CONTINENTAL RESOURCES, INC - Quarter Report: 2009 September (Form 10-Q)

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UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

(Mark One)

For the quarterly period ended September 30, 2009

or

For the transition period from              to             

Commission File Number: 001-32886

CONTINENTAL RESOURCES, INC.

(Exact name of registrant as specified in its charter)

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

Former name, former address and former fiscal year, if changed since last report: Not applicable

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  ¨    No  ¨

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 Exchange Act).    Yes  ¨    No  x

169,855,461 shares of our $0.01 par value common stock were outstanding on October 31, 2009.

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

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Glossary of Oil and Natural Gas Terms

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

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

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

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

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

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

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

“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.

“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.

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

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

“MBoe.” One thousand Boe.

“MMBoe.” One million Boe.

“MMBtu.” One million British thermal units.

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

“NYMEX.” The New York Mercantile Exchange.

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

“Proved undeveloped reserves 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.

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

“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.

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PART I. Financial Information

Continental Resources, Inc. and Subsidiary

Condensed Consolidated Balance Sheets

The accompanying notes are an integral part of these condensed consolidated financial statements.

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Continental Resources, Inc. and Subsidiary

Unaudited Condensed Consolidated Statements of Income

The accompanying notes are an integral part of these condensed consolidated financial statements.

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Continental Resources, Inc. and Subsidiary

Condensed Consolidated Statements of Shareholders’ Equity

The accompanying notes are an integral part of these condensed consolidated financial statements.

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Continental Resources, Inc. and Subsidiary

Unaudited Consolidated Statements of Cash Flows

The accompanying notes are an integral part of these condensed consolidated financial statements.

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Continental Resources, Inc. and Subsidiary

Notes to Unaudited Condensed Consolidated Financial Statements

Note 1. Organization and Nature of Business

Description of Company

Continental Resources, Inc.’s principal business is oil and natural gas exploration, development and production. Continental’s operations are primarily in the Rocky Mountain, Mid-Continent and Gulf Coast regions of the United States.

Note 2. Basis of Presentation and Significant Accounting Policies

Basis of presentation

This report has been prepared pursuant to the rules and regulations of the Securities and Exchange Commission (“SEC”) applicable to interim financial information. Because this is an interim period filing presented using a condensed format, it does not include all of the disclosures required by accounting principles generally accepted in the United States (“U.S. GAAP”), although the Company believes that the disclosures are adequate to make the information not misleading. You should read this Form 10-Q along with the Company’s Annual Report on Form 10-K for the year ended December 31, 2008 (“2008 Form 10-K”), which includes a summary of the Company’s significant accounting policies and other disclosures.

The financial statements as of September 30, 2009 and for the three and nine month periods ended September 30, 2009 and 2008 are unaudited. The Condensed Consolidated Balance Sheet as of December 31, 2008 was derived from the audited balance sheet filed in the 2008 Form 10-K. The Company has evaluated events or transactions through the date this report on Form 10-Q was filed in conjunction with its preparation of these financial statements.

The preparation of financial statements in conformity with U. S. GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities, the disclosure of contingent assets and liabilities at the date of the financial statements, and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates. The most significant of the estimates and assumptions that affect reported results is the estimate of the Company’s oil and natural gas reserves, which is used to compute depreciation, depletion, amortization and impairment on producing oil and natural gas properties. In the opinion of management, all adjustments (consisting only of normal recurring adjustments) necessary for a fair presentation in accordance with accounting principles generally accepted in the United States of America have been included in these unaudited interim condensed consolidated financial statements. The results of operations for any interim period are not necessarily indicative of the results of operations that may be expected for any other interim period or for the entire year.

Inventory

Inventories are stated at the lower of cost or market. Inventory consists of the following:

Crude oil represents 581,000 barrels of crude oil at September 30, 2009 and 275,000 barrels of crude oil at December 31, 2008. The Company entered into a series of physical delivery forward sale contracts that provide for the sale of stored crude oil through October 2009. The Company sold 124,100 barrels of crude oil from inventory that was delivered in October. Included in the total crude oil inventory were minimum pipeline line fill requirements of 341,000 barrels and 230,000 barrels at September 30, 2009 and December 31, 2008, respectively, which were not currently available for sale. Inventory, including line fill, is valued at the lower of cost or market using the FIFO inventory method.

Earnings per common share

Basic earnings per common share is computed by dividing net income by the weighted-average number of shares outstanding for the period. Diluted earnings per share reflects the potential dilution of non-vested restricted stock awards and dilutive stock options, which are calculated using the treasury stock method as if these options were exercised. The following is the calculation of basic and diluted weighted average shares outstanding and income per share computations for the three and nine months ended September 30, 2009 and 2008:

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New accounting standards

In December 2007, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Codification (“ASC”) 805-10 (formerly SFAS No. 141 (R)), Business Combinations, and ASC 810-10 (formerly SFAS No. 160), Noncontrolling Interests in Consolidated Financial Statements, and amendment of ARB No. 51, which changes how business acquisitions are accounted for and impacts financial statements both on the acquisition date and in subsequent periods. There are also changes in the accounting and reporting for minority interests, which are re-characterized as noncontrolling interests and classified as a component of equity. Both of these standards are effective for the Company for fiscal years beginning on or after December 15, 2008. ASC 805-10 will be applied prospectively while ASC 810-10 requires retroactive adoption of the presentation and disclosure requirements for existing minority interests. All other requirements will be applied prospectively. The adoption of these standards on January 1, 2009 did not have any impact on the Company’s financial position or results of operations though it would impact financial reporting for any future acquisitions.

In February 2008, the FASB issued ASC 820-10 (formerly Financial Staff Position SFAS 157-2), Effective Date of FASB Statement No. 157, which provided a one year delay of the effective date of ASC 820-10 (formerly SFAS 157) to January 1, 2009 for the Company for non-financial assets and non-financial liabilities, except those that are recognized or disclosed at fair value in the financial statements on a recurring basis (at least annually). Beginning January 1, 2009, the Company applied the provisions of the standard to non-financial assets and liabilities. The standard applies to the Company’s non-financial assets and liabilities in calculating fair value related to impairments of long-lived assets and asset retirement obligations. In both cases, the standard had no effect on these calculations. Both calculations are based primarily on level three inputs. The adoption of the standard on January 1, 2009 did not have a material impact on the Company’s financial position or results of operations.

In March 2008, the FASB issued ASC 815-10 (formerly SFAS No. 161), Disclosures about Derivative Instruments and Hedging Activities, which amends and expands disclosure requirements to require qualitative disclosure about objectives and strategies for using derivatives, quantitative disclosures about fair value amounts of gains and losses on derivative instruments, and disclosures about credit-risk-related contingent features in derivative agreements. The Company adopted the disclosure requirements of the standard beginning January 1, 2009 and it did not have an impact on the Company’s financial position or results of operations.

In April 2009, the FASB issued additional application guidance and enhancements to disclosures regarding fair value measurements and impairments of securities.

In May 2009, the FASB issued ASC 855-10 (formerly SFAS No. 165), “Subsequent Events” which establishes general standards of accounting for and disclosure of events that occur after the balance sheet date but before financial statements are issued or are available to be issued. Although there is new terminology, the standard is based on the same principles as those that previously existed. This statement, which includes a new required disclosure of the date through which an entity has evaluated subsequent events, is effective for interim or annual periods ending after June 15, 2009. The Company adopted the standard for the period ending June 30, 2009 and the adoption did not have an impact on its financial position or results of operations.

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In June 2009, the FASB issued ASC 105-10 (formerly SFAS No. 168), Accounting Standards Codification ^TM and the Hierarchy of Generally Accepted Accounting Principles. The FASB Accounting Standards Codification ^TM (“Codification”) has become the source of authoritative U.S. GAAP recognized by the FASB to be applied by nongovernmental entities. Rules and interpretive releases of the SEC under authority of federal securities laws are also sources of authoritative GAAP for SEC registrants. All existing accounting standard documents are superseded by the Codification. All other non-grandfathered non-SEC accounting literature not included in the Codification will become non-authoritative. The Codification is effective for financial statements issued for interim and annual periods ending after September 15, 2009 and all references made to GAAP in the condensed consolidated financial statements include the new Codification numbering system along with the original references. The Codification does not change or alter existing GAAP and, therefore, did not have an impact on our financial position, results of operations or cash flows.

Note 3. Cash Flow Information

Net cash provided by operating activities reflects cash interest payments of $13.7 million for the nine months ended September 30, 2009 and $8.2 million for the nine months ended September 30, 2008. During the first nine months of 2009, the Company received cash payments of $22.0 million for refunds of income taxes paid. Non-cash investing and financing activities include asset retirement obligations of $0.6 million and $3.5 million for the nine months ended September 30, 2009 and 2008, respectively.

Note 4. Derivative Contracts

The Company is required to recognize all derivative instruments on the balance sheet as either assets or liabilities measured at fair value. The Company elected not to designate its derivatives as cash flow hedges. As a result, the Company marked its derivative instruments to fair value and recognized the realized and unrealized change in fair value on derivative instruments in the statements of income.

In July 2007, the Company entered into fixed-price swap contracts covering 10,000 barrels of oil per day for the period from August 2007 through April 2008 to partially reduce price risk. During each month of the contract, the Company received a fixed-price of $72.90 per barrel and paid to the counterparties the average of the prompt NYMEX crude oil futures contract settlement prices for such month. These contracts expired in April 2008 and currently the Company’s crude oil production remains unhedged.

In June 2009, the Company entered into natural gas fixed price swaps for 600,000 MMBtu per month at an average price of $5.80 per MMBtu for December 2009 and $6.30 per MMBtu for calendar year 2010. The Company also entered into basis swaps for the same volumes and periods to lock in the difference between NYMEX natural gas prices and Inside FERC Centerpoint Energy East Index at an average differential of ($0.53) per MMBtu for December 2009 and ($0.62) for calendar year 2010. These swaps were put in place to underpin the Company’s current and expected level of operations in the Arkoma Woodford play in southeastern Oklahoma by securing a predictable cash flow stream on about a third of the Company’s natural gas production for the periods covered.

Derivative Fair Value Income (Loss)

The following table presents information about the components of derivative fair value income (loss) for the following periods presented:

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The table below provides data about the carrying values of derivatives that do not qualify for hedge accounting.

Note 5. Fair Value Measures

The Company is required to calculate fair value based on a hierarchy which prioritizes the input to valuation techniques used to measure fair value into three levels. The fair value hierarchy gives the highest priority to quoted market prices (unadjusted) in active markets for identical assets or liabilities (Level 1) and the lowest priority to unobservable inputs (Level 3). Level 2 inputs are inputs, other than quoted prices included within Level 1, which are observable for the asset or liability, either directly or indirectly. The Company uses Level 1 inputs when available as Level 1 inputs generally provide the most reliable evidence of fair value.

Assets and Liabilities Measured at Fair Value on a Recurring Basis

Certain assets and liabilities are reported at fair value on a recurring basis. The Company’s assessment of the significance of a particular input to the fair value measurement requires judgment, and may affect the valuation of the fair value of assets and liabilities and their placement within the fair value hierarchy levels. In determining the fair value of our fixed price and basis swaps, due to the unavailability of relevant comparable market data for our exact contracts, a discounted cash flow method is used. The discounted cash flow method estimates future cash flows based on quoted market prices for future commodity prices, observable inputs relating to basis differentials and a risk-adjusted discount rate. The fair value of derivatives is calculated using mainly significant observable inputs (Level 2). The Company’s calculation is then compared to the counterparty valuation for reasonableness. The following table summarizes the valuation of investments and financial instruments by pricing levels that were accounted for at fair value on a recurring basis as of September 30, 2009:

The following table sets forth the fair value of financial instruments that are not recorded at fair value in our Unaudited Condensed Consolidated Financial Statements.

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Assets and Liabilities Measured at Fair Value on a Nonrecurring Basis

Certain assets and liabilities are reported at fair value on a nonrecurring basis in the consolidated balance sheets. The following methods and assumptions were used to estimate the fair values:

Asset Impairments – Proved oil and gas properties are reviewed for impairment when events and circumstances indicate a possible decline in the recoverability of the carrying value of such property. The estimated future cash flows expected in connection with the property are compared to the carrying amount of the property to determine if the carrying amount is recoverable. If the carrying amount of the property exceeds its estimated undiscounted future cash flows, the carrying amount of the property is reduced to its estimated fair value. Due to the unavailability of relevant comparable market data, a discounted cash flow method is used. The discounted cash flow method estimates future cash flows based on management’s expectations for the future and includes estimates of future oil and gas production, commodity prices based on commodity futures price strips, operating and development costs, and a risk-adjusted discount rate. The fair value of oil and gas properties is calculated using significant unobservable inputs (Level 3).

As a result of changes in reserves and the forward futures price strip, developed oil and natural gas properties were reviewed for impairment at September 30, 2009 and the Company determined that the carrying amount was recoverable from future cash flows and, therefore, had no impairment on developed oil and natural gas properties at September 30, 2009. A similar calculation at June 30, 2009, determined that the carrying amount of certain fields were not recoverable from future cash flows and, therefore, were impaired. The affected fields had a fair value of $1.8 million at June 30, 2009 resulting in $10.1 million of developed property impairments for the quarter ended June 30, 2009. A similar calculation at March 31, 2009 determined that the carrying amount of certain fields was not recoverable from future cash flows and, therefore, was impaired. The affected fields at March 31, 2009 had a fair value of $13.1 million resulting in $26.0 million of developed property impairments for first quarter of 2009. Total pre-tax (non-cash) impairments related to developed oil and gas properties were $36.1 million for the nine months ended September 30, 2009.

Asset Retirement Obligations – The fair value of asset retirement obligations (“AROs”) is estimated based on discounted cash flow projections using numerous estimates, assumptions and judgments regarding such factors as the existence of a legal obligation for an ARO; estimated probabilities, amounts and timing of settlements; the credit-adjusted risk-free rate to be used; and inflation rates. The fair value of ARO additions for the nine months ended September 30, 2009 was $976,000. The fair value of ARO is calculated using significant unobservable inputs (Level 3).

Note 6. Long-term Debt

Long-term debt consists of the following:

Revolving credit facility – The Company had $246.0 million and $376.4 million in long-term debt outstanding at September 30, 2009 and December 31, 2008, respectively, on its revolving credit facility due April 11, 2011. At the Company’s election, the maturity date can be extended for up to two one-year periods. Borrowings under the facility bear interest, payable quarterly, at a rate per annum equal to the London Interbank Offered Rate for one, two, three or six months, as elected by the Company, plus a margin ranging from 175 to 250 basis points, depending on the percentage of its borrowing base utilized, or the lead bank’s reference rate (prime). The revolving credit facility has a maximum facility amount of $750.0 million and a borrowing base of $850.0 million, subject to semi-annual re-determination. The commitment level was increased from $672.5 million to $750.0 million in June 2009. Under the terms of the revolving credit facility, the commitment level can be increased up to the lesser of the borrowing base or the note amount subject to bank agreement. The Company’s weighted average interest rate was 2.84% at September 30, 2009. Amounts outstanding under the revolving credit facility at September 30, 2009 are stated at cost, which approximates fair value.

The Company had $504.0 million of unused commitments under the revolving credit facility at September 30, 2009 and incurs commitment fees of 0.25% to 0.375% of the daily average excess of the commitment amount over the outstanding credit balance. The revolving credit facility contains certain covenants including that the Company maintain a Current Ratio of not less than 1.0 to 1.0 (inclusive of availability under the revolving credit facility) and a Total Funded Debt to EBITDAX, as such terms are defined in the credit agreement, of no greater than 3.75 to 1.0. The Company was in compliance with these covenants at September 30, 2009.

8.25% Senior Notes due 2019 – On September 23, 2009, the Company issued $300 million of 8.25% Senior Notes due 2019 (“Notes”). The Notes, which carry a coupon rate of 8.25%, were sold at a discount (99.16% of par), which equates to an effective yield to maturity of approximately 8.375%. The Company received net proceeds of approximately $289.7 million, after deducting the underwriters’ discounts of approximately $6.8 million and offering expenses of approximately $1.0 million. The net proceeds were used to repay a portion of the borrowings outstanding under our revolving credit facility.

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The Notes will mature on October 1, 2019, and interest is payable on the Notes on each April 1 and October 1, commencing April 1, 2010. The Company has the option to redeem all or a portion of the Notes at any time on or after October 1, 2014 at the redemption price specified in the Indenture dated September 23, 2009 (the “Indenture”) plus accrued and unpaid interest. The Company may also redeem the Notes, in whole or in part, at a “make-whole” redemption price specified in the Indenture, plus accrued and unpaid interest, at any time prior to October 1, 2014. In addition, the Company may redeem up to 35% of the Notes prior to October 1, 2012 under certain circumstances with the net cash proceeds from certain equity offerings. The Indenture contains certain restrictions on our ability to incur additional debt, pay dividends on our common stock, make investments, create liens on our assets, engage in transactions with our affiliates, transfer or sell assets, consolidate or merge, or sell substantially all of our assets. These covenants are subject to a number of important exceptions and qualifications. The Company was in compliance with these covenants as of September 30, 2009. The Notes are not subject to any sinking fund requirements. Our sole subsidiary, which currently has no independent assets or operations, fully and unconditionally guarantees this debt.

Information Technology Financing Arrangement – On August 21, 2009, the Company entered into a Project Financing Agreement with IBM Credit LLC pursuant to which IBM Credit may advance up to $10.0 million for information technology services and software products to be provided to us by International IBM. The financing agreement matures on September 30, 2013, is unsecured and the interest rate under the agreement is 4.73%.

Note 7. Commitments and Contingencies

Drilling Commitments. As of September 30, 2009, the Company had one drilling contract that expires in August 2011. This commitment is not recorded in the accompanying consolidated balance sheets. Future commitments as of September 30, 2009 are $16.8 million.

Employee retirement plan. The Company maintains a defined contribution retirement plan for its employees and makes discretionary contributions to the plan based on a percentage of each eligible employee’s compensation. During the nine months ended September 30, 2009 and the year ended December 31, 2008, contributions to the plan were 5% of eligible employees’ compensation, excluding bonuses.

Employee health claims. The Company self insures employee health claims up to the first $125,000 per employee. The Company self insures employee workers’ compensation claims up to the first $250,000 per employee. Any amounts paid above these are reinsured through third-party providers. The Company accrues for claims that have been incurred but not yet reported based on a review of claims filed versus expected claims based on claims history. At September 30, 2009 and December 31, 2008, the accrued liability for health and worker’s compensation claims was $1.1 million and $0.9 million, respectively.

Litigation. The Company is involved in various legal proceedings in the normal course of business, none of which, in the opinion of management, will individually or collectively have a material adverse effect on the financial position or results of operations of the Company. As of September 30, 2009 and December 31, 2008, the Company has provided a reserve of $2.8 million and $1.2 million, respectively, for various matters none of which are believed to be individually significant.

Environmental Risk. Due to the nature of the oil and gas business, the Company is exposed to possible environmental risks. The Company is not aware of any material environmental issues or claims.

Note 8. Stock Compensation

The Company has granted stock options and restricted stock to employees and directors pursuant to the Continental Resources, Inc. 2000 Stock Option Plan (“2000 Plan”) and the Continental Resources, Inc. 2005 Long-Term Incentive Plan (“2005 Plan”) as discussed below. The Company’s associated compensation expense included in general and administrative expense was $8.6 million for the nine months ended September 30, 2009 and $6.5 million for the nine months ended September 30, 2008.

Stock Options

Effective October 1, 2000, the Company adopted the 2000 Plan and granted options to eligible employees. These grants consisted of either incentive stock options, nonqualified stock options or a combination of both. The granted stock options vest ratably over either a three or five-year period commencing on the first anniversary of the grant date and expire ten years from date of grant. On November 10, 2005, the 2000 Plan was terminated. As of September 30, 2009, options covering 1,916,973 shares had been exercised.

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The Company’s stock option activity under the 2000 Plan for the nine months ended September 30, 2009 was as follows:

The intrinsic value of a stock option is the amount by which the value of the underlying stock exceeds the exercise price of the option at its exercise date. The total intrinsic value of options exercised during the nine months ended September 30, 2009 was approximately $1.8 million. At September 30, 2009, all options were exercisable and had a weighted average remaining life of 1.5 years with an aggregate intrinsic value of $15.1 million.

Restricted Stock

On October 3, 2005, the Company adopted the 2005 Plan and reserved a maximum of 5,500,000 shares of common stock that may be issued pursuant to the 2005 Plan. As of September 30, 2009, the Company had 3,285,697 shares of restricted stock available to grant to directors, officers and key employees under the 2005 Plan. Restricted stock is awarded in the name of the recipient and except for the right of disposal, constitutes issued and outstanding shares of the Company’s common stock for all corporate purposes during the period of restriction including the right to receive dividends, subject to forfeiture. Restricted stock grants vest over periods ranging from one to three years.

The Company began issuing shares of restricted common stock to employees and non-employee directors in October 2005. A summary of changes in the non-vested shares of restricted stock for the nine months ended September 30, 2009, is presented below:

The fair value of the restricted shares that vested during the nine months ended September 30, 2009 at their vesting date was $1.7 million. As of September 30, 2009, there was $19.8 million of unrecognized compensation expense related to non-vested restricted shares. The expense is expected to be recognized over a weighted average period of 1.4 years.

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Cautionary Statement Regarding Forward-Looking Statements

Certain statements and information in this report may constitute “forward-looking statements” within the meaning of the Private Securities Litigation Act of 1995. All statements, other than statements of historical fact included in this report, regarding our strategy, future operations, financial position, estimated revenues and losses, projected costs, prospects, plans and objectives of management are forward-looking statements. When used in this report, the words “could,” “believe,” “anticipate,” “intend,” “estimate,” “expect,” “project” and similar expressions are intended to identify forward-looking statements, although not all forward-looking statements contain such identifying words. These forward-looking statements are based on our current expectations and assumptions about future events and are based on currently available information as to the outcome and timing of future events. When considering forward-looking statements, you should keep in mind the risk factors and other cautionary statements described under the heading “Risk Factors” included in our Annual Report on Form 10-K for the year ended December 31, 2008 and included in our Quarterly Reports on Form 10-Q for the periods ended March 31, 2009 and June 30, 2009.

These forward-looking statements are based on management’s current belief, based on currently available information, as to the outcome and timing of future events. Without limiting the generality of the foregoing, certain statements incorporated by reference or included in this report constitute forward-looking statements.

Forward-looking statements may include statements about our:

We caution you that these forward-looking statements are subject to all of the risks and uncertainties, most of which are difficult to predict and many of which are beyond our control, incident to the exploration for and development, production, and sale of oil and natural gas. These risks include, but are not limited to, commodity price volatility, inflation, lack of availability of drilling and production equipment and services, environmental risks, drilling and other operating risks, regulatory changes, the uncertainty inherent in estimating oil and natural gas reserves and in projecting future rates of production, cash flow and access to capital, the timing of development expenditures, and the other risks described under “Risk Factors” in this report, our Annual Report on Form 10-K for the year ended December 31, 2008, our Quarterly Reports on Form 10-Q for the periods ended March 31, 2009 and June 30, 2009, registrations statements filed from time to time with the SEC, and other announcements we make from time to time.

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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, all of which are expressly qualified by the statements in this section, to reflect events or circumstances after the date of this report.

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The following discussion and analysis should be read in conjunction with our historical consolidated financial statements and the notes included in our Annual Report on Form 10-K for the year ended December 31, 2008. Our operating results for the periods discussed may not be indicative of future performance. Statements concerning future results are forward-looking statements.

Overview

We are engaged in oil and natural gas exploration, exploitation and production activities in the Rocky Mountain, Mid-Continent and Gulf Coast regions of the United States. 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 target large repeatable resource plays where horizontal drilling, advanced fracture stimulation and enhanced recovery technologies provide the means to economically develop and produce oil and natural gas reserves from unconventional formations. We derive the majority of our operating income and cash flow from the sale of oil and natural gas. We expect that growth in our operating income and revenues will primarily depend on product prices and our ability to increase our oil and natural gas production. In recent months and years, there has been significant volatility in oil and natural gas prices due to a variety of factors we can not control or predict, including political and economic events, weather conditions, and competition from other energy sources. These factors impact supply and demand for oil and natural gas, which affects oil and natural gas prices. In addition, the prices we realize for our oil and natural gas production are affected by location differences in market prices. Oil and natural gas prices have declined dramatically over the past 15 months and have had a material impact on our operating results as we discuss in detail below.

For the first nine months of 2009, our oil and natural gas production increased to 10,151 MBoe (37,182 Boe per day), up 17% from the first nine months of 2008. The increase in 2009 production was primarily driven by an increase in production from our Arkoma Woodford and Bakken fields. Despite this substantial increase in production, our oil and natural gas revenues for the first nine months of 2009 decreased by 50% to $407.4 million due to a 56% decrease in commodity prices compared to the same period in 2008. Our realized price per Boe decreased $51.72 to $40.92 for the nine months ended September 30, 2009 compared to the nine months ended September 30, 2008. While we experienced decreases in production expense and production tax and other expenses of a combined total of $23.7 million, or 19%, due to a decrease in workover expense and a decrease in production taxes as a result of lower commodity prices, respectively, our decrease in combined per unit cost was $4.11 per Boe, or 29%, as a result of a 1,220 MBoe increase in sales volumes. For the nine months ended September 30, 2009, oil sales volumes were 196 MBbls less than oil production due to temporary storage of barrels in response to low prices and pipeline line fill requirements. Oil sales volumes were 42 MBbls more than production for the same period in 2008 due to the sale of crude oil inventory. Our cash flow from operating activities for the nine months ended September 30, 2009, was $216.0 million, a decrease of $373.9 million from $589.9 million provided by our operating activities during the comparable 2008 period. The decrease in operating cash flows was primarily due to decreases in commodity prices. During the nine months ended September 30, 2009, we invested $302.7 million (excluding payments to reduce accruals of $76.9 million and including seismic costs) in our capital program concentrating mainly in the Red River units, the Bakken field and the Arkoma Woodford play.

In response to significantly lower oil and natural gas prices during the fourth quarter of 2008 and the first three months of 2009 and the resulting decrease in cash flows, we significantly reduced our capital expenditures budget for 2009 to $275 million. Due to drilling rig commitments and in-progress drilling operations, we knew these expenditures would be heavily weighted toward the first quarter of 2009. Based on increased crude oil prices in the second quarter of 2009, in August 2009, we increased our 2009 capital expenditures budget by 42% from the previously announced budget to $390 million, with the majority of the additional spending directed at drilling operations in the North Dakota Bakken. In November 2009 we increased our 2009 capital expenditures budget to $415.0 million. Cash flow from operations as shown on our statements of cash flows was negatively impacted by payments made to reduce prior year accruals and was less than our capital expenditures for the nine months ended September 30, 2009 and will be less than our capital expenditures for 2009. However, we still expect to manage our capital expenditures for the year to be inline with cash generated from current year operating activities.

How We Evaluate Our Operations

We use a variety of financial and operational measures to assess our performance. Among these measures are:

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The following table contains financial and operational highlights for the periods presented.

Three months ended September 30, 2009 compared to the three months ended September 30, 2008

Results of Operations

The following table presents selected financial and operating information for each of the periods presented.

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Production

The following tables reflect our production by product and region for the periods presented.

Oil production volumes increased 10% during the three months ended September 30, 2009 compared to the three months ended September 30, 2008. Production increases in the Bakken field and the Red River units contributed incremental volumes in 2009 of 274 MBbls in excess of production for the third quarter of 2008. Favorable results from drilling have been the primary contributors to production growth in these areas. This increase was partially offset by decreases in other areas, most notably a 19 MBbl decrease in the Rockies Other area. Natural gas volumes increased 813 MMcf, or 18%, during the three months ended September 30, 2009 compared to the same period in 2008. The Mid-Continent region increased 676 MMcf due to the results of our exploration efforts in the Arkoma Woodford play. The Rocky Mountain region natural gas production was up 160 MMcf for the three months ended September 30, 2009 compared to the same period in 2008 due to additional natural gas being connected and sold in North Dakota.

Revenues

Oil and Natural Gas Sales. Oil and natural gas sales for the three months ended September 30, 2009 were $168.4 million, a 41% decrease from sales of $286.2 million for the same period in 2008. Our sales volumes increased 423 MBoe or 14% over the same period in 2008 due to the continuing success of our enhanced oil recovery and drilling programs. Our realized price per Boe decreased $45.01 to $48.19 for the three months ended September 30, 2009 from $93.21 for the three months ended September 30, 2008. The differential between NYMEX calendar month average crude oil prices and our realized crude oil price per barrel for the three months ended September 30, 2009 was $9.39 compared to $9.68 for the three months ended September 30, 2008, $6.02 for the second quarter 2009, and $9.50 for the year ended December 31, 2008. Factors contributing to the changing differentials included Canadian oil imports and increases in production in the Rocky Mountain region, coupled with downstream transportation capacity constraints, refinery downtime in the Rocky Mountain region, and seasonal demand fluctuations for gasoline.

Derivatives. The Company is required to recognize all derivative instruments on the balance sheet as either assets or liabilities measured at fair value. We elected not to designate our derivatives as cash flow hedges. As a result, we marked our derivative instruments to fair value and recognized the realized and unrealized change in fair value on derivative instruments in the statements of income under the caption “Loss on mark-to-market derivative instruments.”

In June 2009, we entered into natural gas fixed price swaps for 600,000 MMBtu per month at an average price of $5.80 per MMBtu for December 2009 and $6.30 per MMBtu for calendar year 2010. We also entered into basis swaps for the same volumes and periods to lock in the difference between NYMEX natural gas prices and Inside FERC Centerpoint Energy East Index at an average differential of ($0.53) per MMBtu for December 2009 and ($0.62) for calendar year 2010. These swaps were put in place to underpin our current and expected level of operations in the Arkoma Woodford play in southeastern Oklahoma by securing a predictable cash flow stream on a portion of our natural gas production. We reported non-cash unrealized mark-to-market losses from our gas derivatives of $2.1 million for the three months ended September 30, 2009. Currently our crude oil production remains unhedged.

Oil and Natural Gas Service Operations. Our oil and natural gas service operations consist primarily of the treatment and sale of lower quality crude oil, or reclaimed oil and sales of high-pressure air. Prices for reclaimed oil sold from our central treating units were lower for the three months ended September 30, 2009 than the comparable 2008 period. The price decreased $56.01 per barrel

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which decreased reclaimed oil income by $2.7 million contributing to an overall decrease in oil and gas service operations revenue of $3.5 million for the three months ended September 30, 2009. Associated oil and natural gas service operations expenses decreased $2.8 million to $2.3 million during the three months ended September 30, 2009 from $5.1 million during the three months ended September 30, 2008 due mainly to a decrease in the costs of purchasing and treating oil for resale compared to the same period in 2008. We sold high-pressure air from our Red River units to a third party and recorded revenues of $0.5 million for the three months ended September 30, 2009 compared to $0.8 million for the three months ended September 30, 2008.

Operating Costs and Expenses

Production Expense and Production Tax and Other Expenses. Production expense decreased $2.5 million, or 10%, during the three months ended September 30, 2009 to $22.7 million from $25.2 million during the three months ended September 30, 2008. Production expense per Boe decreased to $6.50 for the three months ended September 30, 2009 from $8.22 per Boe for the three months ended September 30, 2008 due to a decrease in workover expenses coupled with an increase in sales volumes.

Production tax and other expenses decreased $5.6 million, or 31%, during the three months ended September 30, 2009 compared to the three months ended September 30, 2008 as a result of lower revenues resulting from decreased sales prices partially offset by the expiration of various tax incentives and increases in other charges. Production tax and other expenses on the unaudited condensed consolidated statements of income includes other charges for marketing, gathering, dehydration and compression fees primarily related to natural gas sales in the Arkoma area of $1.5 million and $1.1 million for the three months ended September 30, 2009 and 2008, respectively. Production tax, excluding other charges, as a percentage of oil and natural gas sales was 6.7% for the three months ended September 30, 2009 compared to 5.6% for the three months ended September 30, 2008. Production taxes are based on the wellhead values of production and vary by state. Additionally, some states offer exemptions or reduced production tax rates for wells that produce less than a certain quantity of oil or natural gas and to encourage certain activities, such as horizontal drilling and enhanced recovery projects. In Montana, North Dakota and Oklahoma, new horizontal wells qualify for a tax incentive and are taxed at a lower rate during their initial months of production. After the incentive period expires, the tax rate increases to the statutory rates. Our overall production tax rate is expected to increase as incentives we currently receive for horizontal wells reach the end of their incentive period.

On a unit of sales basis, production expense and production tax and other expenses were as follows: