UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-K

(Mark One)

For the fiscal year ended December 31, 20102012

ORor

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(405) 234-9000

Securities registered underpursuant 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)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”,filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act. (Check one):

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

The aggregate market value of the voting and non-voting common equity held by non-affiliates of the registrant as of June 30, 20102012 was approximately $1.4$3.8 billion, based upon the closing price of $44.62$66.62 per share as reported by the New York Stock Exchange on such date.

As of February 18, 2011, the registrant had 170,405,395185,602,632 shares of our $0.01 par value common stock outstanding.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 StockholdersShareholders to be held in 2011,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.

Table of Contents

When we refer to “us,” “we,” “our,” “Company,” or “Continental” we are describing Continental Resources, Inc. and our subsidiaries.

Glossary of Crude Oil and Natural Gas Terms

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

“Basin”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.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”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, or in the case of a dry hole, the reporting of abandonment to the appropriate agency.gas.

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

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

“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.

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

“Developmentdevelopment 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.

“Drydry 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 approved by the North Dakota Industrial Commission which allows for drilling fourmultiple wells from a single pad resulting in less environmental impact and lower drilling and completion costs.

“Enhancedenhanced 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 oftensometimes applied when production slows due to depletion of the natural pressure.

“Exploratoryexploratory 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”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”formation” A layer of rock which has distinct characteristics that differs from nearby rock.

“Heldheld by production” or“HBP” Refers to a mineralan oil and gas lease in which an entity is allowed to operate a property ascontinued into effect into its secondary term for so long as a producing oil and/or gas well is located on any portion of the property produces a minimum paying quantity of crude oilleased premises or natural gas.lands pooled therewith.

“Horizontalhorizontal 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.

“Injectionhydraulic 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.

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“MMBtu” One million British thermal units.

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

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

“NYMEX” The New York Mercantile Exchange.

“Netnet 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”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.

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

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“Prospect”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.

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

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

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

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

“Reservoir”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.

“Royaltyresource 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 that are produced from a crude oil or natural gas property. A royalty interest owner does not bear any of the exploration, development, or operating expenses associated with drilling and producing a crude oil or natural gas property.

“Spacing”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.

“Standardizedstandardized 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 (for year-end 2010 and 2009) or year-end prices (for 2008 and prior) to the estimated future production of year-end proved reserves. Future cash inflows are reduced by estimated future production and development costs based on period-end costs to determine pre-tax cash inflows. Future income taxes, if applicable, are computed by applying the statutory tax rate to the excess of pre-tax cash inflows over ourthe 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-outstep-out well” or“Stepstep 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.

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

“Undevelopedundeveloped 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 andand/or natural gas.

“Unit”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”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”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.

“Workingworking 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 Regarding Forward-Looking Statements

Certain statements and information in this report may constitute “forward-looking statements” withinfor the meaningPurpose of the “Safe Harbor” Provisions of the Private Securities Litigation Reform Act of 1995.1995

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”“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 the headingPart I, Item 1A. Risk Factors included in this report.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 our: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 the development, production, and sale of, crude oil and natural gas. These risks include, but are not limited to, commodity price volatility, inflation, lack of availability of drilling, 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 underPart 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 historical consolidated financial statements and the notes to those historical consolidated financial statements included elsewhere in this report. Unless the context otherwise requires, references in this report to “Continental Resources,” “we,” “ us,” “our, “ours” or “the Company” refer to Continental Resources, Inc. and its subsidiary.

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

General

We are an independent crude oil and natural gas exploration and production company with operationsproperties 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 1993,1989, our activities and growth remained focused primarily in Oklahoma. In 1993,1989, we expanded our activity into the North region. Approximately 70%82% of our estimated proved reserves as of December 31, 20102012 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 allowsallow us to economically develop and produce crude oil and natural gas reserves from unconventional formations. As a result of these efforts, we have grown substantially through the drill bit, adding 287.0649.0 MMBoe of proved crude oil and natural gas reserves through extensions and discoveries from January 1, 20062008 through December 31, 20102012 compared to 3.086.7 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, 2010,2012, our estimated proved reserves were 364.7784.7 MMBoe, with estimated proved developed reserves of 140.4317.8 MMBoe, or 38%40% of our total estimated proved reserves. Crude oil comprised 62%72% of our total estimated proved reserves as of December 31, 2010.2012. For the year ended December 31, 2010,2012, we generated crude oil and natural gas revenues of $948.5 million$2.4 billion and operating cash flows of $653.2 million.$1.6 billion. For the year andended 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, 2010, daily production averaged 43,3182012 increased 42% to 106,831 Boe per day and 48,034from 75,219 Boe per day respectively. This represents growth of 16% and 27% as compared tofor the year and quarter ended December 31, 2009, when daily production averaged 37,324 Boe per day and 37,747 Boe per day, respectively.2011.

The following table summarizes our total estimated proved reserves, PV-10 and net producing wells as of December 31, 2010,2012, average daily production for the three monthsquarter ended December 31, 20102012 and the reserve-to-production index in our principal regions. Our reserve estimates as of December 31, 20102012 are based primarily on a reserve report prepared by our independent reserve engineers, Ryder Scott Company, L.P (“Ryder Scott”). In preparing its report, Ryder Scott evaluated properties representing approximately 94%99% of our PV-10, 97%99% of our proved crude oil reserves, and 94%96% of our proved natural gas reserves as of December 31, 2010.2012. 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, 20102012 were determined using the 12-month unweighted

arithmetic average of the first-day-of-the-month commodity prices for the period of January 20102012 through December 2010,2012, without giving effect to derivative transactions, and were held constant throughout the lifelives of the properties. These prices were $79.43$94.71 per Bbl for crude oil and $4.38$2.76 per MMBtu for natural gas ($71.9286.56 per Bbl for crude oil and $5.07$4.31 per Mcf for natural gas net ofadjusted for location and quality differentials).

The following table provides additional information regarding our key development areas as of December 31, 20102012 and the budgeted amounts we plan to spend on exploratory and development drilling, capital workovers, and facilities in 2011:2013.

Our Business Strategy

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

Focus on crude oil. During the late 1980’s1980s we began to believe that the valuation potential for crude oil exceeded that of natural gas. Accordingly, we began to shift our reserve and production profiles towardstoward crude oil. As of December 31, 2010,2012, crude oil comprises 62%comprised 72% of our total proved reserves and 75%70% of our 20102012 annual production. Although we do pursue liquids-rich natural gas opportunities, such as those found in the Anadarko Woodford shale play in Oklahoma, that have the potential to improve the overall economics of our development projects,SCOOP, we continue to believe that crude oil valuations will be superior to natural gas valuations on a relative Btu basis.basis for the foreseeable future.

Growth Through Low-Cost Drilling. Substantially allA substantial portion of our annual capital expenditures are invested in drilling projects and acreage acquisitions. From January 1, 20062008 through December 31, 2010,2012, proved crude oil and natural gas reserve additions through extensions and discoveries were 287.0649.0 MMBoe compared to 3.086.7 MMBoe of proved reserve acquisitions.

Internally Generated Prospects. Although we periodically evaluate and complete strategic acquisitions, periodically, our technical staff has internally generated substantially alla 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,Dolomite, Bakken, shale and Oklahoma Woodford shale formations. Production rates in the Red River units also have been increased through the use of enhanced recovery technologies.technologies including water and high pressure air injection. Our production from the Red River units, the Bakken field, and the Oklahoma Woodford shaleplay comprised approximately 13,96133,831 MBoe, or 88%95%, of our total crude oil and natural gas production duringfor the year ended December 31, 2010.2012.

Acquire Significant Acreage Positions in New or Developing Plays. In addition to the 1,006,391971,634 net undeveloped acres held in the Montana andBakken play in North Dakota Bakken shale,and Montana, the Oklahoma Woodford play, and the Niobrara play in Colorado and Wyoming, Niobrara shale and Oklahoma Woodford shale fields, we held 364,044375,412 net undeveloped acres in other crude oil and natural gas plays as of December 31, 2010.2012. 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.

Our Business Strengths

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

Large Acreage Inventory. We own 1,370,435hold 1,347,046 net undeveloped acres and 518,333897,542 net developed acres as of December 31, 2010.2012. Approximately 83%72% of the net undeveloped acres are located within unconventional resource plays including, but not limited to,in the Bakken shale in North(North Dakota and Montana, theMontana), Woodford shale in Oklahoma(Oklahoma) and the Niobrara shale in Colorado(Colorado and Wyoming.Wyoming). The remaining balance of the net undeveloped acreage is located in conventional plays including 3D-defined locations for the Trenton-Black River of Michigan, Red River of Montana and North Dakota, Lodgepole of North Dakota,(North Dakota), Morrow-Springer of western Oklahoma(Western Oklahoma) and Frio in south Texas.(South Texas) plays.

Experience with Horizontal Drilling and Enhanced Recovery ExperienceMethods. We have substantial experience with horizontal drilling and enhanced recovery methods. In 1992, we drilled our initialfirst horizontal well, and we have drilled over 1,0001,800 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 substantial experience with enhanced recovery methodsa positive impact on well productivity and currently serve as the operator of 48 waterflood units.economics. Additionally, we operate 7 high pressure air injection (“HPAI”) floods.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, 2010,2012, we operated properties comprising 88%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 79 senior officers have an average of 3029 years of crude oil and natural gas industry experience. Additionally, our technical staff, which includes 40 petroleum engineers, 22 geoscientists and 19 landmen, has an average of 16 years experience in the industry.

Strong Financial Position. As of February 18, 2011, we had outstanding borrowings under ourWe have a revolving credit facility with lender commitments totaling $1.5 billion and a borrowing base of approximately $95.0 million and$3.25 billion as of February 15, 2013, with available borrowing capacity of $652.6 million.$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 that our planned exploration and development activities will be funded substantially from our operating cash flows and borrowings under our revolving credit facility. Our 20112013 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 varydiffer 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.

Crude Oil and Natural Gas Operations

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

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

Proved Reserves

Proved reserves are those quantities of crude oil and natural gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations.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 the PV-10 by reserve category as of December 31, 2010 by reserve category.2012. The total Standardized Measure of discounted cash flows as of December 31, 20102012 is also presented. Ryder Scott evaluated properties representing approximately 94%99% of our PV-10, 97%99% of our proved crude oil reserves, and 94%96% of our proved natural gas reserves as of December 31, 2010,2012, 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, 20102012 were determined using the 12-month unweighted arithmetic average of the first-day-of-the-month commodity prices for the period of January 20102012 through December 2010,2012, without giving effect to derivative transactions, and were held constant throughout the lifelives of the properties. These prices were $79.43$94.71 per Bbl for crude oil and $4.38$2.76 per MMBtu for natural gas ($71.9286.56 per Bbl for crude oil and $5.07$4.31 per Mcf for natural gas net ofadjusted for location and quality differentials).

The following table provides additional information regarding our proved crude oil and natural gas reserves by region as of December 31, 2010.2012.

We have historically added reserves through our exploration program and development activities. SeeItem 1. Business—Crude Oil and Natural Gas Operations. Reserves at December 31, 2010, 2011 and 20092012 were computed using the 12-month unweighted average of the first-day-of-the-month commodity prices as required by the new SEC rules. Reserves at December 31, 2008 were computed using year-end commodity prices pursuant to previous SEC rules. Changes in proved reserves were as follows for the periods indicated:

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

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

strategic exploration, planning and technology. We expect that a significant portion of future reserve additions will come from our major development projects includingin 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, Woodford plays.Wyoming, and our East region in an effort to redeploy capital to our strategic areas that we believe will deliver higher future growth potential. SeePart II, Item 8. Notes to Consolidated Financial Statements—Note 13. Property Acquisitions and Dispositions for further discussion of our 2012 dispositions. We may also purchasecontinue 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. SeePart II, Item 8. Notes to Consolidated Financial Statements—Note 13. Property Acquisitions and Dispositions andNote 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 acquisitions.plays at favorable terms.

Qualifications of Technical Persons and Internal Controls Over Reserves Estimation Process. Ryder Scott, our independent reserve engineers,reserves evaluation consulting firm, estimated, in accordance with generally accepted petroleum engineering and evaluation principles and definitions and guidelines established by the SEC, 94%99% of our PV-10, 97%99% of our proved crude oil reserves, and 94%96% of our proved natural gas reserves as of December 31, 20102012 included in this Annual Report on Form 10-K. The Ryder Scott technical personspersonnel 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 meetsis 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 disseminationthe information is filed with the SEC on Form 10-K. Additionally, certain members of the information. Additionally, our senior management reviewsreview and approvesapprove the Ryder Scott reserve report and on a quarterly basis review any internally estimated significant changes to our proved reserves on a quarterly basis.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 2527 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 PresidentSenior Vice President—Operations and Chief Operating Officer.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 (“PUD”) reserves at December 31, 20102012 were 224,323466,891 MBoe, consisting of 123,512334,293 MBbls of crude oil and 604,869795,585 MMcf of natural gas. In 2010,2012, we developed approximately 11%17% of our proved undeveloped reserves booked as of December 31, 20092011 through the drilling of 130231 gross (60.4(127.9 net) development wells at an aggregate capital cost of approximately $310$892 million. Also in 2010,

2012, we removed the reserves associated with 61202 gross (23.9(90.0 net) PUD locations, because, in the opinion of management, such locations were no longer expected to be developed within the 5 year timeline required by SEC rules. Thiswhich resulted in the removal of 40.13.5 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 (6.7 MMBoe) in 2010.accordingly. Estimated future development costs relating to the development of proved undeveloped reserves are projected to be approximately $865 million$1.8 billion in 2011, $1,055 million2013, $2.2 billion in 2012,2014, $2.0 billion in 2015, $1.4 billion in 2016, and $811 million$0.9 billion in 2013.2017.

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.(i.e., categorized as held by production (HBP)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 simultaneouslyexpect to increase our focus on drilling programs over the next 5 years which harvestdeveloping our PUD locations. Our current 5 year plan anticipates thatWhile full development of our current PUD inventory will comprise over one-third of our projected level of drilling activity and generateis expected to occur within five years, we believe additional PUD locations as our current inventory is harvested.will be generated through drilling activities.

Developed and Undeveloped Acreage

The following table presents our total gross and net developed and undeveloped acreageacres by region as of December 31, 2010:2012:

The following table sets forth the number of gross and net undeveloped acres as of December 31, 20102012 that willare 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, 2010,2012, we drilled exploratory and development wells as set forth in the table below:

As of December 31, 2010,2012, there were 151323 gross (47.9(122.4 net) wells in the process of drilling, completing or waiting on completion.

As of February 18, 2011,15, 2013, we operated 3828 rigs on our properties. Our rig activity during 20112013 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. SeePart 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 2011. We2013. Although we cannot provide any assurance, we believe our cash flows from operations, remaining cash balance, and borrowing availability under our revolving credit facility, including our ability to increase our borrowing capacity thereunder, will be sufficient to satisfy our 20112013 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 crude oil and natural gascommodity prices could cause us to curtail our actual capital expenditures. Conversely, an increase in commodity prices could result in increased capital expenditures.

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

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

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

North Region

Our properties in the North region represented 85%90% of our PV-10 as of December 31, 2010. During2012 and 78% of our average daily Boe production for the three months ended December 31, 2010,2012. For the three months ended December 31, 2012, our average daily production from such properties was 33,214 net Bbls83,205 Boe per day, an increase of crude oil and 26,456 net Mcf of natural gas.45% over our average daily production for the three months ended December 31, 2011. Our principal producing properties in thisthe North region are in the Bakken field and the Red River units.

Bakken Field

The Bakken field of North Dakota and Montana has becomeis 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 inIn October 2011, the USGS began a study to update their 2008 assessment of recoverable reserves is a result of improved drilling and completion technologies andfor the additionalBakken field to include reserves found infrom the Three Forks formation which is now recognized as partand 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.

Industry-wide production from the Bakken petroleum system. Drillingfield 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 and production rates in the Bakken field continued to increase in 2010, reachingalso reached record levels at 229 rigs in June 2012. North Dakota accordingnow ranks as the second largest crude oil producing state in the U.S. due to a report issued by the NDIC in January 2011. As of February 18, 2011, there were 174 rigs drillingproduction growth in the Bakken field, up 96% from the 89 rigs that were drilling as of January 25, 2010.field. We continue to be a leader in the development and expansion of the Bakken field. Wefield and control one of the largest leasehold positionsposition with approximately 1,597,1771,725,089 gross (855,936(1,139,803 net) acres as of December 31, 2010.2012. We are also the most active driller in the Bakken field, with 2321 operated rigs drilling as of February 18, 2011.15, 2013. During 20102012, we completed 233573 gross (76.5(204.1 net) wells in the Bakken field. Our properties within the Bakken field represented 56%74% of our PV-10 as of December 31, 20102012 and 47%63% of our average daily Boe production for the three months ended December 31, 2010.2012. As of December 31, 20102012 we had completed 6481,887 gross (260.5(757.7 net) wells in the Bakken field. Our inventory of provenproved undeveloped drilling locations in the Bakken field as of December 31, 20102012 totaled 8421,501 gross (393.7(847.3 net) wells.

2010 proved to be an exceptional year for us in the Bakken field asDuring 2012, we saw our production, reserves and acreage position in the Bakken field grow to record levels while substantial portions of our undeveloped acreage werecontinued to be de-risked due to the record breakinglevels of drilling activity in North Dakota. Our Bakken field production averaged 25,589 net67,522 Boe per day during the month ofthree months ended December 2010,31, 2012, up 78%64% from our average daily Bakken field production infor the three months ended December 2009. Total31, 2011. Our total proved Bakken field reserves at December 31, 20102012 were 198564 MMBoe, up 47%92% over our proved Bakken field reserves as of December 31, 2009. 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 increased 33%by 24% during 2010,2012, from 645,347915,863 net acres as of December 31, 20092011 to 855,9361,139,803 net acres as of December 31, 2010.2012. Approximately 22%51% of our net acreage in the Bakken field is developed and 78%the remaining 49% of our net acreage is undeveloped as of December 31, 2010.2012.

We plan to invest approximately $845 million$2.4 billion drilling 530558 gross (131.7(226.2 net) wells in the Bakken field during 2011. Approximately 91%2013, of which approximately 83% will be invested in North Dakota and the remaining 9%17% will be invested in Montana. We plan to keep 23average 22 rigs drilling in the Bakken field throughout the year, with 2117 rigs located in North Dakota and 25 rigs in Montana.

North Dakota Bakken.Our production and reserve growth in the Bakken field during 20102012 came primarily from our activities in North Dakota. Production increased to an average rate of 20,860 net59,019 Boe per day during the month ofthree months ended December 2010,31, 2012, up 129%66% from the average daily rate infor the three months ended December 2009.31, 2011. Proved reserves grew 50% year over year102% year-over-year to 158518 MMBoe as of December 31, 2010. Our estimated ultimate recoverable reserves per well (1,280-acre spacing) also increased during the year from 430 MBoe gross to 518 MBoe gross based on historical well performance.2012. As of December 31, 2010,2012, our North Dakota Bakken properties represented 43%67% of our PV-10 and 37%55% of our average daily Boe production for the three months ended December 31, 2010.2012. We completed 222526 gross (71(173.0 net) wells during 2010,2012, bringing our total number of wells

drilled in the North Dakota Bakken to 4751,589 gross (150.2(576.5 net) as of December 31, 2010.2012. As of December 31, 2010,2012, we had 1,285,6651,378,784 gross (623,649(866,967 net) acres in the North Dakota Bakken field, of which 19%55% of the net acreage is developed and 81%45% of the net acreage is undeveloped. Our inventory of proven netproved undeveloped locations stood at 7471,421 gross (329.5(791.3 net) wells as of December 31, 2010.2012.

One of the more significant outcomes of the 2010

Our drilling activity in the North Dakota Bakken field during 2012 was diversified, reflecting the expansionextensive nature of the play west of the Nesson Anticline. Technological breakthroughs demonstrated that widespread commercial production can be achieved in this area by increasing fracture stimulation treatments where necessary. Based on this information, we expanded our leasing effort and acquired an additional 141,800acreage position. With 866,967 net acres in the North Dakota Bakken during 2010, increasing our net acreage position by 29% overas 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 net acreage position as of December 31, 2009.assets through strategic exploration, planning and technology.

Another significant achievement during 2010 wasDuring 2012, we expanded the successful implementation of our ECO-Pad^TM technology. ECO-Pad technology allows 4 wells (2 Bakken and 2 Three Forks) to be drilled from a single drilling pad, which reduces drilling costs, completion costs and environmental impact by centralizing operations on a single pad. Drilling costs are saved by utilizing a walking rig, which moves between wells on hydraulic feet that eliminate the need to breakdown the rig each time it moves from one well to another well. Completion costs are saved by conducting fracture stimulation treatments on multiple wells in one continuous operation. Centralizing operations and production facilities reduces the size of the pad needed by as much as 75%. Our first ECO-Pad operation, the Arthur-Hegler, was completed in August 2010, flowing at a combined maximum 24-hour rate of 4,350 Boe per day. As of December 31, 2010, we had completed 4 ECO-Pad locations and had 4 ECO-Pad rigs drilling. We believe our ECO-Pad technology is a key to maximizing the developmentknown 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 plandiscovered there were three additional layers or “benches” of crude oil bearing reservoir rock in the Lower Three Forks formation. We refer to increase the use of this technologythese 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 matures.in North Dakota.

During 2010 we increasedThe discovery of three additional benches indicates the numberLower Three Forks formation has the potential to add incremental reserves in the Bakken field. The existence of fracture stimulation stages per well from approximately 18 stages to as many as 30 stages. Although there are always overriding geologic factors that influence production, themore 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 announced in 2010 can be attributed primarilyhave begun drilling wells to test the increased number of fracture stimulation stages used per well. We are studying these results to optimize future fracture stimulationsTF2, TF3 and TF4 reservoirs. In October 2011, we successfully completed our first well in the field.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 2011,2013, we plan to invest approximately $771 million$2.0 billion drilling 514507 gross (120.6(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 will include development wells along our Nesson Anticline acreage and step-out wells west ofin the Nesson Anticline to continue expanding the proven extents of the Bakken and Three Forks reservoirs underlying our acreage. The majority of our drilling will be on 1,280-acre spacing but will include some 640-acre infield locations and dual zone development. In time, we expect that the North Dakota Bakken field will be developed on 320-acre spacing like the Elm Coulee field in Montana.field. As of February 18, 2011,15, 2013, we had 2116 operated rigs drilling in the North Dakota Bakken and plan to maintain 21 operatedoperate 17 rigs drilling in the play throughout 2011.through most of 2013.

Montana Bakken. Our Montana Bakken production isproperties are located primarily in the Elm Coulee field in Richland County, Montana. The Elm Coulee field iswas listed by the Energy Information Administration (“EIA”) in 2010 as the 17th17^th largest onshore field in the lower 48 states of the United States ranked by 2009 proved liquid reserves in 2009. Since drilling our first well in August 2003,reserves. During 2012, we have completed a total of 17147 gross (108.6(31.0 net) wells, bringing our total number of wells drilled in the fieldMontana Bakken to 298 gross (181.2 net) wells as of December 31, 2010. Year over year,2012. Our production in 2010 was down 18%, reflecting our limited drilling activity inincreased to an average rate of 8,503 Boe per day for the field during 2010. The majority of our drilling was conducted during the second half of 2010, and production during the month ofthree months ended December 2010 was down only 10%31, 2012, up 50% from the average daily production inrate for the three months ended December 2009.31, 2011. As of December 31, 20102012 our Montana Bakken properties represented 14%7% of our PV-10 and 10%8% of our average daily Boe production for the three months ended December 31, 2010. During the year we added 98,344 gross (68,788 net) acres in the Montana Bakken play.2012. As of December 31, 2010,2012, we owned 311,512346,305 gross (232,287(272,836 net) acres in Montana Bakken, of which 29%39% of the net acreage is developed and the remaining 71%61% of the net acreage is undeveloped.

During the year ended December 31, 2010, using the latest drilling and completion technologies,In 2012, we completed 11 gross (5.5 net) wells to further develop the field and test the potentialcontinued to expand the limits of the Elm Coulee field. The Rognas 2-22H well, which is strategically located along the northern edgeproven extents of the Elm Coulee field was completed flowing at a 24-hour maximum rateusing state of 1,014 Boe per day. The Rognas 2-22H was completed using currentthe art drilling and completion technology. Areas once considered non-commercial based on old open hole completion technology

have now proven to be commercial using cased hole, multi-stage fracture stimulation technologytechnology. During 2012, our well completions in the immediate Elm Coulee field area included in-field, step-out and has significantly outperformed offsettingstrategic exploratory wells that were completed using older open hole completion technology. These results are encouraging and indicate that we may be ableflowing at initial 24 hour rates of up to extend1,301 Boe per day. Based on our 2012 drilling program, the productive limits of the Elm Coulee field using these technologies. We will continue testing this concept in 2011.were expanded up to approximately 10 miles to the north onto portions of our undeveloped leasehold.

We plan to invest approximately $74$426 million drilling 1651 gross (11.1(41.0 net) wells in the Montana Bakken during 2011.2013. Our drilling will focus inon in-field development and continued expansion of the Elm Coulee field area but will also include some strategic step-out wells to further testonto our undeveloped acreage immediately north of the Elm Coulee field. As of February 18, 201115, 2013, we had 25 rigs drilling in the Montana Bakken and we plan to maintain 25 rigs in the play throughout 2011.through most of 2013. As of December 31, 2010,2012, we had 9580 gross (64.2(55.9 net) provenproved undeveloped locations identified in the Montana Bakken.

Red River Units

OurThe Red River units represent 28%are comprised of our PV-10 as of December 31, 2010 and 34% of our average daily North region Boe production for December 2010. The 8eight units comprising the Red River units are located along the Cedar Creek Anticline in North Dakota, South Dakota and Montana andthat 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 Energy Information AdministrationEIA in 20082010 as the 7th9th largest onshore field in the lower 48 states of the United States ranked by 2009 proved liquid proved reserves.

InAll 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 plan to complete pattern drilling on the waterflood projecthad 150,450 gross (135,483 net) acres in the Cedar HillsRed River units, and resume development activity in the Medicine Pole Hills and Buffalo units in 2011. all of which is developed acreage.

We have allocated $58$63 million of our 2013 capital expenditure budget to the Red River units, which will support 2 operated rigsone drilling rig and a significantcontinued investment in facilities and infrastructure.

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

Cedar Hills West unit (“CHWU”), in Fallon County, Montana, is contiguousCrude Oil.We are building upon a portfolio approach to the northern portion of CHNU. As of December 31, 2010, this 7,800-acre unit contained 11 horizontal producing wells and 5 horizontal injection wells. We own and operate a 100% working interest in the CHWU.

In January 2003, we commenced enhanced recovery in the two Cedar Hills units, with HPAI used throughout most of the area and water injected generally along the boundary of CHNU. Under HPAI, compressed air injected into a reservoir oxidizes residualmarketing our crude oil and produces flue gases (primarily carbon dioxide and nitrogen) that mobilize and sweep the crude oil into producing wellbores. During Februarybegan in 2008 the transition started to have full scale water injection and this transition was completed in June of 2010 when we stopped our air injection at Cedar Hills after injecting nearly 80 Bcf of air into the reservoir. We have seen continued success from our increased density drilling program which supported the idea that we could more economically inject water than air in these units. In response to our enhanced recovery and increased drilling efforts, our net daily production increased from 2,185 Boe per day in November 2003 to 10,789 Boe per day in December 2010. During 2011, we plan to drill 12 new horizontal wells in the Cedar Hills units continuing with our increased density for both the producing wells and injection wells, and improving and upgrading production and injection facilities. In 2011, we plan to invest approximately $35 million drilling and improving facilities in the Cedar Hills units.

Medicine Pole Hills Units. The Medicine Pole Hills units (“MPHU”) are approximately five miles east of the southern portion of the CHNU. We acquired the Medicine Pole Hills unit in 1995. At that time, the 9,600-acre unit consisted of 18 vertical producing wellbores and 4 injection wellbores under HPAI producing 525 net Bblsfirst shipments of crude oil per day. We have since drilled 51 horizontal wellbores extending productionby 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 west withunstable mid-continent market centers.