CONTINENTAL RESOURCES, INC - Annual Report: 2011 (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, 2011

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 the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities

Act.     Yes  x    No  ¨

Indicate by check mark if the 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.

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the 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, 2011 was approximately $3.7 billion, based upon the closing price of $64.91 per share as reported by the New York Stock Exchange on such date.

180,863,580 shares of our $0.01 par value common stock were outstanding on February 15, 2012.

DOCUMENTS INCORPORATED BY REFERENCE

Portions of the definitive Proxy Statement of Continental Resources, Inc. for the Annual Meeting of Stockholders to be held in 2012, 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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When we refer to “us,” “we,” “our,” “Company,” or “Continental” we are describing Continental Resources, Inc. and/or our subsidiaries.

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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, which represents the amount of energy needed to heat one pound of water by one degree Fahrenheit and can be used to describe the energy content of fuels.

“completion” The process of treating a drilled well followed by the installation of permanent equipment for the production of crude oil and/or natural gas.

“conventional play” An area 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.

“de-risked” Refers to acreage and locations in which the Company believes the geological risks and uncertainties related to recovery of crude oil and natural gas have been reduced as a result of drilling operations to date. However, only a portion of such acreage and locations have been assigned proved undeveloped reserves and ultimate recovery of hydrocarbons from such acreage and locations remains subject to all risks of recovery applicable to other acreage.

“developed acreage” The number of acres 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 gas” Refers to natural gas that remains in a gaseous state in the reservoir and does not produce large quantities of liquid hydrocarbons when brought to the surface. Also may refer to gas that has been processed or treated to remove all natural gas liquids.

“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 which allows for drilling multiple 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 sometimes 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.

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“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.

“hydraulic fracturing” A process involving the high pressure injection of water, sand and additives into rock formations to stimulate crude oil and natural gas production.

“in-field well” A well drilled between producing wells in a field to provide more efficient recovery of crude oil or natural gas from the reservoir.

“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.

“MMBo” One million barrels of crude oil.

“MMBoe” One million Boe.

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

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“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 renewal is reasonably certain.

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

“proved undeveloped reserves” or “PUD” Proved reserves 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.

“resource play” Refers to an expansive contiguous geographical area with prospective crude oil and/or natural gas reserves that has the potential to be developed uniformly with repeatable commercial success due to advancements in horizontal drilling and multi-stage fracturing technologies.

“royalty interest” Refers to the ownership of a percentage of the resources or revenues produced from a crude oil or natural gas property. A royalty interest owner does not bear 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 2009 and later) 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 the 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.

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“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.

“unconventional play” An area 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 oil and 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 Part I, 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:

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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 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 Part I, Item 1A. Risk Factors in this report, quarterly reports and 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 Part I, 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 subsidiaries.

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. 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 Anadarko Woodford and Arkoma Woodford plays in Oklahoma. The East region contains properties east of the Mississippi river including the Illinois Basin and the state of Michigan.

We were originally formed in 1967 to explore for, develop and produce crude oil and natural gas properties. Through 1989, our activities and growth remained focused primarily in Oklahoma. In 1989, we expanded our activity into the North region. Approximately 71% of our estimated proved reserves as of December 31, 2011 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 allow 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 439.0 MMBoe of proved crude oil and natural gas reserves through extensions and discoveries from January 1, 2007 through December 31, 2011 compared to 4.8 MMBoe added through proved reserve acquisitions during that same period.

As of December 31, 2011, our estimated proved reserves were 508.4 MMBoe, with estimated proved developed reserves of 205.2 MMBoe, or 40% of our total estimated proved reserves. Crude oil comprised 64% of our total estimated proved reserves as of December 31, 2011. For the year ended December 31, 2011, we generated crude oil and natural gas revenues of $1.65 billion and operating cash flows of $1.1 billion. For the year ended December 31, 2011, daily production averaged 61,865 Boe per day, a 43% increase over average production of 43,318 Boe per day for the year ended December 31, 2010. Average daily production for the quarter ended December 31, 2011 increased 57% to 75,219 Boe per day from 48,034 Boe per day for the quarter ended December 31, 2010.

The following table summarizes our total estimated proved reserves, PV-10 and net producing wells as of December 31, 2011, average daily production for the quarter ended December 31, 2011 and the reserve-to-production index in our principal regions. Our reserve estimates as of December 31, 2011 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 96% of our PV-10, 97% of our proved crude oil reserves, and 81% of our proved natural gas reserves as of December 31, 2011. 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, 2011 were determined using the 12-month unweighted arithmetic average of the first-day-of-the-month commodity prices for the period of January 2011

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through December 2011, without giving effect to derivative transactions, and were held constant throughout the lives of the properties. These prices were $96.19 per Bbl for crude oil and $4.12 per MMBtu for natural gas ($88.71 per Bbl for crude oil and $5.59 per Mcf for natural gas adjusted for location and quality differentials).

The following table provides additional information regarding our key development areas as of December 31, 2011 and the budgeted amounts we plan to spend on exploratory and development drilling, capital workovers, and facilities in 2012.

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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 1980s we began to believe the valuation potential for crude oil exceeded that of natural gas. Accordingly, we began to shift our reserve and production profiles toward crude oil. As of December 31, 2011, crude oil comprises 64% of our total proved reserves and 73% of our 2011 annual production. Although we do pursue liquids-rich natural gas opportunities, such as the Anadarko Woodford play in Oklahoma, we continue to believe crude oil valuations will be superior to natural gas valuations on a relative Btu basis for the foreseeable future.

Growth Through Drilling. A substantial portion of our annual capital expenditures are invested in drilling projects and acreage acquisitions. From January 1, 2007 through December 31, 2011, proved crude oil and natural gas reserve additions through extensions and discoveries were 439.0 MMBoe compared to 4.8 MMBoe of proved reserve acquisitions.

Internally Generated Prospects. Although we periodically evaluate and complete strategic acquisitions, our technical staff has internally generated a substantial portion 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, Three Forks and Oklahoma Woodford formations. Production rates in the Red River units also have been increased through the use of enhanced recovery technologies including water and high pressure air injection. Our production from the Red River units, the Bakken field, and the Oklahoma Woodford play comprised approximately 20,635 MBoe, or 91%, of our total crude oil and natural gas production for the year ended December 31, 2011.

Acquire Significant Acreage Positions in New or Developing Plays. In addition to the 969,010 net undeveloped acres held in the Bakken play in North Dakota and Montana, the Oklahoma Woodford play, and the Niobrara play in Colorado and Wyoming, we held 260,415 net undeveloped acres in other crude oil and natural gas plays as of December 31, 2011. 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 we believe will help us successfully execute our business strategy:

Large Acreage Inventory. We own 1,229,425 net undeveloped acres and 665,317 net developed acres as of December 31, 2011. Approximately 79% of the net undeveloped acres are located within unconventional

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resource plays in the Bakken (North Dakota and Montana), Woodford (Oklahoma) and the Niobrara (Colorado and Wyoming). The remaining balance of the net undeveloped acreage is located in conventional plays including 3D-defined locations for the Trenton-Black River (Michigan), Lodgepole (North Dakota), Morrow-Springer (Western Oklahoma) and Frio (South Texas).

Horizontal Drilling and Enhanced Recovery Experience. In 1992, we drilled our first horizontal well, and we have drilled over 1,100 horizontal wells since that time. We also have substantial experience with enhanced recovery methods and currently serve as the operator of 49 waterflood units. Additionally, we operate 6 high pressure air injection floods.

Control Operations Over a Substantial Portion of Our Assets and Investments. As of December 31, 2011, we operated properties comprising 86% 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 31 years of crude oil and natural gas industry experience. Additionally, our technical staff, which includes 48 petroleum engineers, 26 geoscientists and 26 landmen, has an average of 15 years experience in the industry.

Strong Financial Position. We have a revolving credit facility with lender commitments totaling $1.25 billion and a borrowing base of $2.25 billion as of February 15, 2012, with available borrowing capacity of $347.2 million at that date after considering outstanding borrowings and letters of credit. While our current commitments total $1.25 billion, we have the ability to increase the aggregate commitment level up to the lesser of $2.5 billion or the borrowing base then in effect to provide additional available liquidity if needed to maintain our growth strategy, take advantage of business opportunities, and fund our capital program. We believe our planned exploration and development activities will be funded substantially from our operating cash flows and borrowings under our revolving credit facility. Our 2012 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 differ from expectations, we believe our credit facility will have sufficient availability to fund any deficit or that we can reduce our capital expenditures to be in line with cash flows from operations.

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. These rules 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 require 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.

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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 17. 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 prior to the time at which contracts providing the right to operate expire, unless evidence indicates renewal is reasonably certain. 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 PV-10 by reserve category as of December 31, 2011. The total Standardized Measure of discounted cash flows as of December 31, 2011 is also presented. Ryder Scott evaluated properties representing approximately 96% of our PV-10, 97% of our proved crude oil reserves, and 81% of our proved natural gas reserves as of December 31, 2011, and our internal 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, 2011 were determined using the 12-month unweighted arithmetic average of the first-day-of-the-month commodity prices for the period of January 2011 through December 2011, without giving effect to derivative transactions, and were held constant throughout the lives of the properties. These prices were $96.19 per Bbl for crude oil and $4.12 per MMBtu for natural gas ($88.71 per Bbl for crude oil and $5.59 per Mcf for natural gas adjusted for 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, 2011.

We have historically added reserves through our exploration program and development activities as discussed in Part I, Item 1. Business—Crude Oil and Natural Gas Operations. Reserves at December 31, 2009, 2010 and 2011 were computed using the 12-month unweighted average of the first-day-of-the-month commodity prices as required by 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 reserve 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 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

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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. Extensions, discoveries and other additions for the year ended December 31, 2011 were primarily due to increases in proved reserves associated with our successful drilling activity in the Bakken field in North Dakota and Anadarko Woodford play in Oklahoma.

We expect a significant portion of future reserve additions will come from our major development projects in the Bakken and Anadarko Woodford plays. We also expect to participate as a buyer of properties when and if we have the ability to increase our position in strategic plays at favorable terms.

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, 96% of our PV-10, 97% of our proved crude oil reserves, and 81% of our proved natural gas reserves as of December 31, 2011 included in this Annual Report on Form 10-K. The Ryder Scott technical personnel 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. Refer to Exhibit 99 included with this Annual Report on Form 10-K for further discussion of the qualifications of Ryder Scott personnel.

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, certain members of our senior management review and approve the Ryder Scott reserve report and on a quarterly basis any internally estimated significant changes to our proved reserves.

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 26 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, 2011 were 303,203 MBoe, consisting of 181,109 MBbls of crude oil and 732,567 MMcf of natural gas. In 2011, we developed approximately 13% of our proved undeveloped reserves booked as of December 31, 2010 through the drilling of 141 gross (68.2 net) development wells at an aggregate capital cost of approximately $448 million. Also in 2011, we removed 230 gross (49.9 net) PUD locations. This resulted in the removal of 1.7 MMBo and 135.4 Bcf of proved undeveloped reserves (24.2 MMBoe). These removals were predominantly due to our decision to declassify 0.2 MMBo and 130.4 Bcf (21.9 MMBoe) of proved undeveloped reserves in our Arkoma Woodford district, which consists primarily of dry gas. These reserves were originally scheduled to be developed by year-end 2013. However, given current and projected prices for natural gas, we elected to defer drilling and as a result declassified these proved undeveloped reserves accordingly. Estimated future development costs relating to the development of proved undeveloped reserves are projected to be approximately $1.5 billion in 2012, $1.6 billion in 2013, $1.4 billion in 2014, $0.5 billion in 2015 and $0.2 billion in 2016.

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

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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) 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 increase our 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 the majority of our currently 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, 2011:

The following table sets forth the number of gross and net undeveloped acres as of December 31, 2011 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:

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Drilling Activity

During the three years ended December 31, 2011, we drilled exploratory and development wells as set forth in the table below:

As of December 31, 2011, there were 195 gross (62.2 net) wells in the process of drilling, completing or waiting on completion.

As of February 15, 2012, we operated 36 rigs on our properties. Our rig activity during 2012 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 Part I, 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 2012. Although we cannot provide any assurance, we believe our cash flows from operations, remaining cash balance, and borrowing availability under our revolving credit facility will be sufficient to satisfy our 2012 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 commodity 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 believed to be capable of producing crude oil and natural gas occurring in discrete accumulations in structural and stratigraphic traps. “Unconventional plays” are areas 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 oil and gas shale, tight oil and gas sands and coalbed methane. Our operations in unconventional plays include operations in the Bakken and Woodford plays 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 hydraulic fracturing treatments, horizontal wellbores, multilateral wellbores, or some other technique or combination of techniques to expose more of the reservoir to the wellbore.

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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 86% of our PV-10 as of December 31, 2011. During the three months ended December 31, 2011, our average daily production from such properties was 50,529 net Bbls of crude oil and 41,545 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 is 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. In October 2011, the USGS began a study to update their 2008 assessment of recoverable reserves for the Bakken field to reflect the increased recoveries due to new geologic models applied to the Bakken Formation, advances in drilling and production technologies, and additional crude oil discoveries in the field. Results of the USGS study are expected to be announced in 2013.

Drilling activity and production rates in the Bakken field continued to increase in 2011, reaching record levels in North Dakota, according to a report issued by the NDIC on January 17, 2012. As of February 6, 2012, there were 210 rigs drilling in the Bakken field, up 21% from the 174 rigs that were drilling as of February 18, 2011. 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 1,660,847 gross (915,863 net) acres as of December 31, 2011. We are also the most active driller in the Bakken field, with 22 operated rigs drilling as of February 15, 2012. During 2011 we completed 390 gross (122.3 net) wells in the Bakken field. Our properties within the Bakken field represented 64% of our PV-10 as of December 31, 2011 and 55% of our average daily Boe production for the three months ended December 31, 2011. As of December 31, 2011 we had completed 1,042 gross (382.9 net) wells in the Bakken field. Our inventory of proved undeveloped drilling locations in the Bakken field as of December 31, 2011 totaled 1,131 gross (497.4 net) wells.

During 2011, we saw our production, reserves and acreage position in the Bakken field grow 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 43,148 net Boe per day during the month of December 2011, up 69% from our average daily Bakken field production in December 2010. Total proved Bakken field reserves at December 31, 2011 were 294 MMBoe, up 49% over our proved Bakken field reserves as of December 31, 2010. Our net acreage position in the Bakken field increased 7% during 2011, from 855,936 net acres as of December 31 2010 to 915,863 net acres as of December 31, 2011. Approximately 34% of our net acreage is developed and 66% of our net acreage is undeveloped as of December 31, 2011.

We plan to invest approximately $1,040.7 million drilling 488 gross (126.2 net) wells in the Bakken field during 2012. Approximately 91% will be invested in North Dakota and the remaining 9% will be invested in Montana. We plan to average 24 rigs drilling in the Bakken field throughout the year, with 21 rigs located in North Dakota and 3 rigs in Montana.

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North Dakota Bakken. Our production and reserve growth in the Bakken field during 2011 came primarily from our activities in North Dakota. Production increased to an average rate of 37,177 net Boe per day during the month of December 2011, up 78% from the average daily rate in December 2010. Proved reserves grew 62% year-over-year to 256 MMBoe as of December 31, 2011. Our estimated average ultimate recoverable reserves per well (1,280-acre spacing) also increased during the year from 518 MBoe gross to 603 MBoe gross based on historical well performance. As of December 31, 2011, our North Dakota Bakken properties represented 54% of our PV-10 and 47% of our average daily Boe production for the three months ended December 31, 2011. We completed 369 gross (109.5 net) wells during 2011, bringing our total number of wells drilled in the North Dakota Bakken to 849 gross (260.8 net) as of December 31, 2011. As of December 31, 2011, we had 1,313,057 gross (663,237 net) acres in the North Dakota Bakken field, of which 36% of the net acreage is developed and 64% of the net acreage is undeveloped. Our inventory of proved net undeveloped locations stood at 1,050 gross (442.4 net) wells as of December 31, 2011.

One of the more significant outcomes of our 2011 drilling activity in the North Dakota Bakken was the discovery of three additional layers or “benches” of oil bearing rock in the Three Forks formation based on six drilling cores taken at various locations across the North Dakota Bakken field. This discovery redefined the Bakken petroleum system and prompted the NDIC to expand the definition of the Bakken reservoir, in certain areas of the field, to include all zones from 50 feet above the top of the Bakken Formation down to the base of the Three Forks Formation. These three benches are found approximately 50 to 150 feet below the traditional Middle Bakken and Upper (first bench) Three Forks reservoir and indicate that more oil exists under our leasehold than previously perceived. This, in turn, could translate into increased recoverable reserves from our acreage. To prove these three benches add reserves will require additional drilling. In October 2011, we successfully drilled and completed our first well in the second bench of the Three Forks formation. The Charlotte 2-22H was completed flowing 1,396 Boe per day from the second bench of the Three Forks and is producing in line with a typical commercial first bench Three Forks producing well.

Another significant achievement during 2011 was the successful expansion of the play west of the Nesson anticline. During the year we drilled 80 gross (49.3 net) wells west of the anticline and as of February 15, 2012 had 10 rigs drilling in this area. We also continued to expand the use of our ECO-Pad^TM technology during the year. ECO-Pad technology allows 4 wells (2 in the Bakken Formation and 2 in the Three Forks Formation) 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 reduced by utilizing a walking rig, which moves between wells on hydraulic feet that eliminate the need to break down the rig each time it moves from one well to another well. Completion costs are reduced 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%. As of December 31, 2011, we had completed 12 ECO-Pad locations and had 4 ECO-Pad rigs drilling or completing wells. 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 the year, our access to natural gas pipeline infrastructure also improved significantly. At this time, the majority of the natural gas from our wells is connected to pipeline systems.

During 2011, we increased our standard number of fracture stimulation stages per well from approximately 24 stages to 30 stages. Although there are always overriding geologic factors that influence production, we believe the increase in our estimated average recoverable reserves per well from 518 MBoe gross to 603 MBoe gross in 2011 can be attributed primarily to the increased number of fracture stimulation stages used per well. We continually monitor results and modify our fracture stimulation techniques to maximize the amount of crude oil we recover from the reservoirs.

During 2012, we plan to invest approximately $950 million drilling 470 gross (114.6 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 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 the North Dakota Bakken field

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will eventually be developed on 320-acre spacing like the Elm Coulee field in Montana. As of February 15, 2012, we had 19 operated rigs drilling in the North Dakota Bakken and plan to operate 21 rigs drilling in the play through most of 2012.

Montana Bakken. Our Montana Bakken production is located primarily in the Elm Coulee field in Richland County, Montana. The Elm Coulee field was listed by the Energy Information Administration in 2010 as the 17^th largest onshore field in the lower 48 states of the United States ranked by 2009 proved liquid reserves. During 2011 we completed 21 gross (12.8 net) wells, bringing our total number of wells drilled in the Montana Bakken to 193 gross (122.1 net) wells as of December 31, 2011. Our production increased to an average rate of 5,971 net Boe per day during the month of December 2011, up 26% from the average daily rate in December 2010. As of December 31, 2011 our Montana Bakken properties represented 9% of our PV-10 and 8% of our average daily Boe production for the three months ended December 31, 2011. During the year we added 36,278 gross (20,339 net) acres in the Montana Bakken play. As of December 31, 2011, we owned 347,790 gross (252,626 net) acres, of which 30% of the net acreage is developed and the remaining 70% of the net acreage is undeveloped.

2011 was a breakthrough year for us in the Montana Bakken as we successfully began to expand and develop the Elm Coulee field using state of the art drilling and completion technology. Areas once considered non-commercial based on old open hole completion technology have now proved to be commercial using cased hole, multi-stage fracture stimulation technology. During 2011 we completed 15 gross (12.3 net) wells in the immediate Elm Coulee field area. These wells included in-field, step-out and strategic exploratory wells that were completed flowing at initial 24 hour rates of up to 1,163 Boe per day. Based on the 2011 drilling program, the productive limits of the Elm Coulee field were expanded 2 to 5 miles to the north onto portions of our undeveloped leasehold.

We plan to invest approximately $90.7 million drilling 18 gross (11.6 net) wells in the Montana Bakken during 2012. Our drilling will focus on in-field development and continued expansion of the Elm Coulee field onto our undeveloped acreage north of the field. As of February 15, 2012, we had 3 rigs drilling in the Montana Bakken and plan to maintain 3 rigs in the play through most of 2012. As of December 31, 2011, we had 81 gross (50.0 net) proved undeveloped locations identified in the Montana Bakken.

Red River Units

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 2010 as the 9th largest onshore field in the lower 48 states of the United States ranked by 2009 liquid proved reserves.

Our Red River units represented 22% of our PV-10 as of December 31, 2011 and 20% of our average daily Boe production for the three months ended December 2011. Production from these legacy properties increased 5% in 2011 compared to 2010 due to new wells being completed and enhanced recovery techniques being successfully applied. For the month of December 2011, total production from the units averaged 14,925 Boe per day, an increase of 9% from average daily production in December 2010. Proved reserves grew 18% year-over-year to 64 MMBoe as of December 31, 2011. We are continuing to extend the peak performance life of our properties in the Red River units primarily by increasing our water and air injection capabilities and taking other measures to optimize production. As of December 31, 2011, we had 150,534 gross (131,428 net) acres in the Red River units, all of which is developed acreage.

In 2012, we plan to complete pattern drilling on the waterflood project in the Cedar Hills units and continue development activity in the Medicine Pole Hills units and Buffalo units. We have allocated $48.5 million of our 2012 capital expenditure budget to the Red River units, which will support one drilling rig and continued investment in facilities and infrastructure.

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Cedar Hills Units. The 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, 2011, we had drilled 238 horizontal wells within this 49,700-acre unit, with 117 producing wellbores and the remainder serving as injection wellbores. We own and operate a 96% working interest in the CHNU.

The Cedar Hills West unit (“CHWU”), in Fallon County, Montana, is contiguous to the northern portion of CHNU. As of December 31, 2011, this 7,800-acre unit contained 12 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 high-pressure air injection 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, we began to transition the units to 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 it is more economical to 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 11,401 Boe per day in December 2011. During 2012, we plan to complete the increased density drilling for both producing wells and injection wells. We plan to invest approximately $36.6 million during 2012 for capital workovers, facilities, and the drilling of 12 gross (11.5 net) wells in the Cedar Hills units.

Medicine Pole Hills Units. The three Medicine Pole Hills units (“MPHU”), consisting of the original MPHU, West MPHU, and South MPHU, are approximately five miles east of the southern portion of the CHNU and are located in Bowman County, North Dakota. We acquired the original 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 own and operate working interests of 62%, 92%, and 98% in the original MPHU, West MPHU, and South MPHU, respectively. Total production from the three units averaged 1,787 Boe per day during December 2011, 17% higher than average daily production in December 2010. In 2012, we plan to install a third electric driven air compressor (15 MMcf per day injection capacity) to replace the four remaining higher maintenance gas driven air compressors. We plan to invest approximately $6.4 million during 2012 for drilling, capital workovers, upgrading facilities, and other activities in the Medicine Pole Hills units.

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. We own and operate working interests of 97%, 97%, and 96% in the 33,000 acres comprising the Buffalo, West Buffalo, and South Buffalo units, respectively. When we purchased the three 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. From 2005 through 2011, we re-entered 46 existing vertical wells and drilled horizontal laterals to increase production and sweep efficiency from the three units. Total production from the three units for the month of December 2011 averaged 1,737 Boe per day, an increase of 22% from average daily production in December 2010. In 2012, we plan to invest approximately $5.5 million for capital workovers, upgrading facilities, and other activities in the Buffalo Red River units.

Niobrara

The Upper Cretaceous Niobrara formation has emerged as another potential crude oil resource play in various basins throughout the northern Rocky Mountain region including the DJ Basin of Colorado and Wyoming. As with most resource plays, the Niobrara has a history of producing through conventional technology with some of

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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. Historically, natural fracturing has played a key role in producing the Niobrara due to the low porosity and low permeability of the formation. Because of this, conventional production has been very localized and limited in extent. We believe the Niobrara can be produced on a more widespread basis using horizontal multi-stage fracture stimulation technology where the Niobrara is thermally mature.

DJ Basin. The DJ Basin Niobrara play emerged as a potential crude oil resource play in 2010 and attracted a flurry of leasing activity based on drilling results announced early in 2010. Since that time, approximately 161 horizontal Niobrara wells have been reported as completed with initial production rates of up to 1,665 Boe per day. The most consistent results have been reported on the Colorado portion of the DJ Basin, particularly Weld County Colorado. As of December 31, 2011, we owned 154,799 gross (93,339 net) acres in the DJ Basin Niobrara play. Approximately 37% of the net acreage is located in Weld and Morgan Counties, Colorado and 63% in Laramie, Goshen and Platte Counties in Wyoming.

During 2011, we drilled our first horizontal Niobrara wells in the DJ Basin and as of February 15, 2012, we have completed 5 gross (3.6 net) Niobrara wells. Results have varied which is typical in the early stages of any play as we refine our geologic model and completion techniques. Thus far, the Staudinger 1-31H (56% WI) is our best performing well, producing 736 Boe per day during its initial 24 hour test period. Early performance of the Staudinger 1-31H is encouraging and in line with our economic model for the play. Of note, we continue to be a leader with technology as our Staudinger 1-31H and Newton 1-4H wells were the first 1,280-acre unit wells drilled in the play. During 2011 we acquired 92 square miles of 3D seismic data to guide future drilling.

In 2012, we plan to invest approximately $59 million to drill 26 gross (12.0 net) wells in the DJ Basin Niobrara play. This drilling will continue to be focused in Weld County, Colorado. The drilling will include step-out and exploratory wells that are strategically located to de-risk our acreage.

South Region

Our properties in the South region represented 12% of our PV-10 as of December 31, 2011 and 22% of our average daily Boe production for the three months ended December 31, 2011. During the three months ended December 31, 2011, our average daily production from such properties was 2,316 net Bbls of crude oil and 85,631 net Mcf of natural gas, up 82% from the same period in 2010. 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 11% of our PV-10 as of December 31, 2011 and 18% of our net average daily Boe production for the three months ended December 31, 2011. Production from the Oklahoma Woodford for 2011 totaled 3,548 MBoe (21,288 MMcfe), up 84% over 2010. Production increased throughout the year, and the average daily production for our Oklahoma Woodford properties for the month of December 2011 was 15,026 Boe per day, up 145% over our daily average production for the month of December 2010. As of December 31, 2011, we held 617,313 gross (332,162 net) acres in the play. As of December 2011, 25% of the net acreage is developed and the remaining 75% of the net acreage is undeveloped.

During 2011 we completed 121 gross (46.6 net) Oklahoma Woodford wells. During 2012, we plan to invest approximately $356.1 million drilling 160 gross (46.6 net) wells in the Oklahoma Woodford. As of February 15, 2012 we had 12 rigs drilling in the Oklahoma Woodford and plan to operate 10 rigs in the play through most of 2012.

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Anadarko Woodford. The Anadarko Woodford represented 9% of our PV-10 as of December 31, 2011 and 13% of our average daily Boe production for the three months ended December 31, 2011. Our Anadarko Woodford production grew 367% year-over-year due to our increased drilling activity in 2011. During the month of December 2011, our Anadarko Woodford production averaged 10,675 net Boe per day, up 465% over our average daily production in December 2010.

Over the past 2 years, the Anadarko Woodford play has developed into an established resource play that appears to cover at least 1,800 square miles (1,152,000 acres) along the eastern flank of the Anadarko Basin. We control one of the largest acreage positions in the Anadarko Woodford play, with 444,345 gross (278,116 net) acres under lease as of December 31, 2011. This acreage is located in Canadian, Blaine, Dewey, Caddo, Grady and McClain counties in Oklahoma, extending approximately 50 miles northwest and 75 miles southeast from the Cana field area, where the initial discovery was made in late 2007. Approximately 65% of our acreage is located in our Northwest Cana project and 35% is located in our Southeast Cana project.

During 2011, we accelerated our drilling program and completed 103 gross (41.8 net) wells as compared to 16 gross (8.2 net) wells in 2010. Our 2011 drilling program was designed to expand the known extents of Anadarko Woodford production on our acreage. Under this program, we successfully completed strategic wells in both our Northwest Cana and Southeast Cana projects and de-risked more of our acreage in the play. In particular, the Lambakis 1-11H (98% WI) and the Lyle 1-30H (99%WI) wells in Southeast Cana established commercial production 30 miles south of the known limit of Woodford production at year-end 2010. Both wells are exceptional wells producing a combination of oil, natural gas and natural gas liquids. The Lambakis 1-11H produced 5.4 MMcf of natural gas and 160 Bbls of crude oil per day during its initial 24 hour test period. The Lyle 1-30H produced 7.1 MMcf of natural gas and 325 Bbls of crude oil per day during its initial 24 hour test period. The high liquids content of the natural gas is significant as it increases the overall value of the production due to the higher BTU content of the natural gas.

In February 2012, we completed the first cross-unit well drilled in the Anadarko Woodford play. The Toms 1-21XH (90% WI) in Blaine County, Oklahoma produced 1.9 MMcf per day and 965 Bbls per day during its initial 24 hour test period. The well was drilled to a total depth of 20,523 feet and included a 9,500 foot lateral, which is approximately twice the length of a typical horizontal Anadarko Woodford well. Cross-unit spaced drilling is significant because it allows operators to access two spacing units from a single long wellbore. From our experience, we expect the longer laterals will reduce costs, increase well productivity and enhance the overall economics of the play. We are very encouraged by the results of our first cross-unit well and expect to increase the use of this technology as we develop the field.

During 2011, we acquired approximately 600 square miles of proprietary 3D seismic data. Acquiring this data was a critical step in the development of the Northwest Cana and Southeast Cana projects as the data will be used to guide our drilling for years to come. Another critical development in 2011 was the increased pipeline capacity to transport natural gas from the Northwest Cana area. Curtailments experienced in 2011 should be eliminated in 2012 as a result of new pipeline infrastructure scheduled for operation in early 2012.

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. To date, approximately one third of our Woodford wells have encountered indications of productive reservoirs in overlying Tonkawa, Red Fork, Morrow, Springer and/or Mississippian reservoirs, while drilling to the Woodford shale.

In 2012, we plan to invest approximately $354.5 million to drill 159 gross (46.1 net) wells to further delineate and develop the Anadarko Woodford on our acreage. As of February 15, 2012, we had 12 operated rigs drilling in the Anadarko Woodford play and plan to operate 10 rigs in the play through most of 2012. To support our

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drilling program, we expect to invest approximately $11.9 million to acquire approximately 350 square miles of proprietary 3D seismic to guide future drilling on our acreage. As of December 31, 2011, we had a total of 251 gross (120.1 net) proved undeveloped locations identified on our Anadarko Woodford acreage.

Arkoma Woodford. The Arkoma Woodford represented 2% of our PV-10 as of December 31, 2011 and 5% of our average daily Boe production for the three months ended December 31, 2011. Year-over-year, Arkoma Woodford production was down 6% due to our scaled back drilling program in 2011. As of December 31, 2011 we have completed a total of 367 gross (59.7 net) wells in the Arkoma Woodford play.

In 2011, we slowed our pace of drilling in the Arkoma Woodford as available capital was redirected to the more liquid-rich Anadarko Woodford. During the year we completed a total of 18 gross (4.8 net) wells, as compared to 50 gross (6.5 net) wells in 2010. The wells were focused primarily on our East McAlester acreage and produced up to 5,055 Mcf per day during their initial 24 hour test period. As of December 31, 2011, we owned approximately 132,898 gross (39,594 net) acres in the Arkoma Woodford play, of which 63% of our net acreage is developed and the remaining 37% of our net acreage is undeveloped.

In 2011, we removed 21.9 MMBoe of proved undeveloped reserves from our Arkoma Woodford district, representing 213 gross (44.8 net) PUD locations. We had planned to develop these PUD reserves by year-end 2013. However, given current and projected prices for natural gas, we elected to defer drilling and therefore declassified these PUD reserves. A remaining total of 97 gross (46.5 net) PUD locations, representing 26.0 MMBoe of remaining PUD reserves, have been identified on this acreage as of December 31, 2011. In 2012, we plan to finish wells in progress at year-end 2011 but plan to defer any further drilling until natural gas prices improve. We expect to invest approximately $1.6 million to drill 1 gross (0.5 net) well in the Arkoma Woodford play during 2012.

East Region

Our properties in the East region represented 1% of our PV-10 as of December 31, 2011. During the three months ended December 31, 2011, our average daily production from such properties was 1,178 net Boe per day. Our principal producing properties in this region are located in the Illinois Basin and Michigan Basin in the eastern United States. We continue to maximize the performance of these properties through workovers, recompletions and drilling as warranted. As of December 31, 2011, we had 69,042 gross (49,545 net) acres in the Trenton-Black River area of Michigan, of which 1% of the net acreage is developed and 99% of the net acreage is undeveloped. Drilling on these properties has been guided by our proprietary 3D seismic data. We currently own 64 square miles of 3D seismic data on the properties and have numerous potential drilling locations identified for future drilling. In 2012, we plan to acquire an additional 30 square miles of 3D seismic to identify additional opportunities for drilling.

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Table of Contents

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, 2011, 2010 and 2009 in total and for each field containing 15 percent or more of our total proved reserves as of December 31, 2011: