERC regulates interstate natural gas transportation rates and service conditions, which affects the marketing of natural gas that we produce, as well as the revenues we receive for sales of our natural gas. Since 1985, the FERC has endeavored to make natural gas transportation more accessible to natural gas buyers and sellers on an open and non-discriminatory basis. The FERC has stated that open access policies are necessary to improve the competitive structure of the interstate natural gas pipeline industry and to create a regulatory framework that will put natural gas sellers into more direct contractual relations with natural gas buyers by, among other things, unbundling the sale of natural gas from the sale of transportation and storage services. Beginning in 1992, the FERC issued a series of orders to implement its open access policies. As a result, the interstate pipelines’ traditional role as wholesalers of natural gas has been eliminated and replaced by a structure under which pipelines provide transportation and storage service on an open access basis to others who buy and sell natural gas. Although the FERC’s orders do not directly regulate natural gas producers, they are intended to foster increased competition within all phases of the natural gas industry.

We cannot accurately predict whether the FERC’s actions will achieve the goal of increasing competition in markets in which our natural gas is sold. Additional proposals and proceedings that might affect the natural gas industry are pending before the FERC and the courts. The natural gas industry historically has been very heavily

regulated. Therefore, we cannot provide any assurance that the less stringent regulatory approach recently established by the FERC will continue. However, we do not believe that any action taken will affect us in a way that materially differs from the way it affects other natural gas producers.

The price at which we sell natural gas is not currently subject to federal rate regulation and, for the most part, is not subject to state regulation. However, with regard to our physical sales of these energy commodities, we are required to observe anti-market manipulation laws and related regulations enforced by the FERC and/or the Commodity Futures Trading Commission (“CFTC”). See below the discussion of “Other Federal Laws and Regulations Affecting Our Industry—Energy Policy Act of 2005.” Should we violate the anti-market manipulation laws and regulations, we could also be subject to related third party damage claims by, among others, sellers, royalty owners and taxing authorities. In addition, pursuant to Order 704, some of our operations may be required to annually report to FERC, starting May 1, 2009, information regarding natural gas sale transactions depending on the volume of natural gas transacted during the prior calendar year. See below the discussion of “Other Federal Laws and Regulations Affecting Our Industry—FERC Market Transparency Rules.”

Gathering service, which occurs upstream of jurisdictional transmission services, is regulated by the states onshore and in state waters. Although its policy is still in flux, FERC has reclassified certain jurisdictional transmission facilities as non-jurisdictional gathering facilities, which has the tendency to increase our costs of getting gas to point of sale locations. State regulation of natural gas gathering facilities generally include various safety, environmental and, in some circumstances, nondiscriminatory-takenondiscriminatory take requirements. Although such regulation has not generally been affirmatively applied by state agencies, natural gas gathering may receive greater regulatory scrutiny in the future.

Intrastate natural gas transportation is also subject to regulation by state regulatory agencies. The basis for intrastate regulation of natural gas transportation and the degree of regulatory oversight and scrutiny given to intrastate natural gas pipeline rates and services varies from state to state. Insofar as such regulation within a particular state will generally affect all intrastate natural gas shippers within the state on a comparable basis, we believe that the regulation of similarly situated intrastate natural gas transportation in any states in which we operate and ship natural gas on an intrastate basis will not affect our operations in any way that is of material difference from those of our competitors. Like the regulation of interstate transportation rates, the regulation of intrastate transportation rates affects the marketing of natural gas that we produce, as well as the revenues we receive for sales of our natural gas.

Regulation of Production

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. All of the states in which we own and operate properties have regulations governing conservation matters, including provisions for the unitization or pooling of oil and natural gas properties, the establishment of maximum allowable rates of production from oil and natural gas wells, the regulation of well spacing, and plugging and abandonment of wells. The effect of these regulations is to limit the amount of oil and natural gas that we can produce from our wells and to limit the number of wells or the locations at which we can drill, although we can apply for exceptions to such regulations or to have

reductions in well spacing. Moreover, each state generally imposes a production or severance tax with respect to the production and sale of oil, natural gas and natural gas liquids within its jurisdiction.

The failure to comply with these rules and regulations can result in substantial penalties. Our competitors in the oil and natural gas industry are subject to the same regulatory requirements and restrictions that affect our operations.

Other Federal Laws and Regulations Affecting Our Industry

Energy Policy Act of 2005.On August 8, 2005, President Bush signed into law the Domenici-Barton Energy Policy Act of 2005 (“EP Act 2005”). The EP Act 2005 is a comprehensive compilation of tax incentives, authorized appropriations for grants and guaranteed loans, and significant changes to the statutory policy that affects all segments of the energy industry. Among other matters, EP Act 2005 amends the NGA to add an anti- market manipulation provision which makes it unlawful for any entity to engage in prohibited behavior to be prescribed by FERC, and furthermore provides FERC with additional civil penalty authority. The EP Act 2005 provides the FERC with the power to assess civil penalties of up to $1,000,000 per day for violations of the NGA and increases the FERC’s civil penalty authority under the NGPA from $5,000 per violation per day to $1,000,000 per violation per day. The civil penalty provisions are applicable to entities that engage in the sale of natural gas for resale in interstate commerce. On January 19, 2006, FERC issued Order No. 670, a rule implementing the anti-market manipulation provision of EP Act 2005, and subsequently denied rehearing. The rules make it unlawful to: (1) in connection with the purchase or sale of natural gas subject to the jurisdiction of FERC, or the purchase or sale of transportation services subject to the jurisdiction of FERC, for any entity, directly or indirectly, to use or employ any device, scheme or artifice to defraud; (2) to make any untrue statement of material fact or omit to make any such statement necessary to make the statements made not misleading; or (3) to engage in any act or practice that operates as a fraud or deceit upon any person. The new anti-market manipulation rule does not apply to activities that relate only to intrastate or other non-jurisdictional sales or gathering, but does apply to activities of gas pipelines and storage companies that provide interstate services, as well as otherwise non-jurisdictional entities to the extent the activities are conducted “in connection with” gas sales, purchases or transportation subject to FERC jurisdiction, which now includes the annual reporting requirements under Order 704. The anti-market manipulation rule and enhanced civil penalty authority reflect an expansion of FERC’s NGA enforcement authority.

FERC Market Transparency Rules.On December 26, 2007, FERC issued a final rule on the annual natural gas transaction reporting requirements, as amended by subsequent orders on rehearing (“Order 704”). Under Order 704, wholesale buyers and sellers of more than 2.2 million MMBtu of physical natural gas in the previous calendar year, including interstate and intrastate natural gas pipelines, natural gas gatherers, natural gas processors, natural gas marketers, and natural gas producers, are now required to report, on May 1 of each year beginning in 2009, aggregate volumes of natural gas purchased or sold at wholesale in the prior calendar year to the extent such transactions utilize, contribute to, or may contribute to the formation of price indices. It is the responsibility of the reporting entity to determine which individual transactions should be reported based on the guidance of Order 704. Order 704 also requires market participants to indicate whether they report prices to any index publishers, and if so, whether their reporting complies with FERC’s policy statement on price reporting.

Additional proposals and proceedings that might affect the natural gas industry are pending before Congress, FERC and the courts. We cannot predict the ultimate impact of these or the above regulatory changes to our natural gas operations. We do not believe that we would be affected by any such FERC action materially differently than similarly situated competitors.

Environmental, Health and Safety Regulation

General. Our operations are subject to stringent and complex federal, state, local and provincial laws and regulations governing environmental protection, health and safety, including the discharge of materials into the environment. These laws and regulations may, among other things:

These laws and regulations may also restrict the rate of oil and natural gas production below the rate that would otherwise be possible. The regulatory burden on the oil and gas industry increases the cost of doing business in the industry and consequently affects profitability. Additionally, Congress and federal and state agencies frequently revise environmental, health and safety laws and regulations, and any changes that result in more stringent and costly waste handling, disposal, cleanup and cleanupremediation requirements for the oil and gas industry could have a significant impact on our operating costs.

Some of the existing environmental, health and safety laws and regulations to which our business operations are subject include, among others, (i) regulations by the EPA and various state agencies regarding approved methods of disposal for certain hazardous and nonhazardous wastes; (ii) the Comprehensive Environmental Response, Compensation, and Liability Act and analogous state laws that regulatemay require the removal or remediation of previously disposed wastes (including wastes disposed of or released by prior owners or operators), property contamination (including groundwater contamination), and remedial plugging operations to prevent future contamination; (iii) the Clean Air Act and comparable state and local requirements, which may result in the gradual imposition of certainestablish pollution control requirements with respect to air emissions from the operations of the Company;our operations; (iv) the Oil Pollution Act of 1990, which contains numerous requirements relating to the prevention of and response to oil spills into waters of the United States; (v) the Federal Water Pollution Control Act, or the Clean Water Act, and analogous state laws which impose restrictions and strict controls with respect to the discharge of pollutants, including oil and other substances generated by our operations, into waters of the United States or state waters; (vi) the Resource Conservation and Recovery Act, which is the principal federal statute governing the treatment, storage and disposal of hazardous wastes and comparable state law pertaining to the handling of solid and hazardous wastes; (vii) the Safe Drinking Water Act and analogous state laws which impose requirements relating to our underground injection activities; (viii) the National Environmental Policy Act, which requires federal agencies, including the Department of Interior, to evaluate major agency actions that have the potential to significantly impact the environment; (ix) the federal Occupational Safety and Health Act and comparable state statutes which requiresrequire that we organize and/or disclose information about hazardous materials stored, used or produced in our operations and; (x) state regulations and statutes governing the handling, treatment, storage and disposal of naturally occurring radioactive material.

We have incurred in the past, and expect to incur in the future, capital and other expenditures related to environmental compliance. Such expenditures, however, are included within our overall capital and operating

budgets and are not separately itemized. Although we believe that our continued compliance with existing requirements will not have a material adverse impact on our financial condition and results of operations, we cannot assure you that the passage of more stringent laws or regulations in the future will not have a negative impact on our financial position or results of operations.

Employees

As of December 31, 2007,2008, we employed 332394 people, including 181209 employees in drilling and production, 4758 in financial and accounting, 3336 in land, 2128 in exploration, 1113 in reservoir engineering, 2839 in administrative and 11 in information technology. Our future success will depend partially on our ability to attract, retain and motivate qualified personnel. We are not a party to any collective bargaining agreements and have not experienced any strikes or work stoppages. We consider our relations with our employees to be satisfactory. From time to time weWe utilize the services of independent contractors to perform various field and other services.

Initial Public Offering

On May 14, 2007, the Companywe completed itsour initial public offering. In conjunction therewith, the Company affectedwe effected an 11 for 1 stock split by means of a stock dividend. All prior period share and per share information contained in this report have been retroactively restated to give effect to the stock split. On May 14, 2007, the Companywe amended its our

certificate of incorporation to, among other things, increase the number of authorized preferred shares to 25 million and common shares to 500 million. Prior to completion of theour initial public offering, the Company waswe were a subchapter S corporation and income taxes were payable by itsour shareholders. In connection with the public offering, the Companywe converted to a subchapter C corporation and recorded a charge to earnings in the second quarter of 2007 of $198.4 million to recognize deferred taxes at May 14, 2007. Thereafter, the Company haswe have provided for income taxes on income. SeeNotes to Consolidated Financial Statements—Note 1. Organization and Summary ofSignificant Accounting Policies—Pro forma information (unaudited) and Income taxes and Note 11.12. Shareholders’ Equityfor a complete discussion of the accounting for the various transactions resulting from theour initial public offering and of the pro forma information presented.

Company Contact Information

Our corporate internet web site iswww.contres.com. Through the investor relations section of our website, we make available our annual report on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K, and all amendments to those reports as soon as reasonably practicable after the report is filed with or furnished withto the Securities and Exchange Commission. For a current version of various corporate governance documents, including our Code of Ethics (as updated February 25, 2009), please see our website. Information contained at our website is not incorporated by reference into this report and you should not consider information contained at our website as part of this report.

We file periodic reports and proxy statements with the Securities and Exchange Commission (“SEC”). The public may read and copy any materials we file with the SEC at the SEC’s Public Reference Room at 100 F Street N.E., Washington, D.C. 20549. The public may obtain information about the operation of the Public Reference Room by calling the SEC at 1-800-SEC-0330. We file our reports with the SEC electronically. The SEC maintains an Internet site that contains reports, proxy and information statements, and other information regarding issuers that file electronically with the SEC. The address of this site is http://www.sec.gov.

Our principal executive offices are located at 302 N. Independence, Enid, Oklahoma 73701, and our telephone number at that address is (580) 233-8955.

Item 1A.

Risk Factors

You should carefully consider each of the risks described below, together with all of the other information contained in this report, before deciding to invest in shares of our common stock. If any of the following risks develop into actual events, our business, financial condition or results of operations could be materially adversely affected, the trading price of your shares could decline and you may lose all or part of your investment.

Risks Relating to the Oil and Natural Gas Industry and Our Business

A substantial or extended decline in oil and natural gas prices may adversely affect our business, financial condition or results of operations and our ability to meet our capital expenditure obligations and financial commitments.

The price we receive for our oil and natural gas production heavily influences our revenue, profitability, access to capital and future rate of growth. Oil and natural gas are commodities and, therefore, their prices are subject to wide fluctuations in response to relatively minor changes in supply and demand. Historically, the markets for oil and natural gas have been volatile. These markets will likely continue to be volatile in the future. The prices we receive for our production, and the levels of our production, depend on numerous factors beyond our control. These factors include the following:

Furthermore, the current worldwide financial and credit crisis has reduced the availability of liquidity and credit to fund the continuation and expansion of industrial business operations worldwide. The shortage of liquidity and credit combined with recent substantial losses in worldwide equity markets has lead to a worldwide economic recession. The slowdown in economic activity caused by such recession has reduced worldwide demand for energy and resulted in lower oil and natural gas prices. Oil prices declined from record high levels in early July 2008 of over $140 per Bbl to below $35 per Bbl in February 2009, while natural gas prices declined from over $13 per Mcf to approximately $4 per Mcf over the same period.

Lower oil and natural gas prices will reduce our cash flows and borrowing ability. For example, although our average realized price received for oil and natural gas was $77.66 per Boe for the year ended December 31, 2008, it was bolstered by record oil prices for the first half of the year. In the fourth quarter of 2008, our average realized price received for oil and natural gas declined to $38.80 per Boe. See “Our-”Our exploration, development and exploitation projects require substantial capital expenditures. We may be unable to obtain needed capital or financing on satisfactory terms, which could lead to a decline in our oil and natural gas reserves.” Lower oil and natural gas prices may also reduce the amount of oil and natural gas that we can produce economically.

Substantial decreases in oil and natural gas prices would render uneconomic a significant portion of our exploration, development and exploitation projects. This may result in our having to make significant downward adjustments to our estimated proved reserves. As a result, a substantial or extended decline in oil or natural gas prices may materially and adversely affect our future business, financial condition, results of operations, liquidity or ability to finance planned capital expenditures.

In addition, because our producing properties are geographically concentrated in the Rocky Mountain region, we are vulnerable to fluctuations in pricing in that area. In particular, 81%76% of our production during the fourth quarter of 20072008 was from the Rocky Mountain region. As a result of this concentration, we may be disproportionately exposed to the impact of regional supply and demand factors, transportation capacity constraints, curtailment of production or interruption of transportation of oil produced from the wells in these areas. Such factors can cause significant fluctuation in our realized oil and natural gas prices. For example, the company-wide difference between the average NYMEX oil price and our average realized oil price for the year

ended December 31, 20072008 was $8.85$9.50 per Bbl, whereas the company-wide difference between the NYMEX oil price and our realized oil price for the year ended December 31, 20062007 was $11.04$8.85 per Bbl.

Our exploration, development and exploitation projects require substantial capital expenditures. We may be unable to obtain needed capital or financing on satisfactory terms, which could lead to a decline in our oil and natural gas reserves.

The oil and natural gas industry is capital intensive. We make and expect to continue to make substantial capital expenditures in our business for the development, exploitation, production and acquisition of oil and natural gas reserves. Our cash flow used in investing activities was $930.8 million related to capital and exploration expenditures in 2008. Our budgeted capital expenditures for 2009 are expected to be approximately $275.0 million with $211.0 million allocated for drilling and completion operations. To date, these capital expenditures have been financed with cash generated by operations and through borrowings under our revolving credit facility. The actual amount and timing of our future capital expenditures may differ materially from our estimates as a result of, among other things, commodity prices, actual drilling results, the availability of drilling rigs and other services and equipment, and regulatory, technological and competitive developments. We expect to manage capital expenditures for 2009 to be inline with our cash flows from operations, and expect our capital expenditures during 2009 to be significantly lower than our 2008 capital expenditures due to our desire to cut back on spending due to the current economic crisis and steep drop in oil and natural gas prices. Continued weakness in commodity prices may result in a decrease in our actual capital expenditures. Conversely, a significant improvement in product prices could result in an increase in our capital expenditures. We intend to finance our future capital expenditures primarily through cash flow from operations and through borrowings under our revolving credit facility; however, our financing needs may require us to alter or increase our capitalization substantially through the issuance of debt or equity securities or the sale of assets. The issuance of additional debt may require that a portion of our cash flow from operations be used for the payment of interest and principal on our debt, thereby reducing our ability to use cash flow to fund working capital, capital expenditures and acquisitions. The issuance of additional equity securities could have a dilutive effect on the value of your common stock.

Our cash flow from operations and access to capital are subject to a number of variables, including:

If our revenues or the borrowing base under our revolving credit facility decrease as a result of lower oil or natural gas prices, operating difficulties, declines in reserves or for any other reason, we may have limited ability

to obtain the capital necessary to sustain our operations at current levels. If additional capital is needed, we may not be able to obtain debt or equity financing. If cash generated by operations or cash available under our revolving credit facility is not sufficient to meet our capital requirements, the failure to obtain additional financing could result in a curtailment of our operations relating to development of our prospects, which in turn could lead to a decline in our oil and natural gas reserves, and could adversely affect our business, financial condition and results of operations.

Drilling for and producing oil and natural gas are high risk activities with many uncertainties that could adversely affect our business, financial condition or results of operations.

Our future financial condition and results of operations will depend on the success of our exploitation, exploration, development and production activities. Our oil and natural gas exploration and production activities are subject to numerous risks beyond our control;control, including the risk that drilling will not result in commercially viable oil or natural gas production. Our decisions to purchase, explore, develop or otherwise exploit prospects or properties will depend in part on the evaluation of data obtained through geophysical and geological analyses, production data and engineering studies, the results of which are often inconclusive or subject to varying interpretations. For a discussion of the uncertainty involved in these processes, see “—Reserve estimates depend on many assumptions that may turn out to be inaccurate. Any material inaccuracies in these reserve estimates or underlying assumptions will materially affect the quantities and present value of our reserves.” Our cost of drilling, completing and operating wells is often uncertain before drilling commences.

Further, many factors may curtail, delay or cancel our scheduled drilling projects, including the following:

Reserve estimates depend on many assumptions that may turn out to be inaccurate. Any material inaccuracies in these reserve estimates or underlying assumptions will materially affect the quantities and present value of our reserves.

The process of estimating oil and natural gas reserves is complex. It requires interpretations of available technical data and many assumptions, including assumptions relating to current and future economic factors.conditions and commodity prices. Any significant inaccuracies in these interpretations or assumptions could materially affect our estimated quantities and present value of our reserves. See “Item 1. Business—Proved Reserves” for information about our estimated oil and natural gas reserves and the PV-10 and standardized measure of discounted future net cash flows as of December 31, 2007.2008.

In order to prepare our estimates, we must project production rates and timing of development expenditures. We must also analyze available geological, geophysical, production and engineering data. The extent, quality and reliability of this data can vary. The process also requires economic assumptions about matters such as oil and natural gas prices, drilling and operating expenses, capital expenditures, taxes and availability of funds.

Actual future production, oil and natural gas prices, revenues, taxes, development expenditures, operating expenses and quantities of recoverable oil and natural gas reserves will vary from our estimates. Any significant

variance could materially affect the estimated quantities and present value of our reserves. In addition, we may adjust estimates of proved reserves to reflect production history, results of exploration and development, prevailing oil and natural gas prices and other factors, many of which are beyond our control.

You should not assume that the present value of future net revenues from our proved reserves is the current market value of our estimated oil and natural gas reserves. In accordance with SEC requirements, we generally base the estimated discounted future net cash flows from our proved reserves on prices and costs on the date of the estimate. Actual future prices and costs may differ materially from those used in the present value estimate. If oil prices decline by $1.00 per Bbl, then our PV-10 as of December 31, 20072008 would decrease approximately $50$47 million. If natural gas prices decline by $0.10 per Mcf, then our PV-10 as of December 31, 20072008 would decrease approximately $9$8 million.

Our use of enhanced recovery methods creates uncertainties that could adversely affect our results of operations and financial condition.

One of our business strategies is to commercially develop unconventional oil and natural gas resource plays using enhanced recovery technologies. For example, we inject water and high-pressure air into formations on some of our properties to increase the production of oil and natural gas. The additional production and reserves attributable to the use of these enhanced recovery methods are inherently difficult to predict. If our enhanced recovery programs do not allow for the extraction of oil and natural gas in the manner or to the extent that we anticipate, our future results of operations and financial condition could be materially adversely affected.

Our development and exploitation projects require substantial capital expenditures. We may be unable to obtain needed capital or financing on satisfactory terms, which could lead to a decline in our oil and natural gas reserves.

The oil and natural gas industry is capital intensive. We make and expect to continue to make substantial capital expenditures in our business for the development, exploitation, production and acquisition of oil and natural gas reserves. Our cash flow used in investing activities was $486.4 million related to capital and exploration expenditures in 2007. Our budgeted capital expenditures for 2008 are expected to increase to approximately $616.0 million. To date, these capital expenditures have been financed with cash generated by operations and through borrowings from banks and, prior to our initial public offering, from our principal shareholder. The actual amount and timing of our future capital expenditures may differ materially from our estimates as a result of, among other things, actual drilling results, the availability of drilling rigs and other services and equipment, and regulatory, technological and competitive developments. We intend to finance our future capital expenditures primarily through cash flow from operations and through borrowings under our revolving credit facility; however, our financing needs may require us to alter or increase our capitalization substantially through the issuance of debt or equity securities. The issuance of additional debt may require that a portion of our cash flow from operations be used for the payment of interest and principal on our debt, thereby reducing our ability to use cash flow to fund working capital, capital expenditures and acquisitions. The issuance of additional equity securities could have a dilutive effect on the value of your common stock.

Our cash flow from operations and access to capital are subject to a number of variables, including:

If our revenues or the borrowing base under our credit facility decrease as a result of lower oil or natural gas prices, operating difficulties, declines in reserves or for any other reason, we may have limited ability to obtain the capital necessary to sustain our operations at current levels. If additional capital is needed, we may not be able to obtain debt or equity financing. If cash generated by operations or cash available under our revolving credit facility is not sufficient to meet our capital requirements, the failure to obtain additional financing could result in a curtailment of our operations relating to development of our prospects, which in turn could lead to a decline in our oil and natural gas reserves, and could adversely affect our business, financial condition and results of operations.

If oil and natural gas prices decrease, we may be required to take write-downs of the carrying values of our oil and natural gas properties.

Accounting rules require that we periodically review periodically the carrying value of our oil and natural gas properties for possible impairment. Based on specific market factors and circumstances at the time of prospective impairment reviews, and the continuing evaluation of development plans, production data, economics and other factors, we may be required to write down the carrying value of our oil and natural gas properties. A write-down constitutes a non-cash charge to earnings. We may incur impairment charges in the future, which could have a material adverse effect on our results of operations for the periods in which such charges are taken.

Unless we replace our oil and natural gas reserves, our reserves and production will decline, which would adversely affect our cash flows and results of operations.

Unless we conduct successful development, exploitation and exploration activities or acquire properties containing proved reserves, our proved reserves will decline as those reserves are produced. Producing oil and natural gas reservoirs generally are characterized by declining production rates that vary depending upon reservoir characteristics and other factors. Our future oil and natural gas reserves and production, and therefore our cash flow and results of operations, are highly dependent on our success in efficiently developing and exploiting our current reserves and economically finding or acquiring additional recoverable reserves. We may not be able to develop, exploit, find or acquire sufficient additional reserves to replace our current and future production. If we are unable to replace our current and future production, the value of our reserves will decrease, and our business, financial condition and results of operations would be adversely affected.

The unavailability or high cost of additional drilling rigs, equipment, supplies, personnel and oilfield services could adversely affect our ability to execute our exploration and development plans within our budget and on a timely basis.

Shortages or the high cost of drilling rigs, equipment, supplies, personnel or oilfield services could delay or cause us to incur significant expenditures that are not provided for in our capital budget, which could have a material adverse effect on our business, financial condition or results of operations.

We may incur substantial losses and be subject to substantial liability claims as a result of our oil and natural gas operations;operations. Additionally we may not be insured for, or our insurance may be inadequate to protect us against, these risks.

We are not insured against all risks. Losses and liabilities arising from uninsured and underinsured events could materially and adversely affect our business, financial condition or results of operations. Our oil and natural gas exploration and production activities are subject to all of the operating risks associated with drilling for and producing oil and natural gas, including the possibility of:

Any of these risks could adversely affect our ability to conduct operations or result in substantial losses to us as a result of:

We may elect not to obtain insurance if we believe that the cost of available insurance is excessive relative to the risks presented. In addition, pollution and environmental risks generally are not fully insurable. The occurrence of an event that is not fully covered by insurance could have a material adverse effect on our business, financial condition and results of operations.

Prospects that we decide to drill may not yield oil or natural gas in commercially viable quantities.

Prospects that we decide to drill that do not yield oil or natural gas in commercially viable quantities will adversely affect our resultresults of operations and financial condition. In this report, we describe some of our current prospects and our plans to explore those prospects. Our prospects are in various stages of evaluation, ranging from a prospect which is ready to drill to a prospect that will require substantial additional seismic data processing and interpretation. There is no way to predict in advance of drilling and testing whether any particular prospect will yield oil or natural gas in sufficient quantities to recover drilling or completion costs or to be economically viable. The use of seismic data and other technologies and the study of producing fields in the same area will not enable us to know conclusively prior to drilling whether oil or natural gas will be present or, if present, whether oil or natural gas will be present in commercial quantities. We cannot assure you that the analogies we draw from available data from other wells, more fully explored prospects or producing fields will be applicable to our drilling prospects.

Our identified drilling locations are scheduled out over several years, making them susceptible to uncertainties that could materially alter the occurrence or timing of their drilling.

Our management has specifically identified and scheduled drilling locations as an estimation of our future multi-year drilling activities on our existing acreage. These drilling locations represent a significant part of our growth strategy. Our ability to drill and develop these locations depends on a number of uncertainties, including oil and natural gas prices, the availability of capital, costs, drilling results, regulatory approvals and other factors. The North Dakota Bakken Shale and Arkoma Woodford projects comprise the majority of these drilling locations. Due to limited production history on the relatively few number of wells drilled in these projects, we are unable to predict with certainty the quantity of future production from wells to be drilled in these projects. If future drilling results in these projects do not establish sufficient reserves to achieve an economic return, we may curtail drilling in these projects. Because of these uncertainties, we do not know if the numerous potential drilling locations we have identified will ever be drilled or if we will be able to produce oil or natural gas from these or any other potential drilling locations. In addition, unless production is established within the spacing units covering the undeveloped acres on which some of the locations are identified, the leases for such acreage will expire. As of December 31, 2007,2008, we had 173,828, 182,802 and 188,689leases representing 152,105 net acres expiring in 2008, 2009, 221,522 net acres expiring in 2010, and 2010, respectively.360,123 net acres expiring in 2011. As such, our actual drilling activities may materially differ from those presently identified, which could adversely affect our business.

Market conditions or operational impediments may hinder our access to oil and natural gas markets or delay our production.

Market conditions or the unavailability of satisfactory oil and natural gas transportation arrangements may hinder our access to oil and natural gas markets or delay our production. The availability of a ready market for our oil and natural gas production depends on a number of factors, including the demand for and supply of oil

and natural gas and the proximity of reserves to pipelines and terminal facilities. Our ability to market our production depends in substantial part on the availability and capacity of gathering systems, pipelines and processing facilities owned and operated by third parties. Our failure to obtain such services on acceptable terms could materially harm our business. We may be required to shut in wells due to lack of a market or inadequacy or unavailability of crude oil or natural gas pipeline or gathering system capacity. In addition, if gas quality specifications for the third party natural gas pipelines with which we connect change so as to restrict our ability to transport natural gas, our access to natural gas markets could be impeded. If that were to occur, thenour production becomes shut in for any of these or other reasons, we would be unable to realize revenue from those wells until other arrangements were made to deliver the products to market.

We have been an early entrant into new or emerging plays; asplays. As a result, our drilling results in these areas are uncertain, and the value of our undeveloped acreage will decline if drilling results are unsuccessful.

While our costs to acquire undeveloped acreage in new or emerging plays have generally been less than those of later entrants into a developing play, our drilling results in these areas are more uncertain than drilling results in areas that are developed and producing. Since new or emerging plays have limited or no production history, we are unable to use past drilling results in those areas to help predict our future drilling results. As a result, our cost of drilling, completing and operating wells in these areas may be higher than initially expected, and the value of our undeveloped acreage will decline if drilling results are unsuccessful.

We are subject to complex federal, state, local, provincial and other laws and regulations that could adversely affect the cost, manner or feasibility of conducting our operations or expose us to significant liabilities.

Our oil and natural gas exploration, production and transportation operations are subject to complex and stringent laws and regulations. In order to conduct our operations in compliance with these laws and regulations, we must obtain and maintain numerous permits, approvals and certificates from various federal, state, local and provincial governmental authorities. We may incur substantial costs in order to maintain compliance with these

existing laws and regulations. In addition, our costs of compliance may increase if existing laws and regulations are revised or reinterpreted, or if new laws and regulations become applicable to our operations. Such costs could have a material adverse effect on our business, financial condition and results of operations.

Our business is subject to federal, state, local and provincial laws and regulations as interpreted and enforced by governmental authorities possessing jurisdiction over various aspects of the exploration for, and the production and transportation of, oil and natural gas. Failure to comply with such laws and regulations, as interpreted and enforced, could have a material adverse effect on our business, financial condition and results of operations. See “Regulation of the Oil and Natural Gas Industry” for a description of the laws and regulations that affect us.

Strict, joint and several liabilities may be imposed under certain environmental laws, which could cause us to become liable for the conduct of others or for consequences of our own actions that were in compliance with all applicable laws at the time those actions were taken. In addition, claims for damages to persons or property, including natural resources, may result from our operations.

New laws, regulations or enforcement policies could be more stringent and impose unforeseen liabilities or significantly increase compliance costs. If we were not able to recover the resulting costs through insurance or increased revenues, our business, financial condition or results of operations could be adversely affected.

Should we fail to comply with all applicable FERC administered statutes, rules, regulations and orders, we could be subject to substantial penalties and fines.

Under the EP Act 2005, FERC has civil penalty authority under the NGA to impose penalties for current violations of up to $1 million per day for each violation and disgorgement of profits associated with any violation. While our systems have not been regulated by FERC as a natural gas company under the NGA, FERC has adopted regulations that may subject certain of our otherwise non-FERC jurisdictional facilities to FERC annual reporting and daily scheduled flow and capacity posting requirements. Additional rules and legislation pertaining to those and other matters may be considered or adopted by FERC from time to time. Failure to comply with those regulations in the future could subject Continental to civil penalty liability.

Our operations may incur substantial liabilities in connection with climate change legislation and regulatory initiatives.

Recent scientific studies have suggested that emissions of certain gases, commonly referred to as “greenhouse gases” and including carbon dioxide and methane, may be contributing to warming of the Earth’s atmosphere. In response to such studies, the U.S. Congress is considering legislation to reduce emissions of greenhouse gases and more than one-third of the states, either individually or through multi-state initiatives, already have begun implementing legal measures to reduce emissions of greenhouse gases. Also, the U.S. Supreme Court’s holding in its 2007 decision,Massachusetts, et al. v. EPA, that carbon dioxide may be regulated as an “air pollutant” under the federal Clean Air Act could result in future regulation of greenhouse gas emissions from stationary sources, even if Congress does not adopt new legislation specifically addressing emissions of greenhouse gases. In July 2008, EPA released an “Advance Notice of Proposed Rulemaking” regarding possible future regulation of greenhouse gas emissions under the Clean Air Act. Although the notice did not propose any specific, new regulatory requirements for greenhouse gases, it indicates that federal regulation of greenhouse gas emissions could occur in the near future. Although it is not possible at this time to predict how legislation or new regulations that may be adopted to address greenhouse gas emissions would impact our business, any such future laws and regulations could result in increased compliance costs or additional operating restrictions, and could have an adverse effect on our business or demand for the oil and natural gas we produce.

Competition in the oil and natural gas industry is intense, making it more difficult for us to acquire properties, market oil and natural gas and secure trained personnel.

Our ability to acquire additional prospects and to find and develop reserves in the future will depend on our ability to evaluate and select suitable properties and to consummate transactions in a highly competitive environment for acquiring properties, marketing oil and natural gas and securing trained personnel. Also, there is substantial competition for capital available for investment in the oil and natural gas industry. Many of our

competitors possess and employ financial, technical and personnel resources substantially greater than ours. Those companies may be able to pay more for productive oil and natural gas properties and exploratory prospects and to evaluate, bid for and purchase a greater number of properties and prospects than our financial or personnel resources permit. In addition, companies may be able to offer better compensation packages to attract and retain qualified personnel than we are able to offer. The cost to attract and retain qualified personnel has increased over the past three years due to competition and may increase substantially in the future. We may not be able to compete successfully in the future in acquiring prospective reserves, developing reserves, marketing hydrocarbons, attracting and retaining quality personnel and raising additional capital, which could have a material adverse effect on our business.

The loss of senior management or technical personnel could adversely affect operations.

We depend on the services of our senior management and technical personnel. The loss of the services of our senior management or technical personnel, including Harold G. Hamm, our Chairman, President and Chief Executive Officer, could have a material adverse effect on our operations. We do not maintain, nor do we plan to obtain, any insurance against the loss of any of these individuals.

Terrorist attacks aimed at our energy operations could adversely affect our business.

The continued threat of terrorism and the impact of military and other government action have led and may lead to further increased volatility in prices for oil and natural gas and could affect these commodity markets or financial markets used by us. In addition, the U.S. government has issued warnings that energy assets may be a future target of terrorist organizations. These developments have subjected our oil and natural gas operations to increased risks. Any future terrorist attack on our facilities, those of our customers and, in some cases, those of other energy companies, could have a material adverse effect on our business.

Seasonal weather conditions and lease stipulations adversely affect our ability to conduct drilling activities in some of the areas where we operate.

Oil and natural gas operations in the Rocky Mountains are adversely affected by seasonal weather conditions and lease stipulations designed to protect various wildlife. In certain areas, including parts of Montana, North Dakota, South Dakota, Utah and Wyoming, drilling and other oil and natural gas activities can only be conducted during the spring and summer months. This limits our ability to operate in those areas and can intensify competition during those months for drilling rigs, oilfield equipment, services, supplies and qualified personnel, which may lead to periodic shortages. These constraints and the resulting shortages or high costs could delay our operations and materially increase our operating and capital costs.

Our revolving credit facility contains certain covenants that may inhibit our ability to make certain investments, incur additional indebtedness and engage in certain other transactions, which could adversely affect our ability to meet our future goals.

Our revolving credit facility includes certain covenants that, among other things, restrict:

Our revolving credit facility requires us to maintain certain financial ratios, such as leverage ratios. All of these restrictive covenants may restrict our ability to expand or pursue our business strategies. Our ability to

comply with these and other provisions of our revolving credit facility may be impacted by changes in economic or business conditions, results of operations or events beyond our control. The breach of any of these covenants could result in a default under our revolving credit facility, in which case, depending on the actions taken by the lenders there underthereunder or their successors or assignees, such lenders could elect to declare all amounts borrowed under our revolving credit facility, together with accrued interest, to be due and payable. If we were unable to repay such borrowings or interest, our lenders could proceed against their collateral. If the indebtedness under our revolving credit facility were to be accelerated, our assets may not be sufficient to repay in full such indebtedness.

Increases in interest rates could adversely affect our business.

We are exposed to changesOur business and operating results can be harmed by factors such as the availability, terms of and cost of capital, increases in interest rates or a reduction in credit rating. These changes could cause our cost of doing business to increase, limit our ability to pursue acquisition opportunities, reduce cash flow used for drilling and place us at a competitive disadvantage. For example, as a result of February 23, 2009, outstanding borrowings outstanding under our revolving credit facility. At February 29, 2008, our outstanding borrowingsfacility were $222.0$474.4 million and the impact of a 1% increase in interest rates on this amount of debt would result in increased interest expense of approximately $2.2$4.7 million and a $1.4$2.9 million decrease in our net income. Recent and continuing disruptions and volatility in the global financial markets may lead to a contraction in credit availability impacting our ability to finance our operations. We require continued access to capital. A significant reduction in cash flows from operations or the availability of credit could materially and adversely affect our ability to achieve our planned growth and operating results.

The continuing financial crisis may impact our business and financial condition. We may not be able to obtain funding in the capital markets on terms we find acceptable, or obtain funding under our current revolving credit facility because of the deterioration of the capital and credit markets and our borrowing base.

The current credit crisis and related turmoil in the global financial systems have had an impact on our business and our financial condition, and we may face challenges if economic and financial market conditions do not improve. Historically, we have used our cash flow from operations and borrowings under our revolving credit facility to fund our capital expenditures and have relied on the capital markets and asset monetization transactions to provide us with additional capital for large or exceptional transactions. A continuation of the economic crisis could further reduce the demand for oil and natural gas and continue to put downward pressure on the prices for oil and natural gas, which have declined significantly since reaching historic highs in July 2008. These price declines have negatively impacted our revenues and cash flows.

We have an existing revolving credit facility with lender commitments totaling $672.5 million. In the future, we may not be able to access adequate funding under our bank credit facilities as a result of (i) a decrease in our borrowing base due to the outcome of a subsequent borrowing base redetermination, or (ii) an unwillingness or inability on the part of our lending counterparties to meet their funding obligations. The recent declines in commodity prices, or a continuing decline in those prices, could result in a determination to lower the borrowing base in the future and, in such case, we could be required to repay any indebtedness in excess of the borrowing base. The turmoil in the financial markets has adversely impacted the stability and solvency of a number of large global financial institutions.

The current credit crisis makes it difficult to obtain funding in the public and private capital markets. In particular, the cost of raising money in the debt and equity capital markets has increased substantially while the availability of funds from those markets generally has diminished significantly. Also, as a result of concerns about the general stability of financial markets and the solvency of specific counterparties, the cost of obtaining money from the credit markets has increased as many lenders and institutional investors have increased interest rates, imposed tighter lending standards, refused to refinance existing debt at maturity at all or on terms similar to existing debt or at all, and reduced and, in some cases, ceased to provide any new funding.

The credit crisis also has impacted the level of activity in the oil and natural gas property sales market. The lack of available credit and access to capital has limited and will likely continue to limit the parties interested in any proposed asset transactions and will likely reduce the values we could realize in those transactions.

Due to these factors, we cannot be certain that funding, if needed, will be available to the extent required and on acceptable terms. If we are unable to access funding when needed on acceptable terms, we may not be able to fully implement our business plans, complete new property acquisitions to replace our reserves, take advantage of business opportunities, respond to competitive pressures, or refinance our debt obligations as they come due, any of which could have a material adverse effect on our operations and financial results.

The inability of our significant customers to meet their obligations to us may adversely affect our financial results.

Our principal exposures to credit risk are through joint interest receivables ($156.6 million at December 31, 2008) and the sale of our oil and natural gas production ($72.4 million in receivables at December 31, 2008), which we market to energy marketing companies, refineries and affiliates. Joint interest receivables arise from billing entities who own partial interest in the wells we operate. These entities participate in our wells primarily based on their ownership in leases on which we wish to drill. We can do very little to choose who participates in our wells. We are also subject to credit risk due to concentration of our oil and natural gas receivables with several significant customers. The two largest purchaserspurchaser of our oil and natural gas, during the twelve months ended December 31, 20072008, accounted for 20% and 14%44% of our total oil and natural gas sales revenues. We do not require our customers to post collateral. The inability or failure of our significant customers to meet their obligations to us or their insolvency or liquidation may adversely affect our financial results.

Our derivative activities could result in financial losses or could reduce our earnings.

To achieve a more predictable cash flow and to reduce our exposure to adverse fluctuations in the prices of oil and natural gas, we on occasion, enter into derivative instruments for a portion of our oil and/or natural gas production, including collars and price-fix swaps. In July 2007, we entered into fixed price swaps covering 10,000 barrels of oil per day for August 2007 through April 2008 at a price of $72.90 per barrel. We havedid not designateddesignate any of our derivative instruments as hedges for accounting purposes and willdid record all derivative instruments on our balance sheet at fair value. Changes in the fair value of our derivative instruments will bewere recognized in current earnings. Accordingly, our earnings may fluctuate significantly as a result of changes in fair value of our derivative instruments.

Derivative instruments also expose us to the risk of financial loss in some circumstances, including when:

In addition, these types of derivative arrangements limit the benefit we would receive from increases in the prices for oil and natural gas.

We may be subject to risks in connection with acquisitions.

The successful acquisition of producing properties requires an assessment of several factors, including:

The accuracy of these assessments is inherently uncertain. In connection with these assessments, we perform a review of the subject properties that we believe to be generally consistent with industry practices. Our review will not reveal all existing or potential problems nor will it permit us to become sufficiently familiar with the properties to fully assess their deficiencies and capabilities. Inspections may not always be performed on every well, and environmental problems are not necessarily observable even when an inspection is undertaken. Even when problems are identified, the seller may be unwilling or unable to provide effective contractual protection against all or part of the problems. We often are not entitled to contractual indemnification for environmental liabilities and acquire properties on an “as is” basis.

Our business depends on oil and natural gas transportation facilities, most of which are owned by third parties.

The requirementsmarketability of beingour oil and natural gas production depends in part on the availability, proximity and capacity of pipeline systems owned by third parties. The unavailability of, or lack of, available capacity on these systems and facilities could result in the shut-in of producing wells or the delay, or discontinuance of, development plans for properties. Although we have some contractual control over the transportation of our product, material changes in these business relationships could materially affect our operations. We generally do not purchase firm transportation on third party facilities and therefore, our production transportation can be interrupted by those having firm arrangements. Federal and state regulation of oil and natural gas production and transportation, tax and energy policies, changes in supply and demand, pipeline pressures, damage to or destruction of pipelines and general economic conditions could adversely affect our ability to produce, gather and transport oil and natural gas.

The disruption of third-party facilities due to maintenance and/or weather could negatively impact our ability to market and deliver our products. We have no control over when or if such facilities are restored or what prices will be charged. A total shut-in of production could materially affect us due to a public company, including compliance with the reporting requirementslack of cash flow, and if a substantial portion of the Exchange Act and the requirements of the Sarbanes-Oxley Act, may strain our resources, increase our costs and distract management; and we mayproduction is hedged at lower than market prices, those financial hedges would have to be unable to comply with these requirements in a timely or cost effective manner.

As a new public company with listed equity securities, we will need to comply with new laws, regulations and requirements, certain corporate governance provisions of the Sarbanes-Oxley Act of 2002, related regulations of the SEC and the requirements of the New York Stock Exchange (NYSE) with which we were not required to comply as a private company. Complying with these statutes, regulations and requirements will occupy a significant amount of time of our board of directors and management and will increase our costs and expenses. We will need to:

In addition, we also expect that being a public company subject to these rules and regulations will require us to accept less director and officer liability insurance coverage than we desire or to incur substantial costs to obtain coverage. These factors could also make it more difficult for us to attract and retain qualified members of our board of directors, particularly to serve on our audit committee, and qualified executive officers. As a result, compliance with the requirements of the Sarbanes-Oxley Act could have a material adverse effect on our business.paid from borrowings absent sufficient cash flow.

Our Chairman and Chief Executive Officer ownowns approximately 72.8% of our outstanding common stock, giving him influence and control in corporate transactions and other matters, including a sale of our company.

As of February 29, 2008,23, 2009, Harold G. Hamm, our Chairman, President and Chief Executive Officer, beneficially owns 123,140,608123,458,708 shares of our outstanding common stock representing approximately 72.8% of our outstanding common stock.shares. As a result, Mr. Hamm will continue to be our controlling shareholder and will continue to be able to

control the election of our directors, determine our corporate and management policies and determine, without the consent of our other shareholders, the outcome of certain corporate transactions or other matters submitted to our shareholders for approval, including potential mergers or acquisitions, asset sales and other significant corporate transactions. As controlling shareholder, Mr. Hamm could cause, delay or prevent a change of control of our company.Company. The interests of Mr. Hamm may not coincide with the interests of other holders of our common stock.

Several affiliated companies controlled by Mr. Hamm provide oilfield, gathering and processing, marketing and other services to us. We expect these transactions will continue in the future and may result in conflicts of interest between Mr. Hamm’s affiliated companies and us. We can provide no assurance that any such conflicts will be resolved in our favor.

There were no unresolved Securities and Exchange Commission staff comments at December 31, 2007.2008.

The information required by Item 2 is contained in Item“Item 1. Business—Oil and Gas Operations.Operations”.

We are not a party to any material pending legal proceedings, other than ordinary course litigation incidental to our business. While the ultimate outcome and impact of any proceeding cannot be predicted with certainty, our management believes that the resolution of any proceeding will not have a material adverse effect on our financial condition or results of operations.

There were no matters submitted to a vote of security holders during the fourth quarter of 2007.2008.

Part II

Our common stock is listed on the New York Stock Exchange and trades under the symbol “CLR.” The following table sets forth quarterly high and low sales prices since May 14, 2007, when we became a publicly traded company, and cash dividends declared for each quarter of the previous two years.

We declared cash dividends to our shareholders of record for tax purposes and, subject to forfeiture, to holders of unvested restricted stock during such time as we were a subchapter S corporation. On January 10, 2007, we declared a cash dividend of approximately $18.8 million to our shareholders for tax purposes and, subject to forfeiture, to holders of unvested restricted stock. On January 31, 2007, we paid $18.7 million of the dividend declared. On March 6, 2007, we declared a cash dividend of approximately $33.3 million payable in April 2007 to our shareholders of record as of March 15, 2007, for tax purposes and, subject to forfeiture, to holders of unvested restricted stock. In connection with the completion of our offering on May 14, 2007, we converted from a subchapter S corporation to a subchapter C corporation, and we do not anticipate paying any additional cash dividends on our common stock in the foreseeable future. As of February 29, 2008,23, 2009, the number of record holders of our common stock was 35.54. Management believes, after inquiry, that the number of beneficial owners of our common stock is approximately 12,500.28,000. On February 29, 2008,23, 2009, the last reported sales price of our Common Stock, as reported on the NYSE, was $28.08$15.18 per share.

The following table summarizes our purchases of our common stock during the fourth quarter of 2007:2008:

All shares purchased above represent shares issued pursuant to stock option exercises or restricted stock grants that were surrendered to cover taxes required to be withheld. The CompanyWe paid the amounts above to the Internal Revenue Service for the required withholding. SeeNotes to Consolidated Financial Statements—Note 12.13. Stock Compensation.

Performance Graph

The performance graph shown belowinformation provided in this section is being furnished pursuant to, applicable rulesand not filed with, the SEC. As such, this information is neither subject to Regulation 14A or 14C nor to the liabilities of Section 18 of the SEC.Securities Exchange Act of 1934, as amended. As required by these rules, the performance graph was prepared based upon the following assumptions:

Our peer group is comprised of Bill Barrett Corporation, Denbury Resources, Inc., Encore Acquisition Company, Quicksilver Resources, Inc., Range Resources Corp., Southwestern Energy Company and St. Mary Land and Exploration Company. We selected these companies because they are publicly traded exploration and production companies similar in size and operations to us.

Item 6.

Selected Financial Data

This section presents our selected historical and pro forma consolidated financial data. The selected historical consolidated financial data presented below is not intended to replace our historical consolidated financial statements.

The following historical consolidated financial data, as it relates to each of the fiscal years ended December 31, 20032004 through 2007,2008, has been derived from our audited historical consolidated financial statements for such periods. You should read the following selected historical consolidated financial data in connection with “Management’s Discussion and Analysis of Financial Condition and Results of Operation” and our historical consolidated financial statements and related notes included elsewhere in this report. The selected historical consolidated results are not necessarily indicative of results to be expected in future periods.