CONTINENTAL RESOURCES, INC - Annual Report: 2012 (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, 2012

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: (405) 234-9000

Securities registered pursuant to 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, 2012 was approximately $3.8 billion, based upon the closing price of $66.62 per share as reported by the New York Stock Exchange on such date.

185,602,632 shares of our $0.01 par value common stock were outstanding on February 15, 2013.

DOCUMENTS INCORPORATED BY REFERENCE

Portions of the definitive Proxy Statement of Continental Resources, Inc. for the Annual Meeting of Shareholders to be held in May 2013, 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 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.

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“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 an oil and gas lease continued into effect into its secondary term for so long as a producing oil and/or gas well is located on any portion of the leased premises or lands pooled therewith.

“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 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.

“SCOOP” Refers to the South Central Oklahoma Oil Province, a term we use to describe an emerging area of crude oil and liquids-rich properties located in the Anadarko basin of the Oklahoma Woodford formation.

“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 of January to December 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.

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

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“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/or 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 a 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.

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Cautionary Statement for the Purpose of the “Safe Harbor” Provisions of the Private Securities Litigation Reform Act of 1995

This report includes “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934. All statements other than statements of historical fact, including, but not limited to, statements or information concerning the Company’s future operations, performance, financial condition, production and reserves, schedules, plans, timing of development, returns, budgets, costs, business strategy, objectives, and cash flow, included in this report are forward-looking statements. When used in this report, the words “could,” “may,” “believe,” “anticipate,” “intend,” “estimate,” “expect,” “project,” “budget,” “plan,” “continue,” “potential,” “guidance,” “strategy” 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. Although the Company believes the expectations reflected in the forward-looking statements are reasonable and based on reasonable assumptions, no assurance can be given that such expectations will be correct or achieved or that the assumptions are accurate. 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, quarterly reports, registration statements filed from time to time with the SEC, and other announcements we make from time to time.

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 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, completion 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, 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 consolidated financial statements and the notes to those 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 properties 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, and the Red River units. The South region includes Kansas and all properties south of Kansas and west of the Mississippi River including the South Central Oklahoma Oil Province (“SCOOP”), Northwest Cana and Arkoma Woodford plays in Oklahoma. The SCOOP and Northwest Cana plays were previously combined by the Company and referred to as the Anadarko Woodford play. In December 2012, we sold the producing crude oil and natural gas properties in our East region. Our remaining East region properties are comprised of undeveloped leasehold acreage east of the Mississippi River that will be managed as part of our exploration program.

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 82% of our estimated proved reserves as of December 31, 2012 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 649.0 MMBoe of proved crude oil and natural gas reserves through extensions and discoveries from January 1, 2008 through December 31, 2012 compared to 86.7 MMBoe added through proved reserve acquisitions during that same period. In October 2012, we announced a new five-year growth plan to triple our production and proved reserves from year-end 2012 to year-end 2017.

As of December 31, 2012, our estimated proved reserves were 784.7 MMBoe, with estimated proved developed reserves of 317.8 MMBoe, or 40% of our total estimated proved reserves. Crude oil comprised 72% of our total estimated proved reserves as of December 31, 2012. For the year ended December 31, 2012, we generated crude oil and natural gas revenues of $2.4 billion and operating cash flows of $1.6 billion. For the year ended December 31, 2012, daily production averaged 97,583 Boe per day, a 58% increase over average production of 61,865 Boe per day for the year ended December 31, 2011. Average daily production for the quarter ended December 31, 2012 increased 42% to 106,831 Boe per day from 75,219 Boe per day for the quarter ended December 31, 2011.

The following table summarizes our total estimated proved reserves, PV-10 and net producing wells as of December 31, 2012, average daily production for the quarter ended December 31, 2012 and the reserve-to-production index in our principal regions. Our reserve estimates as of December 31, 2012 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 99% of our PV-10, 99% of our proved crude oil reserves, and 96% of our proved natural gas reserves as of December 31, 2012. 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, 2012 were determined using the 12-month unweighted

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arithmetic average of the first-day-of-the-month commodity prices for the period of January 2012 through December 2012, without giving effect to derivative transactions, and were held constant throughout the lives of the properties. These prices were $94.71 per Bbl for crude oil and $2.76 per MMBtu for natural gas ($86.56 per Bbl for crude oil and $4.31 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, 2012 and the budgeted amounts we plan to spend on exploratory and development drilling, capital workovers, and facilities in 2013.

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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, 2012, crude oil comprised 72% of our total proved reserves and 70% of our 2012 annual production. Although we do pursue liquids-rich natural gas opportunities, such as those found in the SCOOP, 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, 2008 through December 31, 2012, proved crude oil and natural gas reserve additions through extensions and discoveries were 649.0 MMBoe compared to 86.7 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, 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 33,831 MBoe, or 95%, of our total crude oil and natural gas production for the year ended December 31, 2012.

Acquire Significant Acreage Positions in New or Developing Plays. In addition to the 971,634 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 375,412 net undeveloped acres in other crude oil and natural gas plays as of December 31, 2012. 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.

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Our Business Strengths

We have a number of strengths we believe will help us successfully execute our business strategy:

Large Acreage Inventory. We hold 1,347,046 net undeveloped acres and 897,542 net developed acres as of December 31, 2012. Approximately 72% of the net undeveloped acres are located within unconventional 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 Lodgepole (North Dakota), Morrow-Springer (Western Oklahoma) and Frio (South Texas) plays.

Experience with Horizontal Drilling and Enhanced Recovery Methods. We have substantial experience with horizontal drilling and enhanced recovery methods. In 1992, we drilled our first horizontal well, and we have drilled over 1,800 horizontal wells since that time. We continue to be a leader in the development of new drilling and completion technologies. Our trademarked ECO-Pad drilling concept, which allows for drilling multiple wells from a single pad, is becoming a standard drilling approach in the industry because it improves land use and increases operating efficiencies. We started with drilling four wells per pad but have since begun drilling as many as 14 wells on a pad site. We are also on the leading edge of extending lateral drilling lengths, in some instances up to three miles. In 2012, we completed the first multiple-unit spaced well drilled in Oklahoma, which had a horizontal section that was twice the length of previous laterals in the area. Longer laterals are believed to have a positive impact on well productivity and economics. Additionally, we are pioneering the exploration and evaluation of the lower layers or “benches” of the Three Forks formation in the Bakken field, initially targeting the first bench of the Three Forks in mid-2008 followed by the successful completion of our first well in the second bench in October 2011. In 2012, we successfully completed the first well ever drilled in the third bench of the Three Forks, the discovery of which may lead to an increase in recoverable reserves for the Company and the Bakken field as a whole.

Control Operations Over a Substantial Portion of Our Assets and Investments. As of December 31, 2012, we operated properties comprising 84% 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 9 senior officers have an average of 29 years of crude oil and natural gas industry experience.

Strong Financial Position. We have a revolving credit facility with lender commitments totaling $1.5 billion and a borrowing base of $3.25 billion as of February 15, 2013, with available borrowing capacity of $655.2 million at that date after considering outstanding borrowings and letters of credit. While our current commitments total $1.5 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 2013 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 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

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, 2012. The total Standardized Measure of discounted cash flows as of December 31, 2012 is also presented. Ryder Scott evaluated properties representing approximately 99% of our PV-10, 99% of our proved crude oil reserves, and 96% of our proved natural gas reserves as of December 31, 2012, 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, 2012 were determined using the 12-month unweighted average of the first-day-of-the-month commodity prices for the period of January 2012 through December 2012, without giving effect to derivative transactions, and were held constant throughout the lives of the properties. These prices were $94.71 per Bbl for crude oil and $2.76 per MMBtu for natural gas ($86.56 per Bbl for crude oil and $4.31 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, 2012.

Reserves at December 31, 2010, 2011 and 2012 were computed using the 12-month unweighted average of the first-day-of-the-month commodity prices as required by 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 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 each of the three years reflected in the table above were primarily due to increases in proved reserves associated with our successful drilling activity and strong production growth in the Bakken field in North Dakota. In 2012, we continued to make significant headway in developing and expanding our North Dakota Bakken assets, both laterally and vertically, through

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strategic exploration, planning and technology. We expect a significant portion of future reserve additions will come from our major development projects in the Bakken, SCOOP and Northwest Cana plays.

Sales of minerals in place. These are reductions to proved reserves that result from the disposition of properties during a period. During the year ended December 31, 2012, we disposed of certain non-strategic properties in Oklahoma, Wyoming, and our East region in an effort to redeploy capital to our strategic areas that we believe will deliver higher future growth potential. See Part II, Item 8. Notes to Consolidated Financial Statements—Note 13. Property Acquisitions and Dispositions for further discussion of our 2012 dispositions. We may continue to seek opportunities to sell non-strategic properties if and when we have the ability to dispose of such assets at favorable terms.

Purchases of minerals in place. These are additions to proved reserves that result from the acquisition of properties during a period. Purchases for the year ended December 31, 2012 primarily reflect the Company’s acquisition of properties in the Bakken play of North Dakota during the year. See Part II, Item 8. Notes to Consolidated Financial Statements—Note 13. Property Acquisitions and Dispositions and Note 14. Property Transaction with Related Party for further discussion of our 2012 acquisitions. We may continue 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 reserves evaluation consulting firm, estimated, in accordance with generally accepted petroleum engineering and evaluation principles and definitions and guidelines established by the SEC, 99% of our PV-10, 99% of our proved crude oil reserves, and 96% of our proved natural gas reserves as of December 31, 2012 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 is in contact 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 the information is filed with the SEC on Form 10-K. Additionally, certain members of our senior management review and approve the Ryder Scott reserve report and on a quarterly basis review 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 27 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 Senior Vice President—Operations and Resource Development. The reserve estimates are reviewed and approved by the President and Chief Operating Officer and certain other members of senior management.

Proved Undeveloped Reserves. Our proved undeveloped reserves at December 31, 2012 were 466,891 MBoe, consisting of 334,293 MBbls of crude oil and 795,585 MMcf of natural gas. In 2012, we developed approximately 17% of our proved undeveloped reserves booked as of December 31, 2011 through the drilling of 231 gross (127.9 net) development wells at an aggregate capital cost of approximately $892 million. Also in

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2012, we removed 202 gross (90.0 net) PUD locations, which resulted in the removal of 3.5 MMBo and 183.8 Bcf (34.2 MMBoe) of proved undeveloped reserves. These removals were predominantly due to our decision to declassify 100.4 Bcf (16.7 MMBoe) of proved undeveloped reserves in our Arkoma Woodford district, which consists primarily of dry gas. For similar reasons, we removed 1.4 MMBo and 73.3 Bcf (13.6 MMBoe) of proved undeveloped reserves in our Northwest Cana district. 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 $1.8 billion in 2013, $2.2 billion in 2014, $2.0 billion in 2015, $1.4 billion in 2016, and $0.9 billion in 2017.

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) 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 expect to increase our focus on developing our PUD locations. While full development of our current PUD inventory is expected to occur within five years, we believe additional PUD locations will be generated through drilling activities.

Developed and Undeveloped Acreage

The following table presents our total gross and net developed and undeveloped acres by region as of December 31, 2012:

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The following table sets forth the number of gross and net undeveloped acres as of December 31, 2012 that are expected to 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, 2012, we drilled exploratory and development wells as set forth in the table below:

As of December 31, 2012, there were 323 gross (122.4 net) wells in the process of drilling, completing or waiting on completion.

As of February 15, 2013, we operated 28 rigs on our properties. Our rig activity during 2013 will depend on potential drilling efficiency gains and 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 budget and on a timely basis.

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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 2013. Although we cannot provide any assurance, we believe our cash flows from operations, remaining cash balance, and our revolving credit facility, including our ability to increase our borrowing capacity thereunder, will be sufficient to satisfy our 2013 capital budget. We may choose to access the capital markets for additional financing to take advantage of business opportunities that may arise if such financing can be arranged at favorable terms. 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, unbudgeted acquisitions, 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 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.

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 90% of our PV-10 as of December 31, 2012 and 78% of our average daily Boe production for the three months ended December 31, 2012. For the three months ended December 31, 2012, our average daily production from such properties was 83,205 Boe per day, an increase of 45% over our average daily production for the three months ended December 31, 2011. Our principal producing properties in the North 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. In October 2011, the USGS began a study to update their 2008 assessment of recoverable reserves for the Bakken field to include reserves from the Three Forks formation and take into account improved well performance due to advances in drilling, completion and production technologies. Results of the USGS study may be announced in late 2013.

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Industry-wide production from the Bakken field reached a record 801,500 Boe per day in October 2012, up 55% over October 2011 based on data published by IHS Inc. Industry-wide drilling activity in the Bakken field also reached record levels at 229 rigs in June 2012. North Dakota now ranks as the second largest crude oil producing state in the U.S. due to production growth in the Bakken field. We continue to be a leader in the development and expansion of the Bakken field and control the largest leasehold position with approximately 1,725,089 gross (1,139,803 net) acres as of December 31, 2012. We are also the most active driller in the Bakken field, with 21 operated rigs drilling as of February 15, 2013. During 2012, we completed 573 gross (204.1 net) wells in the Bakken field. Our properties within the Bakken field represented 74% of our PV-10 as of December 31, 2012 and 63% of our average daily Boe production for the three months ended December 31, 2012. As of December 31, 2012 we had completed 1,887 gross (757.7 net) wells in the Bakken field. Our inventory of proved undeveloped drilling locations in the Bakken field as of December 31, 2012 totaled 1,501 gross (847.3 net) wells.

During 2012, we saw our production, reserves and acreage position in the Bakken field grow while substantial portions of our undeveloped acreage continued to be de-risked due to the record levels of drilling activity in North Dakota. Our Bakken field production averaged 67,522 Boe per day during the three months ended December 31, 2012, up 64% from our average daily Bakken field production for the three months ended December 31, 2011. Our total proved Bakken field reserves at December 31, 2012 were 564 MMBoe, up 92% over our proved Bakken field reserves as of December 31, 2011.

Our development drilling activity accelerated in 2012 since much of the Bakken field is now entering the development mode. This allowed us to increase the use of our ECO-Pad technology in 2012. Using ECO-Pad technology allows us to utilize more efficient centralized production facilities that accelerate production and reduce the environmental footprint of our operations. Combined, we expect these efficiencies will result in reduced costs for wells drilled from ECO-Pads. Approximately 18% of our operated wells completed in 2012 were drilled from ECO-Pads. At February 15, 2013, 67% of our 21 operated rigs in the Bakken were capable of ECO-Pad drilling and 14 rigs were actively drilling pad locations.

We strengthened our Bakken focus in 2012 by executing strategic property acquisitions throughout the year, which allowed us to increase our ownership in existing and future operated and non-operated wells in the play. We believe the acquisitions will allow us to leverage the scale and efficiency of our Bakken operations to help lower our drilling and completion costs. As a result of our leasing and acquisition activities, we increased our net acreage position in the Bakken field by 24% during 2012, from 915,863 net acres as of December 31, 2011 to 1,139,803 net acres as of December 31, 2012. Approximately 51% of our net acreage in the Bakken field is developed and the remaining 49% of our net acreage is undeveloped as of December 31, 2012.

We plan to invest approximately $2.4 billion drilling 558 gross (226.2 net) wells in the Bakken field during 2013, of which approximately 83% will be invested in North Dakota and the remaining 17% will be invested in Montana. We plan to average 22 rigs drilling in the Bakken field throughout the year, with 17 rigs located in North Dakota and 5 rigs in Montana.

North Dakota Bakken. Our production and reserve growth in the Bakken field during 2012 came primarily from our activities in North Dakota. Production increased to an average rate of 59,019 Boe per day during the three months ended December 31, 2012, up 66% from the average daily rate for the three months ended December 31, 2011. Proved reserves grew 102% year-over-year to 518 MMBoe as of December 31, 2012. As of December 31, 2012, our North Dakota Bakken properties represented 67% of our PV-10 and 55% of our average daily Boe production for the three months ended December 31, 2012. We completed 526 gross (173.0 net) wells during 2012, bringing our total number of wells drilled in the North Dakota Bakken to 1,589 gross (576.5 net) as of December 31, 2012. As of December 31, 2012, we had 1,378,784 gross (866,967 net) acres in the North Dakota Bakken field, of which 55% of the net acreage is developed and 45% of the net acreage is undeveloped. Our inventory of proved undeveloped locations stood at 1,421 gross (791.3 net) wells as of December 31, 2012.

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Our drilling activity in the North Dakota Bakken field during 2012 was diversified, reflecting the extensive nature of our acreage position. With 866,967 net acres in the North Dakota Bakken as of December 31, 2012, some areas of the field were under development while other areas were being tested through step-out and exploratory drilling. All combined, in 2012 we made significant progress in developing and expanding our North Dakota Bakken assets through strategic exploration, planning and technology.

During 2012, we expanded the known productive extents of the Bakken field laterally and vertically through strategic step-out and exploratory drilling. Our step-out drilling continued to expand the productive footprint of the field west and east of the Nesson anticline. Of particular significance to the Company and the Bakken field in general during 2012 was our ongoing exploration efforts to evaluate the Lower Three Forks formation. Through our independent coring program, we discovered there were three additional layers or “benches” of crude oil bearing reservoir rock in the Lower Three Forks formation. We refer to these three benches as the second, third and fourth benches of the Three Forks formation (“TF2”, “TF3” and “TF4”, respectively) and they are located approximately 50 to 150 feet below the traditional Middle Bakken (“MB”) and Upper Three Forks (“TF1”) reservoirs. This discovery redefined the Bakken petroleum system and prompted the NDIC to expand the definition of the Bakken reservoir to include all zones from 50 feet above the top of the Bakken formation down to the base of the Three Forks formation across much of the Bakken field in North Dakota.

The discovery of three additional benches indicates the Lower Three Forks formation has the potential to add incremental reserves in the Bakken field. The existence of more reserves in place could potentially translate into an increase in recoverable reserves for the Company and the Bakken field as a whole. To determine if there are incremental reserves to be recovered from the Lower Three Forks formation, we have begun drilling wells to test the TF2, TF3 and TF4 reservoirs. In October 2011, we successfully completed our first well in the TF2. The Charlotte 2-22H was completed flowing 1,396 Boe per day from the TF2 and as of February 15, 2013 the well had produced 107 MBoe and continues to produce in line with a typical commercial TF1 producing well. In November 2012, we successfully completed the first well ever drilled in the TF3. The Charlotte 3-22H was completed flowing 953 Boe per day from the TF3 and as of February 15, 2013 had produced 33 MBoe and continues to produce in line with a typical commercial TF1 producing well. In 2013, we plan to drill 20 gross (15.2 net) strategically placed wells throughout our Bakken acreage to accelerate our assessment of the Lower Three Forks reservoirs.

During 2013, we plan to invest approximately $2.0 billion drilling 507 gross (185.2 net) wells in the North Dakota Bakken field. Approximately 18% of the capital expenditures are expected to be spent on exploratory drilling to test the lower benches of the Three Forks formation and conduct multi-zone pilot development projects. These pilot development projects will test the viability of developing four reservoirs (MB, TF1, TF2, and TF3) on 320-acre and 160-acre spacing. The remainder of the capital expenditures are expected to be spent on drilling development and step-out wells in the field. As of February 15, 2013, we had 16 operated rigs drilling in the North Dakota Bakken and plan to operate 17 rigs drilling in the play through most of 2013.

Montana Bakken. Our Montana Bakken properties are located primarily in the Elm Coulee field in Richland County, Montana. The Elm Coulee field was listed by the Energy Information Administration (“EIA”) 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 2012, we completed 47 gross (31.0 net) wells, bringing our total number of wells drilled in the Montana Bakken to 298 gross (181.2 net) wells as of December 31, 2012. Our production increased to an average rate of 8,503 Boe per day for the three months ended December 31, 2012, up 50% from the average daily rate for the three months ended December 31, 2011. As of December 31, 2012 our Montana Bakken properties represented 7% of our PV-10 and 8% of our average daily Boe production for the three months ended December 31, 2012. As of December 31, 2012, we owned 346,305 gross (272,836 net) acres in Montana Bakken, of which 39% of the net acreage is developed and the remaining 61% of the net acreage is undeveloped.

In 2012, we continued to expand the proven extents of 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

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have now proven to be commercial using cased hole, multi-stage fracture stimulation technology. During 2012, our well completions in the immediate Elm Coulee field area included in-field, step-out and strategic exploratory wells that were completed flowing at initial 24 hour rates of up to 1,301 Boe per day. Based on our 2012 drilling program, the productive limits of the Elm Coulee field were expanded up to approximately 10 miles to the north onto portions of our undeveloped leasehold.

We plan to invest approximately $426 million drilling 51 gross (41.0 net) wells in the Montana Bakken during 2013. 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, 2013, we had 5 rigs drilling in the Montana Bakken and plan to maintain 5 rigs in the play through most of 2013. As of December 31, 2012, we had 80 gross (55.9 net) proved undeveloped locations identified in the Montana Bakken.

Red River Units

The Red River units are comprised of eight units located along the Cedar Creek Anticline in North Dakota, South Dakota and Montana that 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 principal producing properties in the Red River units include the Cedar Hills units in North Dakota and Montana, the Medicine Pole Hills units in North Dakota, and the Buffalo Red River units in South Dakota. Our properties in the Red River units comprise a portion of the Cedar Hills field, which was listed by the EIA in 2010 as the 9th largest onshore field in the lower 48 states of the United States ranked by 2009 proved liquid reserves.

All combined, our Red River units represented 15% of our PV-10 as of December 31, 2012 and 14% of our average daily Boe production for the three months ended December 2012. Production from these legacy properties increased 4% in 2012 compared to 2011 due to new wells being completed and enhanced recovery techniques being successfully applied. Proved reserves grew 22% year-over-year to 78 MMBoe as of December 31, 2012. 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, 2012, we had 150,450 gross (135,483 net) acres in the Red River units, all of which is developed acreage.

We have allocated $63 million of our 2013 capital expenditure budget to the Red River units, which will support one drilling rig and continued investment in facilities and infrastructure.

North Region Marketing Activities

Crude Oil. We are building upon a portfolio approach to marketing our crude oil that began in 2008 with our first shipments of crude oil by rail out of the Williston Basin. During 2012, we accessed new market centers on the east and west coasts of the United States and expanded our marketing efforts along the U.S. gulf coast. This approach has provided flexibility to allow us to shift sales of our North region crude oil to markets that provide the most favorable pricing. During 2012, we moved from predominantly using pipelines to deliver our North region crude oil to traditional market centers in Guernsey, Wyoming and Clearbrook, Minnesota to using rail deliveries into U.S. coastal markets that yield superior pricing compared to the unstable mid-continent market centers.

Rail transportation costs are typically higher than pipeline transportation costs per barrel mile; however, the premium received for our North region production being sold at Brent-based prices in U.S. coastal markets compared to mid-continent West Texas Intermediate (“WTI”) benchmark pricing has more than offset the increased transportation costs. We expect that rail transportation will take a prominent role in crude oil deliveries out of the North region throughout 2013 and then may lessen in significance as additional pipeline infrastructure is built out of the Williston Basin to the great lakes, upper mid-west, southern mid-continent and gulf coast regions of the United States. We expect rail transportation costs will then be impacted by pressure to compete with pipeline economics.

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We anticipate volatility in price differentials between the mid-continent and coastal markets will continue through 2013 as infrastructure is built out and refiners establish a desire for the high quality grade of Bakken crude oil. We believe the Bakken field contains superior quality crude oil with ample supply and volume growth to meet refiners’ needs for years to come.

Transportation infrastructure continues to improve in the North region with gathering systems picking up crude oil at well site storage tanks with subsequent delivery to railhead or regional pipeline terminals, thereby mitigating the need for truck deliveries. We expect more of our North region crude oil will be shipped in this fashion through the coming years, especially as we accelerate development drilling using ECO-Pad technology.

Natural Gas. Field infrastructure build-out continued at a rapid pace in the Williston Basin in 2012 as third party midstream gathering and processing companies expanded field gathering and compression facilities, cryogenic processing capacity and natural gas liquids (“NGL”) pipeline and rail capacity to market centers. Aided by improved infrastructure, we reduced the percentage of our operated natural gas production being flared in North Dakota Bakken by approximately 50% in 2012. During December 2012, we flared approximately 10% of produced natural gas volumes on our operated North Dakota Bakken wells and expect to further reduce this amount as we continue to build out infrastructure and transition to a greater use of ECO-Pad development in 2013 and beyond.

South Region

Our properties in the South region represented 10% of our PV-10 as of December 31, 2012 and 21% of our average daily Boe production for the three months ended December 31, 2012. For the three months ended December 31, 2012, our average daily production from such properties was 22,620 Boe per day, up 36% from the same period in 2011. Our principal producing properties in this region are located in the Anadarko and Arkoma basins of Oklahoma, as well as various basins in 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 Anadarko and Arkoma basins. Combined, these properties represented 9% of our PV-10 as of December 31, 2012 and 19% of our average daily Boe production for the three months ended December 31, 2012. Production from the Oklahoma Woodford for 2012 totaled 7,099 MBoe, up 100% over 2011. Average daily production for our Oklahoma Woodford properties for the three months ended December 31, 2012 was 20,064 Boe per day, up 49% over our average daily production for the three months ended December 31, 2011. As of December 31, 2012, we held 804,025 gross (428,192 net) acres in the Oklahoma Woodford. As of December 2012, 28% of the net acreage is developed and the remaining 72% of the net acreage is undeveloped.

During 2012, we completed 93 gross (48.7 net) Oklahoma Woodford wells. During 2013, we plan to invest approximately $455 million drilling 92 gross (41.9 net) wells in the Oklahoma Woodford. As of February 15, 2013 we had 6 rigs drilling in the Oklahoma Woodford and plan to operate an average of 9 rigs in the play through most of 2013.

In 2012, we divided our Anadarko Woodford assets into two projects we refer to as SCOOP and Northwest Cana. Our wells in the SCOOP area typically produce significantly more crude oil and natural gas liquids than wells in Northwest Cana and provide a higher rate of return on the dollars we invest. Consequently, our drilling and development plans for SCOOP differ from our plans for Northwest Cana. As a result, we now report and discuss the two areas separately. The difference between the SCOOP and Northwest Cana areas is rooted in our geologic model that determined the SCOOP area is ideally suited for crude oil and liquids rich production from the Woodford reservoir. Due to the depositional, tectonic and thermal history of the SCOOP area, we believe it contains some of the best and thickest Woodford reservoir rocks in Oklahoma. The Woodford formation is

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thought to be the source of much of the crude oil produced from over 60 different conventional reservoirs in Oklahoma since the early 1900s. Three of the largest crude oil producing counties in Oklahoma are located in the SCOOP play.

SCOOP

Our SCOOP properties are located in southern Oklahoma primarily in Garvin, Grady, Stephens, Carter, McClain and Love Counties. SCOOP represented 7% of our PV-10 as of December 31, 2012 and 7% of our average daily Boe production for the three months ended December 31, 2012. For the year ended December 31, 2012, SCOOP production grew 297% over 2011 due to our increased drilling activity. For the three months ended December 31, 2012, SCOOP production averaged 7,123 Boe per day, up 281% over our average daily production for the three months ended December 31, 2011. As of December 31, 2012 we held 412,816 gross (218,167 net) acres under lease in SCOOP. As of December 31, 2012, 10% of the net acreage is developed and the remaining 90% of the net acreage is undeveloped. Our inventory of proved undeveloped drilling locations in SCOOP as of December 31, 2012 totaled 122 gross (58.4 net) wells.

We completed 47 gross (24.8 net) wells in SCOOP during 2012 and as of December 31, 2012 we had completed a total of 68 gross (37.2 net) wells in SCOOP. Although SCOOP is in the early stages of development, industry-wide drilling results through December 31, 2012 have established a crude oil producing fairway and a condensate rich, natural gas producing fairway that combined is approximately 15 to 20 miles wide and 120 miles long. Our internal reserve models estimate wells in the SCOOP crude oil fairway may produce approximately 626 MBoe per well and wells in the SCOOP’s condensate rich natural gas fairway may produce approximately 1,190 MBoe per well. The SCOOP area could prove to be another significant opportunity for reserve and production growth for the Company.

A possible upside to SCOOP is the potential to encounter additional pay from a variety of conventional and potential unconventional reservoirs overlying and underlying the Woodford formation. There are over 60 different conventional reservoirs known to produce in the SCOOP area. These conventional reservoirs have the potential to produce locally under our SCOOP acreage.

In 2013, we plan to invest approximately $450 million to drill 90 gross (40.5 net) wells in the SCOOP play. We also expect to invest approximately $9 million to acquire 103 square miles of additional proprietary 3D seismic data to guide future drilling. As of February 15, 2013, we had 6 operated rigs drilling in the SCOOP. We plan to add rigs throughout the year targeting 12 rigs by December 2013 with an expected average rig count of 9 for 2013.

Northwest Cana

Our Northwest Cana properties are located in northwestern Oklahoma primarily in Blaine, Dewey and Custer Counties. Northwest Cana represented 2% of our PV-10 as of December 31, 2012 and 9% of our average daily Boe production for the three months ended December 31, 2012. For the year ended December 31, 2012, Northwest Cana production grew 134% over 2011 due to our increased drilling activity. For the three months ended December 31, 2012, Northwest Cana production averaged 9,716 Boe per day, up 22% over our average daily production for the three months ended December 31, 2011. As of December 31, 2012 we held 271,743 gross (178,432 net) acres under lease in Northwest Cana. As of December 31, 2012, 40% of the net acreage is developed and the remaining 60% of the net acreage is undeveloped. During 2012, we completed 43 gross (22.8 net) wells in Northwest Cana and as of December 31, 2012 we had completed a total of 161 gross (73.3 net) wells in Northwest Cana. We had a total of 90 gross (38.6 net) proved undeveloped locations on our Northwest Cana acreage as of December 31, 2012. No significant drilling or development plans are expected to take place in the Northwest Cana play in 2013 due to the pricing environment for natural gas.

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Arkoma Woodford

The Arkoma Woodford represented less than 1% of our PV-10 as of December 31, 2012 and 3% of our average daily Boe production for the three months ended December 31, 2012. Year-over-year, Arkoma Woodford production decreased 2% due to the suspension of our drilling program in 2012 due to the pricing environment for natural gas. In 2012, we completed 3 gross (1.1 net) wells, compared to 18 gross (4.8 net) wells in 2011. As of December 31, 2012 we had completed a total of 395 gross (59.6 net) wells in the Arkoma Woodford play. As of December 31, 2012, we held 119,466 gross (31,593 net) acres under lease in the Arkoma Woodford play. Approximately 83% of our net acreage is developed and the remaining 17% of our net acreage is undeveloped as of December 31, 2012. We had a total of 22 gross (15.2 net) proved undeveloped locations in the Arkoma Woodford as of December 31, 2012. In 2013, we do not plan on drilling any new wells in the play.

South Region Marketing Activities

Crude Oil. Due to the proximity of our South region operations to the market center in Cushing, Oklahoma, we typically sell our South region production directly to midstream trading and transportation companies at the wellhead with price realizations that correlate with WTI benchmark pricing. We anticipate continuing this approach through early 2013 and to begin delivery of production from our SCOOP properties via wellhead pipeline gathering systems directly into Cushing as field infrastructure is constructed and developed.

During 2013, we expect the disparity of WTI pricing to Brent pricing will begin to improve as the recently expanded Seaway Pipeline begins to alleviate the oversupply of crude oil at Cushing and as Permian Basin production begins to take newly-developed routes to gulf coast market centers that do not go to or through Cushing.

Natural Gas. In 2012, field infrastructure build-out continued at a rapid pace in the Anadarko Basin and in SCOOP as third party midstream gathering and processing companies expanded field gathering and compression facilities, cryogenic processing capacity and NGL pipeline capacity to market centers. Throughout our South region leasehold, we are coordinating our well completion operations to coincide with well connections to gathering systems in order to minimize greenhouse gas emissions.

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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, 2012, 2011 and 2010 in total and for each field containing 15 percent or more of our total proved reserves as of December 31, 2012: