CONTINENTAL RESOURCES, INC - Annual Report: 2010 (Form 10-K)

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UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-K

(Mark One)

For the fiscal year ended December 31, 2010

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 Act:

Securities registered pursuant to Section 12(g) of the 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  ¨

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 whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).    Yes   x    No  ¨

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K (§229.405 of this chapter) 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 the definitions of “large accelerated filer”, “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act. (Check one):

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

The aggregate market value of the voting and non-voting common equity held by non-affiliates of the registrant as of June 30, 2010 was approximately $1.4 billion, based upon the closing price of $44.62 per share as reported by the New York Stock Exchange on such date.

As of February 18, 2011, the registrant had 170,405,395 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 in 2011, which will be filed with the Securities and Exchange Commission within 120 days after the end of the fiscal year, are incorporated by reference into Part III of this Form 10-K.

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Glossary of Crude Oil and Natural Gas Terms

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

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

“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.

“Boe” Barrels of crude oil equivalent, with six thousand cubic feet of natural gas being equivalent to one barrel of crude oil based on the average equivalent energy content of the two commodities.

“Btu” British thermal unit.

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

“Conventional play” An area that is believed to be capable of producing crude oil and natural gas occurring in discrete accumulations in structural and stratigraphic traps.

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

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

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

“Dry hole” Exploratory or development well that does not produce crude oil and/or natural gas in economically producible quantities.

“ECO-Pad ^TM” A Continental Resources Inc. trademark which describes a well site layout approved by the North Dakota Industrial Commission which allows for drilling four wells from a single pad resulting in less environmental impact and lower drilling and completion costs.

“Enhanced recovery” The recovery of crude 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” A well drilled to find a new field or to find a new reservoir in a field previously found to be productive of crude oil or natural gas in another 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 differs from nearby rock.

“Held by production” or “HBP” Refers to a mineral lease in which an entity is allowed to operate a property as long as the property produces a minimum paying quantity of crude oil or natural gas.

“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.

“Injection well” A well into which liquids or gases are injected in order to “push” additional crude oil or natural gas out of underground reservoirs and into the wellbores of producing wells. Typically considered an enhanced recovery process.

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

“MBoe” One thousand Boe.

“Mcf” One thousand cubic feet of natural gas.

“Mcfe” One thousand cubic feet of natural gas equivalent, with one barrel of crude oil being equivalent to six Mcf of natural gas based on the average equivalent energy content of the two commodities.

“MMBoe” One million Boe.

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“MMBtu” One million British thermal units.

“MMcf” One million cubic feet of natural gas.

“MMcfe” One million cubic feet of natural gas equivalent, with one barrel of crude oil being equivalent to six Mcf of natural gas based on the average equivalent energy content of the two commodities.

“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 a 50% interest in 100 acres owns 50 net acres.

“Play” A term applied to a portion of the exploration and production cycle following the identification by geologists and geophysicists of areas with potential crude oil and natural gas reserves.

“Productive 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.

“Prospect” A potential geological feature or formation which geologists and geophysicists believe may contain hydrocarbons. A prospect can be in various stages of evaluation, ranging from a prospect that has been fully evaluated and is ready to drill to a prospect that will require substantial additional seismic data processing and interpretation.

“Proved reserves” The quantities of crude oil and natural gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible from a given date forward, from known reservoirs and under existing economic conditions, operating methods, and government regulations prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain.

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

“Proved undeveloped reserves (“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.

“PV-10” When used with respect to crude oil and natural gas reserves, PV-10 represents 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 Securities and Exchange Commission (“SEC”). PV-10 is not a financial 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 the Company’s crude oil and natural gas properties. The Company 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.

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

“Royalty interest” Refers to the ownership of a percentage of the resources or revenues that are produced from a crude oil or natural gas property. A royalty interest owner does not bear any of the exploration, development, or operating expenses associated with drilling and producing a crude oil or natural gas property.

“Spacing” The distance between wells producing from the same reservoir. Spacing is often expressed in terms of acres (e.g., 640-acre spacing) and is often established by regulatory agencies.

“Standardized measure” Discounted future net cash flows estimated by applying the 12-month unweighted arithmetic average of the first-day-of-the-month commodity prices for the period January to December (for year-end 2010 and 2009) or year-end prices (for 2008 and prior) 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 crude oil and natural gas properties. Future net cash inflows after income taxes are discounted using a 10% annual discount rate.

“Step-out well” or “Step outs” A well drilled beyond the proved boundaries of a field to investigate a possible extension of the field.

“3D (three dimensional seismic) defined locations” Locations that have been subjected to 3D seismic testing. We typically use 3D seismic testing to evaluate reservoir presence and/or continuity. We do not typically evaluate reservoir productivity using 3D seismic technology.

“3D seismic” Seismic surveys using an instrument to send sound waves into the earth and collect data to help geophysicists define the underground configurations. 3D seismic provides three-dimensional pictures.

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“Unconventional play” An area that is believed to be capable of producing crude oil and natural gas occurring in accumulations that are regionally extensive, but require recently developed technologies to achieve profitability. These areas tend to have low permeability and may be closely associated with source rock as is the case with gas shale, tight oil and gas sands and coalbed methane.

“Undeveloped acreage” Lease acreage on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of crude oil and natural gas.

“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 a crude oil reservoir to “push” additional crude oil out of the reservoir rock and into the wellbores of producing wells. Typically an enhanced recovery process.

“Wellbore” The hole drilled by the bit that is equipped for crude oil or natural 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 crude oil, natural 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

Certain statements and information in this report may constitute “forward-looking statements” within the meaning of the Private Securities Litigation Reform Act of 1995. All statements other than statements of historical fact included in this report are forward-looking statements. When used in this report, the words “could,” “may,” “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. Forward-looking statements are based on the Company’s current expectations and assumptions about future events and currently available information as to the outcome and timing of future events. When considering forward-looking statements, you should keep in mind the risk factors and other cautionary statements described under the heading Item 1A. Risk Factors included in this report.

Without limiting the generality of the foregoing, certain statements incorporated by reference, if any, or included in this report constitute forward-looking statements.

Forward-looking statements may include statements about our:

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We caution you that these forward-looking statements are subject to all of the risks and uncertainties, most of which are difficult to predict and many of which are beyond our control, incident to the exploration for, and the development, production, and sale of, crude oil and natural gas. These risks include, but are not limited to, commodity price volatility, inflation, lack of availability of drilling and production equipment and services, environmental risks, drilling and other operating risks, regulatory changes, the uncertainty inherent in estimating crude oil and natural gas reserves and in projecting future rates of production, cash flows and access to capital, the timing of development expenditures, and the other risks described under Item 1A. Risk Factors in this report, registration statements filed from time to time with the SEC, and other announcements we make from time to time.

Readers are cautioned not to place undue reliance on forward-looking statements, which speak only as of the date hereof. Should one or more of the risks or uncertainties described in this report occur, or should underlying assumptions prove incorrect, our actual results and plans could differ materially from those expressed in any forward-looking statements. All forward-looking statements are expressly qualified in their entirety by this cautionary statement. This cautionary statement should also be considered in connection with any subsequent written or oral forward-looking statements that we or persons acting on our behalf may issue.

Except as otherwise required by applicable law, we disclaim any duty to update any forward-looking statements to reflect events or circumstances after the date of this report.

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Part I

You should read this entire report carefully, including the risks described under Item 1A. 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 “the Company” refer to Continental Resources, Inc. and its subsidiary.

Beginning in 2009, we changed our reporting regions from Rockies, Mid-Continent and Gulf Coast to North, South and East. The North region consists of properties north of Kansas and west of the Mississippi river and includes North Dakota Bakken, Montana Bakken, the Red River units and the Niobrara play in Colorado and Wyoming. The South region includes Kansas and all properties south of Kansas and west of the Mississippi river including the Arkoma Woodford and Anadarko Woodford plays in Oklahoma. The East region contains properties east of the Mississippi river including the Illinois Basin and Michigan.

General

We are an independent crude oil and natural gas exploration and production company with operations in the North, South and East regions of the United States. We were originally formed in 1967 to explore for, develop and produce crude oil and natural gas properties. Through 1993, our activities and growth remained focused primarily in Oklahoma. In 1993, we expanded our activity into the North region. Approximately 70% of our estimated proved reserves as of December 31, 2010 are located in the North region. We completed an initial public offering of our common stock in 2007, and our common stock trades on the New York Stock Exchange 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 allows us to economically develop and produce crude oil and natural gas reserves from unconventional formations. As a result of these efforts, we have grown substantially through the drill bit, adding 287.0 MMBoe of proved crude oil and natural gas reserves through extensions and discoveries from January 1, 2006 through December 31, 2010 compared to 3.0 MMBoe added through proved reserve acquisitions during that same period.

As of December 31, 2010, our estimated proved reserves were 364.7 MMBoe, with estimated proved developed reserves of 140.4 MMBoe, or 38% of our total estimated proved reserves. Crude oil comprised 62% of our total estimated proved reserves as of December 31, 2010. For the year ended December 31, 2010, we generated crude oil and natural gas revenues of $948.5 million and operating cash flows of $653.2 million. For the year and quarter ended December 31, 2010, daily production averaged 43,318 Boe per day and 48,034 Boe per day, respectively. This represents growth of 16% and 27% as compared to the year and quarter ended December 31, 2009, when daily production averaged 37,324 Boe per day and 37,747 Boe per day, respectively.

The following table summarizes our total estimated proved reserves, PV-10 and net producing wells as of December 31, 2010, average daily production for the three months ended December 31, 2010 and the reserve-to-production index in our principal regions. Our reserve estimates as of December 31, 2010 are based primarily on a reserve report prepared by our independent reserve engineers, Ryder Scott Company, L.P (“Ryder Scott”). In preparing its report, Ryder Scott evaluated properties representing approximately 94% of our PV-10, 97% of our proved crude oil reserves, and 94% of our proved natural gas reserves as of December 31, 2010. Our internal technical staff evaluated the remaining properties. Our estimated proved reserves and related future net revenues, PV-10 and Standardized Measure at December 31, 2010 were determined using the 12-month unweighted arithmetic average of the first-day-of-the-month commodity prices for the period of January 2010 through December 2010, without giving effect to derivative transactions, and were held constant throughout the life of the properties. These prices were $79.43 per Bbl for crude oil and $4.38 per MMBtu for natural gas ($71.92 per Bbl for crude oil and $5.07 per Mcf for natural gas net of location and quality differentials).

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The following table provides additional information regarding our key development areas as of December 31, 2010 and the budgeted amounts we plan to spend on exploratory and development drilling, capital workovers, and facilities in 2011:

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 crude 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, 2010, crude oil comprises 62% of our total proved reserves and 75% of our 2010 annual production. Although we do pursue liquids-rich natural gas opportunities, such as the Anadarko Woodford shale play in Oklahoma, that have the potential to improve the overall economics of our development projects, we continue to believe that crude oil valuations will be superior to natural gas valuations on a relative Btu basis.

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Growth Through Low-Cost Drilling. Substantially all of our annual capital expenditures are invested in drilling projects and acreage acquisitions. From January 1, 2006 through December 31, 2010, proved crude oil and natural gas reserve additions through extensions and discoveries were 287.0 MMBoe compared to 3.0 MMBoe of proved reserve acquisitions.

Internally Generated Prospects. Although we evaluate strategic acquisitions periodically, 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 later entrants into a developing play.

Focus on Unconventional Crude Oil and Natural Gas Resource Plays. Our experience with horizontal drilling, advanced fracture stimulation and enhanced recovery technologies allows us to commercially develop unconventional crude oil and natural gas resource reservoirs, such as the Red River B dolomite, Bakken shale and Oklahoma Woodford shale formations. Production rates in the Red River units also have been increased through the use of enhanced recovery technologies. Our production from the Red River units, the Bakken field, and the Oklahoma Woodford shale comprised approximately 13,961 MBoe, or 88%, of our total crude oil and natural gas production during the year ended December 31, 2010.

Acquire Significant Acreage Positions in New or Developing Plays. In addition to the 1,006,391 net undeveloped acres held in the Montana and North Dakota Bakken shale, Colorado and Wyoming Niobrara shale and Oklahoma Woodford shale fields, we held 364,044 net undeveloped acres in other crude oil and natural gas plays as of December 31, 2010. Our technical staff is focused on identifying and testing new unconventional crude oil and natural gas resource plays where significant reserves could be developed if economically producible volumes 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 1,370,435 net undeveloped and 518,333 net developed acres as of December 31, 2010. Approximately 83% of the undeveloped acres are located within unconventional resource plays including, but not limited to, the Bakken shale in North Dakota and Montana, the Woodford shale in Oklahoma and the Niobrara shale in Colorado and Wyoming. The balance of the undeveloped acreage is located in conventional plays including 3D-defined locations for the Trenton-Black River of Michigan, Red River of Montana and North Dakota, Lodgepole of 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 1,000 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 7 high pressure air injection (“HPAI”) floods.

Control Operations Over a Substantial Portion of Our Assets and Investments. As of December 31, 2010, we operated properties comprising 88% 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 crude oil and natural gas industry. Our Chief Executive Officer, Harold G. Hamm, began his career in the crude oil and natural gas industry in 1967. Our 7 senior officers have an average of 30 years of crude oil and natural gas industry experience. Additionally, our technical staff, which includes 40 petroleum engineers, 22 geoscientists and 19 landmen, has an average of 16 years experience in the industry.

Strong Financial Position. As of February 18, 2011, we had outstanding borrowings under our revolving credit facility of approximately $95.0 million and available borrowing capacity of $652.6 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 2011 capital expenditures budget has been established based on our current expectation of available cash flows from operations and availability under our revolving credit facility. Should expected available cash flows from operations materially vary from expectations, we believe our credit facility has sufficient availability to fund any deficit or that we can reduce our capital expenditures to be in line with cash flows from operations.

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Crude Oil and Natural Gas Operations

In December 2008, the SEC adopted new rules related to modernizing reserve calculation and disclosure requirements for crude oil and natural gas companies that became effective prospectively for annual reporting periods ending on or after December 31, 2009. The new rules, which we initially adopted for the year ended December 31, 2009, expanded the definition of crude oil and natural gas producing activities to include the extraction of saleable hydrocarbons from oil sands, shale, coal beds or other nonrenewable natural resources that are intended to be upgraded into synthetic oil or natural gas, and activities undertaken with a view to such extraction. The use of new technologies is now permitted in the determination of proved reserves if those technologies have been demonstrated empirically to lead to reliable conclusions about reserve volumes. The revised rules allow producers to report additional undrilled locations beyond one offset on each side of a producing well when there is reasonable certainty of economic producibility. Other definitions and terms were revised, including the definition of proved reserves, which was revised to indicate that entities must use the unweighted average of the first-day-of-the-month commodity prices over the preceding 12-month period, rather than the year-end price, when estimating whether reserve quantities are economical to produce. Likewise, the 12-month average price is now used to calculate reserves used in computing depreciation, depletion and amortization. Another significant provision of the new rules is a general requirement that, subject to limited exceptions, proved undeveloped reserves may only be booked if they relate to wells scheduled to be drilled within five years of the date of booking.

The initial application in 2009 of new rules related to modernizing the reserve calculation and disclosure requirements resulted in an upward adjustment to our total proved reserves as of December 31, 2009 primarily as a result of the amendments to the definition of crude oil and natural gas reserves and higher crude oil prices. See Notes to Consolidated Financial Statements—Note 15. Supplemental Crude Oil and Natural Gas Information (Unaudited).

Proved Reserves

Proved reserves are those quantities of crude oil and natural gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations. The term “reasonable certainty” implies a high degree of confidence that the quantities of crude oil and/or natural gas actually recovered will equal or exceed the estimate. To achieve reasonable certainty, our internal reserve engineers and Ryder Scott, our independent reserve engineers, employed technologies that have been demonstrated to yield results with consistency and repeatability. The technologies and economic data used in the estimation of our proved reserves include, but are not limited to, well logs, geologic maps and available downhole and production data, seismic data and well test data.

The following tables set forth our estimated proved crude oil and natural gas reserves and the PV-10 as of December 31, 2010 by reserve category. The total Standardized Measure of discounted cash flows as of December 31, 2010 is also presented. Ryder Scott evaluated properties representing approximately 94% of our PV-10, 97% of our proved crude oil reserves, and 94% of our proved natural gas reserves as of December 31, 2010, and our technical staff evaluated the remaining properties. A copy of Ryder Scott’s summary report is included as an exhibit to this Annual Report on Form 10-K. Our estimated proved reserves and related future net revenues and PV-10 at December 31, 2010 were determined using the 12-month unweighted arithmetic average of the first-day-of-the-month commodity prices for the period of January 2010 through December 2010, without giving effect to derivative transactions, and were held constant throughout the life of the properties. These prices were $79.43 per Bbl for crude oil and $4.38 per MMBtu for natural gas ($71.92 per Bbl for crude oil and $5.07 per Mcf for natural gas net of location and quality differentials).

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The following table provides additional information regarding our proved crude oil and natural gas reserves by region as of December 31, 2010.

We have historically added reserves through our exploration program and development activities. See Item 1. Business—Crude Oil and Natural Gas Operations. Reserves at December 31, 2010 and 2009 were computed using the 12-month unweighted average of the first-day-of-the-month commodity prices as required by the new SEC rules. Reserves at December 31, 2008 were computed using year-end commodity prices pursuant to previous SEC rules. Changes in proved reserves were as follows for the periods indicated:

Revisions. Revisions represent changes in previous reserves estimates, upward or downward, resulting from new information normally obtained from development drilling and production history or resulting from a change in economic factors, such as commodity prices, operating costs, or development costs. Revisions for the year ending December 31, 2008 were primarily due to lower commodity prices at the end of 2008 compared to 2007. Revisions for the year ended December 31, 2010 were due to better than anticipated production performance and higher average commodity prices throughout 2010 as compared to 2009.

Extensions, discoveries and other additions. These are additions to our proved reserves that result from (1) extension of the proved acreage of previously discovered reservoirs through additional drilling in periods subsequent to discovery and (2) discovery of new fields with proved reserves or of new reservoirs of proved reserves in old fields. Extensions, discoveries and other additions for the year ended December 31, 2009 include increases in proved undeveloped locations as a result of the change in the SEC’s rules in 2009 to allow producers to report additional undrilled locations beyond one offset on each side of a producing well where there is reasonable certainty of economic producibility. Extensions, discoveries and other additions for the year ended December 31, 2010 were primarily due to increases in proved reserves associated with our successful drilling activity in the Bakken field in North Dakota.

We expect that a significant portion of future reserve additions will come from our major development projects including the Bakken and Oklahoma Woodford plays. We may also purchase proved properties in strategic acquisitions.

Qualifications of Technical Persons and Internal Controls Over Reserves Estimation Process. Ryder Scott, our independent reserve engineers, estimated, in accordance with generally accepted petroleum engineering and evaluation principles and definitions and guidelines established by the SEC, 94% of our PV-10, 97% of our proved crude oil reserves, and 94% of our proved natural gas reserves as of December 31, 2010 included in this Annual Report on Form 10-K. The Ryder Scott technical persons responsible for preparing the reserve estimates presented herein meet the requirements regarding qualifications, independence, objectivity and confidentiality set forth in the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information promulgated by the Society of Petroleum Engineers.

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We maintain an internal staff of petroleum engineers and geoscience professionals who work closely with our independent reserve engineers to ensure the integrity, accuracy and timeliness of data furnished to Ryder Scott in their reserves estimation process. In the fourth quarter, our technical team meets regularly with representatives of Ryder Scott to review properties and discuss methods and assumptions used in Ryder Scott’s preparation of the year-end reserves estimates. While we have no formal committee specifically designated to review reserves reporting and the reserves estimation process, a copy of the Ryder Scott reserve report is reviewed by our Audit Committee with representatives of Ryder Scott and by our internal technical staff before dissemination of the information. Additionally, our senior management reviews and approves the Ryder Scott reserve report and any internally estimated significant changes to our proved reserves on a quarterly basis.

Our Vice President—Resource Development is the technical person primarily responsible for overseeing the preparation of our reserve estimates. He has a Bachelor of Science degree in Petroleum Engineering, an MBA in Finance and 25 years of industry experience with positions of increasing responsibility in operations, acquisitions, engineering and evaluations. He has worked in the area of reserves and reservoir engineering most of his career and is a member of the Society of Petroleum Engineers. The Vice President—Resource Development reports directly to our President and Chief Operating Officer. The reserve estimates are reviewed and approved by the Chief Operating Officer and certain members of senior management.

Proved Undeveloped Reserves. Our proved undeveloped (“PUD”) reserves at December 31, 2010 were 224,323 MBoe, consisting of 123,512 MBbls of crude oil and 604,869 MMcf of natural gas. In 2010, we developed approximately 11% of our proved undeveloped reserves booked as of December 31, 2009 through the drilling of 130 gross (60.4 net) development wells at an aggregate capital cost of approximately $310 million. Also in 2010, we removed the reserves associated with 61 gross (23.9 net) PUD locations because, in the opinion of management, such locations were no longer expected to be developed within the 5 year timeline required by SEC rules. This resulted in the removal of 40.1 Bcf of proved undeveloped natural gas reserves (6.7 MMBoe) in 2010. Estimated future development costs relating to the development of proved undeveloped reserves are projected to be approximately $865 million in 2011, $1,055 million in 2012, and $811 million in 2013.

Since our entry into the Bakken field we have acquired a substantial leasehold position. Our drilling programs to date have focused on proving our undeveloped leasehold acreage through strategic exploratory drilling, thereby increasing the amount of leasehold acreage in the secondary term of the lease with no further drilling obligations, i.e. categorized as held by production (HBP) and resulting in a reduced amount of leasehold acreage in the primary term of the lease with drilling obligations. While we will continue to drill strategic exploratory wells and build on our current leasehold position, we will simultaneously focus on drilling programs over the next 5 years which harvest our PUD locations. Our current 5 year plan anticipates that full development of our PUD inventory will comprise over one-third of our projected level of drilling activity and generate additional PUD locations as our current inventory is harvested.

Developed and Undeveloped Acreage

The following table presents our total gross and net developed and undeveloped acreage by region as of December 31, 2010:

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The following table sets forth the number of gross and net undeveloped acres as of December 31, 2010 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:

Drilling Activity

During the three years ended December 31, 2010, we drilled exploratory and development wells as set forth in the table below:

As of December 31, 2010, there were 151 gross (47.9 net) wells in the process of drilling, completing or waiting on completion.

As of February 18, 2011, we operated 38 rigs on our properties. Our rig activity during 2011 will depend on crude oil and 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 Item 1A. 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 Crude Oil and Natural Gas Properties and Projects

Throughout the following discussion, we discuss our budgeted number of wells and capital expenditures for 2011. We believe our cash flows from operations and borrowing availability under our revolving credit facility will be sufficient to satisfy our 2011 capital budget. The actual amount and timing of our capital expenditures may differ materially from our estimates as a result of, among other things, available cash flows, actual drilling results, the availability of drilling rigs and other services and equipment, and regulatory, technological and competitive developments. Further, a decline in crude 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.

As referred to throughout this report, a “play” is a term applied to a portion of the exploration and production cycle following the identification by geologists and geophysicists of areas with potential crude oil and natural gas reserves. “Conventional plays” are areas that

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are believed to be capable of producing crude oil and natural gas occurring in discrete accumulations in structural and stratigraphic traps. “Unconventional plays” are areas that are believed to be capable of producing crude oil and natural gas occurring in accumulations that are regionally extensive, but require recently developed technologies to achieve profitability. Unconventional plays tend to have low permeability and may be closely associated with source rock as is the case with gas shale, tight oil and gas sands and coalbed methane. Our operations in unconventional plays include operations in the Bakken and Woodford shales and the Red River units. Our operations within conventional plays include operations in the Trenton-Black River of Michigan, Lodgepole of North Dakota, Morrow-Springer of western Oklahoma and Frio in south Texas. In general, unconventional plays require the application of more advanced technology and higher drilling and completion costs to produce relative to conventional plays. These technologies can include large hydraulic fracture treatments, horizontal wellbores, multilateral wellbores, or some other technique or combination of techniques to expose more of the reservoir to the wellbore.

References throughout this report to “3D seismic” refer to seismic surveys of areas by means of an instrument which records the travel time of vibrations sent through the earth and the interpretation thereof. By recording the time interval between the source of the shock wave and the reflected or refracted shock waves from various formations, geophysicists are better able to define the underground configurations. “3D defined locations” are those locations that have been subjected to 3D seismic testing. We typically use 3D seismic testing to evaluate reservoir presence and/or continuity. We do not typically evaluate reservoir productivity using 3D seismic technology.

North Region

Our properties in the North region represented 85% of our PV-10 as of December 31, 2010. During the three months ended December 31, 2010, our average daily production from such properties was 33,214 net Bbls of crude oil and 26,456 net Mcf of natural gas. Our principal producing properties in this region are in the Bakken field and the Red River units.

Bakken Field

The Bakken field of North Dakota and Montana has become one of the premier crude oil resource plays in the United States. It has been described by the United States Geological Survey (“USGS”) as the largest continuous crude oil accumulation it has ever assessed. Estimates of recoverable reserves for the Bakken field have grown from 4.3 billion barrels of crude oil, as published in a report issued by the USGS in April 2008, to potentially 11 billion barrels of crude oil in North Dakota alone, as reported by the North Dakota Industrial Commission (“NDIC”) in January 2011. The increase in reserves is a result of improved drilling and completion technologies and the additional reserves found in the Three Forks formation, which is now recognized as part of the Bakken petroleum system. Drilling activity and production rates in the Bakken field continued to increase in 2010, reaching record levels in North Dakota, according to a report issued by the NDIC in January 2011. As of February 18, 2011, there were 174 rigs drilling in the Bakken field, up 96% from the 89 rigs that were drilling as of January 25, 2010. We continue to be a leader in the development and expansion of the Bakken field. We control one of the largest leasehold positions with approximately 1,597,177 gross (855,936 net) acres as of December 31, 2010. We are also the most active driller in the Bakken field, with 23 operated rigs drilling as of February 18, 2011. During 2010 we completed 233 gross (76.5 net) wells in the Bakken field. Our properties within the Bakken field represented 56% of our PV-10 as of December 31, 2010 and 47% of our average daily Boe production for the three months ended December 31, 2010. As of December 31, 2010 we had completed 648 gross (260.5 net) wells in the Bakken field. Our inventory of proven undeveloped drilling locations in the Bakken field as of December 31, 2010 totaled 842 gross (393.7 net) wells.

2010 proved to be an exceptional year for us in the Bakken field as we saw our production, reserves and acreage position grow to record levels while substantial portions of our undeveloped acreage were de-risked due to the record breaking drilling activity in North Dakota. Our Bakken field production averaged 25,589 net Boe per day during the month of December 2010, up 78% from our average daily Bakken field production in December 2009. Total proved Bakken field reserves at December 31, 2010 were 198 MMBoe, up 47% over our proved Bakken field reserves as of December 31, 2009. Our net acreage position in the Bakken field increased 33% during 2010, from 645,347 net acres as of December 31 2009 to 855,936 net acres as of December 31, 2010. Approximately 22% of our net acreage is developed and 78% of our net acreage is undeveloped as of December 31, 2010.

We plan to invest approximately $845 million drilling 530 gross (131.7 net) wells in the Bakken field during 2011. Approximately 91% will be invested in North Dakota and the remaining 9% will be invested in Montana. We plan to keep 23 rigs drilling in the Bakken field throughout the year, with 21 rigs located in North Dakota and 2 rigs in Montana.

North Dakota Bakken. Our production and reserve growth in the Bakken field during 2010 came primarily from our activities in North Dakota. Production increased to an average rate of 20,860 net Boe per day during the month of December 2010, up 129% from the average daily rate in December 2009. Proved reserves grew 50% year over year to 158 MMBoe as of December 31, 2010. Our estimated ultimate recoverable reserves per well (1,280-acre spacing) also increased during the year from 430 MBoe gross to 518 MBoe gross based on historical well performance. As of December 31, 2010, our North Dakota Bakken properties represented 43% of our PV-10 and 37% of our average daily Boe production for the three months ended December 31, 2010. We completed 222 gross (71 net) wells during 2010, bringing our total number of wells

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drilled in the North Dakota Bakken to 475 gross (150.2 net) as of December 31, 2010. As of December 31, 2010, we had 1,285,665 gross (623,649 net) acres in the North Dakota Bakken field, of which 19% of the net acreage is developed and 81% of the net acreage is undeveloped. Our inventory of proven net undeveloped locations stood at 747 gross (329.5 net) wells as of December 31, 2010.

One of the more significant outcomes of the 2010 drilling activity in the North Dakota Bakken was the expansion of the play west of the Nesson Anticline. Technological breakthroughs demonstrated that widespread commercial production can be achieved in this area by increasing fracture stimulation treatments where necessary. Based on this information, we expanded our leasing effort and acquired an additional 141,800 net acres in the North Dakota Bakken during 2010, increasing our net acreage position by 29% over our North Dakota Bakken net acreage position as of December 31, 2009.

Another significant achievement during 2010 was the successful implementation of our ECO-Pad^TM technology. ECO-Pad technology allows 4 wells (2 Bakken and 2 Three Forks) to be drilled from a single drilling pad, which reduces drilling costs, completion costs and environmental impact by centralizing operations on a single pad. Drilling costs are saved by utilizing a walking rig, which moves between wells on hydraulic feet that eliminate the need to breakdown the rig each time it moves from one well to another well. Completion costs are saved by conducting fracture stimulation treatments on multiple wells in one continuous operation. Centralizing operations and production facilities reduces the size of the pad needed by as much as 75%. Our first ECO-Pad operation, the Arthur-Hegler, was completed in August 2010, flowing at a combined maximum 24-hour rate of 4,350 Boe per day. As of December 31, 2010, we had completed 4 ECO-Pad locations and had 4 ECO-Pad rigs drilling. We believe our ECO-Pad technology is a key to maximizing the development of the Bakken field, and we plan to increase the use of this technology as the field matures.

During 2010 we increased the number of fracture stimulation stages per well from approximately 18 stages to as many as 30 stages. Although there are always overriding geologic factors that influence production, the increase in recoverable reserves we announced in 2010 can be attributed primarily to the increased number of fracture stimulation stages used per well. We are studying these results to optimize future fracture stimulations in the field.

During 2011, we plan to invest approximately $771 million drilling 514 gross (120.6 net) wells in the North Dakota Bakken field. The drilling will include development wells along our Nesson Anticline acreage and step-out wells west of the Nesson Anticline to continue expanding the proven extents of the Bakken and Three Forks reservoirs underlying our acreage. The majority of our drilling will be on 1,280-acre spacing but will include some 640-acre infield locations and dual zone development. In time, we expect that the North Dakota Bakken field will be developed on 320-acre spacing like the Elm Coulee field in Montana. As of February 18, 2011, we had 21 operated rigs drilling in the North Dakota Bakken and plan to maintain 21 operated rigs drilling in the play throughout 2011.

Montana Bakken. Our Montana Bakken production is located primarily in the Elm Coulee field in Richland County, Montana. The Elm Coulee field is listed by the Energy Information Administration as the 17th largest onshore field in the lower 48 states of the United States ranked by proved liquid reserves in 2009. Since drilling our first well in August 2003, we have completed a total of 171 gross (108.6 net) wells in the field as of December 31, 2010. Year over year, production in 2010 was down 18%, reflecting our limited drilling activity in the field during 2010. The majority of our drilling was conducted during the second half of 2010, and production during the month of December 2010 was down only 10% from the average daily production in December 2009. As of December 31, 2010 our Montana Bakken properties represented 14% of our PV-10 and 10% of our average daily Boe production for the three months ended December 31, 2010. During the year we added 98,344 gross (68,788 net) acres in the Montana Bakken play. As of December 31, 2010, we owned 311,512 gross (232,287 net) acres, of which 29% of the net acreage is developed and the remaining 71% of the net acreage is undeveloped.

During the year ended December 31, 2010, using the latest drilling and completion technologies, we completed 11 gross (5.5 net) wells to further develop the field and test the potential to expand the limits of the Elm Coulee field. The Rognas 2-22H well, which is strategically located along the northern edge of the Elm Coulee field, was completed flowing at a 24-hour maximum rate of 1,014 Boe per day. The Rognas 2-22H was completed using current drilling and cased hole, multi-stage fracture stimulation technology and has significantly outperformed offsetting wells that were completed using older open hole completion technology. These results are encouraging and indicate that we may be able to extend the limits of the Elm Coulee field using these technologies. We will continue testing this concept in 2011.

We plan to invest approximately $74 million drilling 16 gross (11.1 net) wells in the Montana Bakken during 2011. Our drilling will focus in the Elm Coulee field area but will also include some strategic step-out wells to further test our undeveloped acreage immediately north of the Elm Coulee field. As of February 18, 2011 we had 2 rigs drilling in the Montana Bakken and we plan to maintain 2 rigs in the play throughout 2011. As of December 31, 2010, we had 95 gross (64.2 net) proven undeveloped locations identified in the Montana Bakken.

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Red River Units

Our Red River units represent 28% of our PV-10 as of December 31, 2010 and 34% of our average daily North region Boe production for December 2010. The 8 units comprising the Red River units are located along the Cedar Creek Anticline in North Dakota, South Dakota and Montana and produce crude 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, which was listed by the Energy Information Administration in 2008 as the 7th largest onshore field in the lower 48 states of the United States ranked by liquid proved reserves.

In the Red River units, we plan to complete pattern drilling on the waterflood project in the Cedar Hills units and resume development activity in the Medicine Pole Hills and Buffalo units in 2011. We have allocated $58 million of our capital expenditure budget to the Red River units, which will support 2 operated rigs and a significant investment in facilities and infrastructure.

Cedar Hills Units. Cedar Hills North unit (“CHNU”) is located in Bowman and Slope Counties, North Dakota. We drilled the initial horizontal well in CHNU, the Ponderosa 1-15, in April 1995. As of December 31, 2010, we had drilled 235 horizontal wells within this 49,700-acre unit, with 116 producing wellbores and the remainder serving as injection wellbores. We own a 98% working interest and operate the CHNU.

Cedar Hills West unit (“CHWU”), in Fallon County, Montana, is contiguous to the northern portion of CHNU. As of December 31, 2010, this 7,800-acre unit contained 11 horizontal producing wells and 5 horizontal injection wells. We own and operate 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 CHNU. Under HPAI, compressed air injected into a reservoir oxidizes residual crude oil and produces flue gases (primarily carbon dioxide and nitrogen) that mobilize and sweep the crude oil into producing wellbores. During February 2008, the transition started to have full scale water injection and this transition was completed in June of 2010 when we stopped our air injection at Cedar Hills after injecting nearly 80 Bcf of air into the reservoir. We have seen continued success from our increased density drilling program which supported the idea that we could more economically inject water than air in these units. In response to our enhanced recovery and increased drilling efforts, our net daily production increased from 2,185 Boe per day in November 2003 to 10,789 Boe per day in December 2010. During 2011, we plan to drill 12 new horizontal wells in the Cedar Hills units continuing with our increased density for both the producing wells and injection wells, and improving and upgrading production and injection facilities. In 2011, we plan to invest approximately $35 million drilling and improving facilities in the Cedar Hills units.

Medicine Pole Hills Units. The Medicine Pole Hills units (“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 4 injection wellbores under HPAI producing 525 net Bbls of crude oil per day. We have since drilled 51 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 and we operate and own an average 77% working interest in the three units. Production from the units averaged 1,241 net Bbls of crude oil and 1,721 net Mcf of natural gas per day during December 2010. In May 2010 we began the installation of two 15 MMcf per day electric air compressors to supplement and ultimately replace our more costly natural gas-fired compressors which currently inject 24 MMcf of air per day. During the second quarter of 2011, we plan to finalize the installation. In 2011, we plan to invest approximately $7 million for capital 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 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 crude oil per day. We operate and own an average working interest of 95% in the 32,900 acres comprising the three units. From 2005 through 2010, we re-entered 48 existing vertical wells and drilled horizontal laterals to increase production and sweep efficiency from the three units. Production for the month of December 2010 was 1,421 net Bbls of crude oil per day. In 2011, we plan to invest approximately $4 million for capital workovers and facilities which will include installing two 14 MMcf per day electric air compressors to supplement and ultimately replace the less efficient and higher maintenance compressors which currently inject 10 MMcf of air per day. This installation started in May 2010 and will be completed during the first quarter of 2011.

Niobrara

The Upper Cretaceous Niobrara formation has emerged as another potential crude oil resource play in various basins throughout the northern Rocky Mountain region. As with most resource plays, the Niobrara has a history of producing through conventional technology with some of the earliest production dating back to the early 1900s. Individual fields have produced up to 12 MMBoe and individual wells have produced up to 2.1 MMBoe. Natural fracturing has played a key role in producing the Niobrara historically due to the low porosity and low permeability of the formation. Because of this, conventional production has been very localized and limited in area extent. We believe the Niobrara can be produced on a more widespread basis using today’s horizontal multi-stage fracture stimulation technology where the Niobrara is thermally mature. Based on studies conducted by our geotechnical teams, we have acquired 103,148 gross (71,712 net) acres in prospective portions of the DJ Basin of Colorado and Wyoming.

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DJ Basin. The DJ Basin Niobrara play emerged as a crude oil resource play in 2010 and attracted a flurry of leasing activity based on drilling results announced early in 2010. Drilling activity increased during the year, and at December 31, 2010 there were 12 rigs drilling horizontal Niobrara wells in the DJ Basin, with 279 outstanding permits to drill additional horizontal Niobrara wells in the basin. Although drilling activity ramped up during the year, the play is in its early stages, and completion results and production histories are limited. A total of 15 Niobrara completions have been published as of December 31, 2010. Initial production rates for these Niobrara producers ranged from 87 Bbls of crude oil per day to 1,558 Bbls of crude oil per day.

As of December 31, 2010, we owned 103,148 gross (71,712 net) acres in the DJ Basin. Approximately 33% of the net acreage is located in Weld and Morgan Counties, Colorado and 67% in Laramie, Goshen and Platte counties in Wyoming. Here, the Niobrara is found at an average depth of approximately 6,000 feet, and the targeted B-bench chalk ranges from 50 to 100 feet thick. We spud our first horizontal well in Weld County, Colorado, the Newton 1-4H, in early February 2011. The Newton 1-4H is the first 1,280-acre spaced well drilled in the Niobrara play, with a targeted lateral length of 9,200 feet. To date, all wells in the play have been drilled on 640-acre spacing with laterals of 4,500 feet or less. By increasing the lateral length, we expect to get more reserves per well at a lower cost.

In 2011, we plan to invest approximately $20 million drilling 5 gross (3.3 net) wells in the DJ Basin Niobrara play. We also plan to acquire 80 square miles of 3D seismic data during the first quarter of 2011 to guide future drilling in the play.

Big Horn Basin and Other

Our wells within the Big Horn Basin in northern Wyoming and other areas within the North region represented 1% of our PV-10 as of December 31, 2010 and 3% of our average daily Boe production for the three months ended December 31, 2010. Our principal property in the Big Horn Basin, the Worland field, produces primarily from the Phosphoria formation. We also have several other ongoing projects in the Rockies, including conventional 3D-defined locations at the Red River and Lodgepole structures in North Dakota and Montana, and horizontal Fryburg opportunities in North Dakota.

South Region

Our properties in the South region represented 12% of our PV-10 as of December 31, 2010 and 19% of our average daily Boe production for the three months ended December 31, 2010. During the three months ended December 31, 2010, our average daily production from such properties was 790 net Bbls of crude oil and 49,843 net Mcf of natural gas, up 27% from same period 2009. Our principal producing properties in this region are located in the Anadarko and Arkoma basins of Oklahoma, as well as various basins of Texas and Louisiana.

Oklahoma Woodford Shale

The Oklahoma Woodford is a widespread unconventional shale reservoir that produces crude oil, natural gas and natural gas condensate in various basins across the state of Oklahoma. Our principal producing properties in the Oklahoma Woodford are located in the Arkoma and Anadarko basins. Combined, these properties represented 10% of our PV-10 as of December 31, 2010 and 13% of our net average daily Boe production for the three months ended December 31, 2010. Production from the Oklahoma Woodford for 2010 totaled 1,928 MBoe (11,568 MMcfe), up 17% over 2009. Production increased throughout the year, and the average daily production for our Oklahoma Woodford properties for the month of December 2010 was 6,144 Boe per day, up 41% over our daily average production for the month of December 2009. As of December 31, 2010, we held 589,742 gross (322,194 net) acres in the play. As of December 2010, 18% of the net acreage is developed and the remaining 82% of the net acreage is undeveloped.

During 2010 we completed 67 gross (15.1 net) Oklahoma Woodford wells. During 2011, we plan to invest approximately $230 million drilling 113 gross (31.1 net) wells in the Oklahoma Woodford. As of February 18, 2011 we had 11 rigs drilling in the Oklahoma Woodford and expect to maintain 8 to 10 rigs in the play throughout 2011.

Arkoma Woodford Shale. The Arkoma Woodford represented 6% of our PV-10 as of December 31, 2010 and 9% of our average daily Boe production for the three months ended December 31, 2010. Year-over-year, Arkoma Woodford production was down 5% due to our

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scaled back drilling program in 2010. During the month of December 2010, however, our Arkoma Woodford production averaged 4,253 net Boe per day, up 19% over our average daily production in December 2009, reflecting results of wells we completed in the second half of 2010. As of December 31, 2010 we have completed a total of 387 gross (57.5 net) wells in the Arkoma Woodford play.

During 2010, we completed a total of 50 gross (6.5 net) wells, as compared to 71 gross (8.5 net) wells in 2009. These completions included a combination of 640-acre exploratory and 80-acre infield development type wells. We also licensed 10 squares miles of 3D seismic data during 2010 to provide guidance for our exploration and development drilling in the East McAlester area. In total, we now own approximately 150 square miles of proprietary and non-proprietary 3D seismic data in the Arkoma basin to complement our drilling effort. As of December 31, 2010, we owned approximately 147,727 gross (43,613 net) acres in the Arkoma Woodford play, of which 52% of our net acreage is developed and the remaining 48% of our net acreage is undeveloped. A total of 339 gross (94.1 net) proven undeveloped locations have been identified on this acreage as of December 31, 2010.

In 2011, we plan to invest approximately $9 million to drill 14 gross (2.3 net) wells in the Arkoma Woodford play. As of February 18, 2011, we had 1 operated rig drilling in the Arkoma Woodford play.

Anadarko Woodford Shale. The Anadarko Woodford represented 4% of our PV-10 as of December 31, 2010 and 4% of our average daily Boe production for the three months ended December 31, 2010. Our Anadarko Woodford production grew 333% year-over-year due to our increased drilling activity in 2010. During the month of December 2010, our Anadarko Woodford production averaged 1,891 net Boe per day, up 136% over our average daily production in December 2009.

We control one of the largest acreage positions in the Anadarko Woodford play, with 405,575 gross (267,542 net) acres under lease as of December 31, 2010. This acreage is located in Canadian, Blaine, Dewey, Caddo, Grady and McClain counties in Oklahoma, extending 51 miles northwest and 75 miles southeast from the Cana field area, where the initial discovery was made in late 2007. Approximately 68% of our acreage is located in our NW Cana project and 32% is located in our SE Cana project.

Competition for acreage and equipment in the Anadarko Woodford grew rapidly during 2010 in response to continued success in the Cana field and our drilling success in our NW Cana and SE Cana projects. The industry rig count tripled during the year, from 15 rigs in January 2010 to 48 rigs as of February 18, 2011. Results from the 2010 drilling activity demonstrated that production from the Woodford Shale is widespread and repeatable, and suggests that the Anadarko Woodford may prove to contain greater recoverable reserves than the Arkoma Woodford.

During 2010, we completed a total of 16 gross (8.2 net) wells as compared to 4 gross (2.6 net) wells in 2009. Our 2010 drilling program was strategically designed to delineate the extent of the productive Anadarko Woodford on our acreage. Under this successful program, we completed key wells in both our NW Cana and SE Cana projects, demonstrating that the productive Anadarko Woodford fairway extends at least 90 miles from known production at our Brown 1-2H well in Dewey County (NW Cana) to our Dana 1-29H well in Grady County (SE Cana). In NW Cana, the Doris 1-25H well (98% WI) was completed flowing at an initial 24-hour test rate of 4.5 MMcf of natural gas per day and 72 Bbls of crude oil per day. The Doris 1-25H well was located 4 miles south of our initial discovery well, the Brown 1-2H (100% WI) that was completed in September 2009. The Brown 1-2H well was completed flowing at 4.2 MMcf of natural gas per day and 102 Bbls of crude oil per day and produced a total of 1,208 MMcf of natural gas and 15,895 Bbls of crude oil as of December 31, 2010. In our SE Cana project we completed the Dana 1-29H well (79% WI) flowing at 2.5 MMcf per day of liquids-rich natural gas and 88 Bbls of crude oil per day during its initial 24-hour test period. The Dana 1-29H well was a key completion for us in SE Cana, as it confirmed our geologic model that higher production rates can be achieved from the upper siliceous member of the Woodford shale in SE Cana. In January 2011, we confirmed the success of the Dana 1-29H well by completing the Sprowls 1-14H well located 17 miles north of the Dana 1-29H well. The Sprowls 1-14H well (100% WI) was completed flowing at 2.8 MMcf of natural gas per day and 96 Bbls of crude oil per day during its initial 24-hour test period. Based on these positive results, we increased our operated rig count in the Anadarko Woodford from 1 operated rig in January 2010 to 10 operated rigs as of February 18, 2011.

An upside to the Anadarko Woodford is the potential to encounter additional pay from reservoirs overlying the Woodford. With the Anadarko basin being one of the more prolific crude oil and natural gas producing basins in the United States, there are up to 12 conventional reservoirs overlying the Anadarko Woodford shale. All of these conventional reservoirs have the potential to produce locally under our Anadarko Woodford acreage. A good example is our Rother 1-4H well (100% WI), which encountered a productive reservoir in an overlying Springer sand while drilling to the Woodford shale. After completing the Rother 1-4H well as a Woodford producer, we drilled a second well, the Rother 2-4 (80% WI) to produce the Springer reservoir. The Rother 2-4 well produced 4.9 MMcf of natural gas per day and 91 Bbls of crude oil per day during its initial 24-hour test period. Springer sand reservoirs can be quite prolific, and since being completed in November 2010, the Rother 2-4 well has produced 221 MMcf of natural gas and 3,926 Bbls of crude oil as of December 31, 2010. To date, 37% of our Woodford wells have encountered productive reservoirs in overlying Tonkawa, Red Fork, Morrow, Springer and/or Mississippian reservoirs, while drilling to the Woodford shale.

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In 2011, we plan to invest approximately $221 million to drill 99 gross (28.8 net) wells to further delineate and develop the Anadarko Woodford shale on our acreage. As of February 18, 2011, we had 10 operated rigs drilling in the Anadarko Woodford play, and expect to have 2 additional rigs drilling in the play by the end of first quarter 2011. To support our drilling program, we are investing approximately $12 million dollars to acquire approximately 500 square miles of proprietary 3D seismic to guide future drilling on our acreage. As of December 31, 2010, we had a total of 80 gross (41.4 net) proven undeveloped locations identified on our Anadarko Woodford acreage.

Conventional Anadarko Basin and Gulf Coast

Our conventional producing properties in the Anadarko basin and Gulf Coast areas represented 2% of our PV-10 as of December 31, 2010 and 6% of our average daily Boe production for the three months ended December 31, 2010. The properties primarily include our legacy assets in Oklahoma along the Anadarko Basin Shelf, the Jefferson Island Salt Dome in Iberia Parish, Louisiana, and producing properties in Nueces County, Texas. We continue to maximize the performance of these properties through workovers, recompletions and drilling as warranted. Year-over-year our conventional Anadarko and Gulf Coast production declined 13% due to normal production declines and our limited drilling activity. During the month of December 2010 however, production averaged 3,269 net Boe per day, up 12% over our average daily production in December 2009 reflecting results of wells we completed in the second half of 2010. We completed 11 gross (4.9 net) wells in the conventional Anadarko and Gulf Coast areas during 2010.

East Region

Our properties in the East region represent 2% of our PV-10 as of December 31, 2010. During the three months ended December 31, 2010, our average daily production from such properties was 1,292 net Bbls of crude oil and 128 net Mcf of natural gas. Our principal producing properties in this region are located in the Illinois Basin, Michigan Basin, and portions of the Appalachian Basin in the eastern United States.

Illinois Basin

Our properties within the Illinois Basin represented 33% of our PV-10 in the East region as of December 31, 2010 and 59% of our average daily East region Boe production for the three months ended December 31, 2010. Our production within the Illinois Basin is primarily crude oil from units comprised of shallow sand formations under water injection. We continue to maximize the performance of these properties through workovers, recompletions and drilling as warranted.

Michigan Trenton-Black River

Our Trenton-Black River properties located in Hillsdale Co., Michigan represented 15% of our PV-10 in the East region as of December 31, 2010 and 16% of our average daily East region Boe production for the three months ended December 31, 2010. We owned approximately 76,500 gross (58,800 net) acres in the play as of December 31, 2010. Since drilling our first well on the properties in 2007, we have drilled and completed 20 gross (12.3 net) wells with net success of 55%.

Drilling on these properties has been guided by our proprietary 3D seismic interpretation techniques. We currently own 46 square miles of 3D seismic data on the properties and have numerous additional drilling locations. We plan to acquire an additional 10.6 square miles of 3D seismic during 2011 to identify additional drilling opportunities.

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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, 2010, 2009 and 2008 in total and for each field containing 15 percent or more of our total proved reserves as of December 31, 2010: