Edgar Filing: CONTINENTAL RESOURCES INC

Large accelerated filer

Accelerated filer

Non-accelerated filer

Smaller reporting company

Form 10-Q

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

(Mark One)

x	QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15 (d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the quarterly period ended March 31, 2009

¨	TRANSITION REPORT PURSUANT TO SECTION 13 OR 15 (d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the transition period from to

Commission File Number: 001-32886

CONTINENTAL RESOURCES, INC.

(Exact name of registrant as specified in its charter)


Oklahoma		73-0767549
(State or other jurisdiction of incorporation or organization)		(I.R.S. Employer Identification No.)

302 N. Independence, Suite 1500, Enid, Oklahoma		73701
(Address of principal executive offices)		(Zip Code)

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

169,604,384 shares of our $0.01 par value common stock were outstanding on April 30, 2009.

Table of Contents


PART I. Financial Information
Item 1.	Financial Statements	4
	Condensed Consolidated Balance Sheets	4
	Unaudited Condensed Consolidated Statements of Operations	5
	Condensed Consolidated Statements of Shareholders’ Equity	6
	Unaudited Condensed Consolidated Statements of Cash Flows	7
	Notes to Unaudited Condensed Consolidated Financial Statements	8
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	15
Item 3.	Quantitative and Qualitative Disclosures About Market Risk	23
Item 4.	Controls and Procedures	24
Item 4T.	Controls and Procedures	24

PART II. Other Information
Item 1.	Legal Proceedings	25
Item 1A.	Risk Factors	25
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	25
Item 3.	Defaults Upon Senior Securities	26
Item 4.	Submission of Matters to a Vote of Security Holders	26
Item 5.	Other Information	26
Item 6.	Exhibits	26

	Signature

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

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 (“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.

“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.

PART I. Financial Information

ITEM 1.

Financial Statements

Continental Resources, Inc. and Subsidiary

Condensed Consolidated Balance Sheets


	March 31,		December 31,
	2009		2008
	(Unaudited)
	(In thousands, except par values and share data)
Assets
Current assets:
Cash and cash equivalents	$	5,315	$	5,229
Receivables:
Oil and natural gas sales		73,506		63,659
Affiliated parties		8,093		14,914
Joint interest and other, net		93,340		150,506
Inventories		38,668		22,210
Deferred and prepaid taxes		16,958		18,810
Prepaid expenses and other		2,521		2,367

Total current assets		238,401		277,695
Net property and equipment, based on successful efforts method of accounting		1,993,291		1,935,143
Debt issuance costs, net		3,635		3,041

Total assets	$	2,235,327	$	2,215,879


Liabilities and shareholders’ equity
Current liabilities:
Accounts payable trade	$	188,400	$	260,188
Accounts payable trade to affiliated parties		23,199		25,730
Accrued liabilities and other		24,677		34,769
Revenues and royalties payable		52,375		78,160
Current portion of asset retirement obligation		2,585		4,747

Total current liabilities		291,236		403,594
Long-term debt		544,000		376,400
Other noncurrent liabilities:
Deferred tax liability		429,493		445,752
Asset retirement obligation, net of current portion		42,915		39,883
Other noncurrent liabilities		2,931		1,542

Total other noncurrent liabilities		475,339		487,177
Commitments and contingencies (Note 7)
Shareholders’ equity:
Preferred stock, $0.01 par value: 25,000,000 shares authorized; no shares issued and outstanding		—		—
Common stock, $0.01 par value; 500,000,000 shares authorized,
169,599,222 shares issued and outstanding at March 31, 2009;
169,558,129 shares issued and outstanding at December 31, 2008		1,696		1,696
Additional paid-in-capital		422,711		420,054
Retained earnings		500,345		526,958

Total shareholders’ equity		924,752		948,708

Total liabilities and shareholders’ equity	$	2,235,327	$	2,215,879

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

Continental Resources, Inc. and Subsidiary

Unaudited Condensed Consolidated Statements of Operations


	Three Months Ended March 31,
	2009			2008
	(In thousands, except per share data)
Revenues:
Oil and natural gas sales	$	85,817		$	208,699
Oil and natural gas sales to affiliates		6,751			16,726
Loss on mark-to-market derivative instruments		—			(4,608	)
Oil and natural gas service operations		4,040			6,834

Total revenues		96,608			227,651

Operating costs and expenses:
Production expenses		17,274			18,950
Production expense to affiliates		5,152			4,123
Production tax and other		6,822			12,775
Exploration expense		7,119			5,262
Oil and natural gas service operations		2,403			4,230
Depreciation, depletion, amortization and accretion		50,697			28,646
Property impairments		35,425			4,520
General and administrative		10,284			7,531
Gain on sale of assets		(136	)		(79	)

Total operating costs and expenses		135,040			85,958

Income (loss) from operations		(38,432	)		141,693
Other income (expense):
Interest expense		(4,587	)		(3,411	)
Other		147			299

		(4,440	)		(3,112	)

Income (loss) before income taxes		(42,872	)		138,581
Provision (benefit) for income taxes		(16,259	)		50,610

Net income (loss)	$	(26,613	)	$	87,971

Basic net income (loss) per share	$	(0.16	)	$	0.52
Diluted net income (loss) per share	$	(0.16	)	$	0.52

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

Continental Resources, Inc. and Subsidiary

Condensed Consolidated Statements of Shareholders’ Equity


						Additional						Total
	Shares		Common			paid-in			Retained			shareholders’
	outstanding		stock			capital			earnings			equity
	(in thousands, except share data)
Balance, January 1, 2008	168,864,015		$	1,689		$	415,435		$	206,008		$	623,132
Net income	—			—			—			320,950			320,950
Stock-based compensation	—			—			9,927			—			9,927
Stock options:
Exercised	436,327			4			1,438			—			1,442
Repurchased and canceled	(82,922	)		(1	)		(4,017	)		—			(4,018	)
Restricted stock:
Issued	461,120			5			—			—			5
Repurchased and canceled	(91,568	)		(1	)		(2,729	)		—			(2,730	)
Forfeited	(28,843	)		—			—			—			—

Balance, December 31, 2008	169,558,129		$	1,696		$	420,054		$	526,958		$	948,708
Net loss (unaudited)	—			—			—			(26,613	)		(26,613	)
Stock-based compensation (unaudited)	—			—			2,717			—			2,717
Stock options:
Exercised (unaudited)	7,000			—			5			—			5
Restricted stock:
Issued (unaudited)	47,028			—			—			—			—
Repurchased and canceled (unaudited)	(2,935	)		—			(65	)		—			(65	)
Forfeited (unaudited)	(10,000	)		—			—			—			—

Balance, March 31, 2009 (unaudited)	169,599,222		$	1,696		$	422,711		$	500,345		$	924,752

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

Continental Resources, Inc. and Subsidiary

Unaudited Consolidated Statements of Cash Flows


	Three months ended March 31,
	2009			2008
	(In thousands)
Cash flows from operating activities:
Net income (loss)	$	(26,613	)	$	87,971
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation, depletion, amortization and accretion		54,257			28,568
Property impairments		35,425			4,520
Change in derivative fair value		—			(18,192	)
Equity compensation		2,717			1,368
Provision (benefit) for deferred income taxes		(16,259	)		40,453
Dry hole costs		4,763			327
Others, net		344			(95	)
Changes in assets and liabilities:
Accounts receivable		54,140			(32,337	)
Inventories		(16,458	)		(936	)
Prepaid expenses and other		1,884			(486	)
Accounts payable		(19,518	)		4,867
Revenues and royalties payable		(25,785	)		(2,360	)
Accrued liabilities and other		(10,182	)		11,193
Other noncurrent liabilities		1,388			(55	)

Net cash provided by operating activities		40,103			124,806
Cash flows from investing activities:
Exploration and development		(206,308	)		(121,234	)
Purchase of oil and gas properties		(350	)		(55,113	)
Purchase of other property and equipment		(440	)		(1,201	)
Proceeds from sale of assets		765			822

Net cash used in investing activities		(206,333	)		(176,726	)
Cash flows from financing activities:
Revolving credit facility		191,600			89,000
Repayment of revolving credit facility		(24,000	)		(42,500	)
Debt issuance costs		(1,220	)		—
Repurchase of equity grants		(67	)		(324	)
Dividends to shareholders		(2	)		(1	)
Exercise of options		5			439
Tax benefit of excess non qualified stock option deduction		—			208

Net cash provided by financing activities		166,316			46,822

Net change in cash and cash equivalents		86			(5,098	)
Cash and cash equivalents at beginning of period		5,229			8,761

Cash and cash equivalents at end of period	$	5,315		$	3,663

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

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, which includes a summary of the Company’s significant accounting policies and other disclosures.

The financial statements as of March 31, 2009 and for the three month periods ended March 31, 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 Company’s 2008 Form 10-K. In management’s opinion, all adjustments (consisting of only normal recurring adjustments) necessary for a fair presentation of the Company’s interim period results have been made. All significant intercompany accounts and transactions have been eliminated in the condensed consolidated 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 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 (in thousands):


	March 31, 2009		December 31, 2008
Tubular goods and equipment	$	19,389	$	14,884
Crude oil		19,279		7,326

	$	38,668	$	22,210

Crude oil represents 609,000 barrels of crude oil at March 31, 2009 and 275,000 barrels of crude oil at December 31, 2008. The Company has entered into a series of physical delivery forward sale contracts that provide for the sale of stored crude oil in future months. The Company is currently committed to sell 248,200 barrels of currently stored crude oil to be delivered in the third quarter of 2009 at an average price of $56.28 per barrel, before transportation costs.

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 (loss) per share computations for the three months ended March 31, 2009 and 2008:


	March 31,
	2009			2008
	(in thousands, except per share data)
Income (loss) (numerator):
Net income (loss)—basic and diluted	$	(26,613	)	$	87,971

Weighted average shares (denominator):
Weighted average shares—basic		168,467			167,890
Restricted shares		—			252
Employee stock options		—			996

Weighted average shares—diluted		168,467			169,138
Income (loss) per share:
Basic	$	(0.16	)	$	0.52
Diluted	$	(0.16	)	$	0.52

The potential dilutive effect of 316,000 weighted average restricted shares and 420,000 weighted average stock options were not considered in diluted income (loss) per share for the three months ended March 31, 2009, because to do so would have been anti-dilutive.

Recent accounting pronouncements

In December 2007, the FASB issued SFAS No. 141 (revised 2007), “Business Combinations” (SFAS 141(R)) and SFAS No. 160, “Noncontrolling Interests in Consolidated Financial Statements, an amendment of ARB No. 51” (SFAS 160). SFAS 141(R) changes how business acquisitions are accounted for and impacts financial statements both on the acquisition date and in subsequent periods. SFAS 160 changes the accounting and reporting for minority interests, which are re-characterized as noncontrolling interests and classified as a component of equity. SFAS 141(R) and SFAS 160 are effective for the Company for fiscal years beginning on or after December 15, 2008. SFAS 141(R) will be applied prospectively. SFAS 160 requires retroactive adoption of the presentation and disclosure requirements for existing minority interests. All other requirements of SFAS 160 will be applied prospectively. The adoption of SFAS 141(R) and SFAS 160 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 FASB Staff Position (“FSP”) FAS 157-2, Effective Date of FASB Statement No. 157, which provided a one year delay of the effective date of FAS 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 SFAS No. 157 to non-financial assets and liabilities. SFAS No. 157 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, SFAS No. 157 had no effect on these calculations. Both calculations are based primarily on level three inputs. The adoption of SFAS No. 157 did not have a material impact on the Company’s financial position or results of operations.

In March 2008, the FASB issued SFAS No. 161, Disclosures about Derivative Instruments and Hedging Activities an amendment of FASB Statement No. 133, which amends and expands the disclosure requirements of FAS 133 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 SFAS No. 161 beginning January 1, 2009. The adoption of this statement did not have an impact on the Company’s financial position or results of operations.

On December 29, 2008, the SEC announced final approval of new requirements, effective for annual reports on Form 10-K for fiscal years ending on or after December 31, 2009, to provide investors with a more meaningful and comprehensive understanding of oil and natural gas reserves. The new disclosure requirements include:

•

Consideration of new technologies in evaluating oil and natural gas reserves,

•

Disclosure of probable and possible oil and natural gas reserves,

•

Use of an average price based on the prior twelve month period rather than year-end prices, and

•

Revisions of the oil and natural gas disclosure requirements for operations.

The Company has not yet evaluated the effects of the above on its financial statements and disclosures.

In April 2009, the FASB issued FSP FAS 107-1 and APB 28-1, Interim Disclosures about Fair Value of Financial Instruments, which requires that disclosures concerning the fair value of financial instruments be presented in interim as well as annual financial statements. FSP FAS 107-1 and APB 28-1 is prospectively effective for interim reporting periods ending after June 15, 2009. The adoption of FSP FAS 107-1 and APB 28-1 will require additional disclosures regarding the Company’s financial instruments; however, it will not impact the Company’s results of operations or financial condition.

Note 3. Cash Flow Information

Net cash provided by operating activities reflects cash interest payments of $4.5 million for the three months ended March 31, 2009 and $2.6 million for the three months ended March 31, 2008. During the three months ended March 31, 2009, the Company received cash payments of $1.9 million for refunds of income taxes paid. Non-cash investing and financing activities include asset retirement obligations of $0.4 million and $1.0 million for the three months ended March 31, 2009 and 2008, respectively.

Note 4. Derivative Contracts

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. SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities” requires recognition of 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 under the provisions of SFAS No. 133. As a result, the Company marked its derivative instruments to fair value in accordance with the provisions of SFAS No. 133 and recognized the realized and unrealized change in fair value on derivative instruments in the statement of operations. For the three months ended March 31, 2008 the statement of operations contain realized losses of $2.4 million and unrealized losses of $2.2 million on derivatives. The Company did not have any derivative contracts at March 31, 2009 or for the three months ended March 31, 2009.

Note 5. Fair Value Measures

SFAS 157 establishes a fair value hierarchy which prioritizes the inputs 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. We use 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

Under SFAS 157, certain assets and liabilities are reported at fair value on a recurring basis. During the quarter ended March 31, 2008, the Company valued its derivative instruments according to SFAS No. 157 pricing levels. These contracts expired during the second quarter of 2008 and the Company currently does not have any financial assets or financial liabilities that are measured on a fair value basis.

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 our consolidated balance sheets. The following methods and assumptions were used to estimate the fair values:

Asset Impairments – In accordance with SFAS No. 144, “Accounting for the Impairment or Disposal of Long-Lived Assets,” 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 was used. The discounted cash flow method estimates future cash flows based on management’s expectations for the future and include 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 the forward futures price strip, developed oil and gas properties were reviewed for impairment at March 31, 2009. We determined that the carrying amount of certain fields were not recoverable from future cash flows and, therefore, were impaired at March 31, 2009. The affected fields had a fair value of $13.1 million at March 31, 2009. Total pre-tax (non-cash) impairments related to developed oil and gas properties for first quarter 2009 were $26.0 million.

Asset Retirement Obligations – The fair values 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 three months ended March 31, 2009 was $469,000. The fair value of ARO is calculated using significant unobservable inputs (Level 3).

Note 6. Long-term Debt

The Company had $544.0 million and $376.4 million in long-term debt outstanding at March 31, 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. The revolving credit facility has a maximum facility amount of $750.0 million, a borrowing base of $850.0 million, subject to semi-annual re-determination, and a commitment level of $672.5 million at March 31, 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 3.31% at March 31, 2009. Amounts outstanding under our revolving credit facility at March 31, 2009 are stated at cost, which approximates fair value.

The Company had $128.5 million of unused commitments under the revolving credit facility at March 31, 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 March 31, 2009.

Note 7. Commitments and Contingencies

Drilling Commitments. As of March 31, 2009, the Company had contracts with various drilling contractors to use four drilling rigs. Two of the drilling rig contracts expired in April 2009, one expires in August 2009 and one expires in August 2011. These commitments are not recorded in the accompanying consolidated balance sheets. Future commitments as of March 31, 2009 are $2.7 million for contracts that expire in 2009 and $21.3 million for contracts that expire in 2011.

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 first quarter of 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 March 31, 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 March 31, 2009 and December 31, 2008, the Company has provided a reserve of $2.6 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 $2.7 million for the three months ended March 31, 2009 and $1.4 million for the three months ended March 31, 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 March 31, 2009, options covering 1,870,463 shares had been exercised.

The Company’s stock option activity under the 2000 Plan for the three months ended March 31, 2009 was as follows:


	Outstanding				Exercisable
			Weighted				Weighted
			average				average
	Number		exercise		Number		exercise
	of options		price		of options		price
Outstanding December 31, 2008	450,200		$	1.28	450,200		$	1.28
Exercised	(7,000	)		0.71	(7,000	)		0.71

Outstanding March 31, 2009	443,200			1.29	443,200			1.29

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 three months ended March 31, 2009 was approximately $97,000. At March 31, 2009, all options were exercisable and had a weighted average life of 2.1 years with an aggregate intrinsic value of $8.8 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 March 31, 2009, the Company had 3,559,349 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 restricted shares of restricted stock for the three months ended March 31, 2009, is presented below:


	Unvested restricted Shares		Weighted average grant-date fair value
Unvested restricted shares at December 31, 2008	1,110,892		$	24.05
Granted	47,028			18.22
Vested	(25,028	)		25.95
Forfeited	(10,000	)		24.59

Outstanding March 31, 2009	1,122,892			23.76

The fair value of the restricted shares that vested during the three months ended March 31, 2009 at their vesting date was $0.5 million. As of March 31, 2009, there was $15.0 million of unrecognized compensation expense related to non-vested restricted shares. The expense is expected to be recognized over a weighted average period of 1.46 years.

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. The words “believe,” “expect,” “anticipate,” “plan,” “intend,” “foresee,” “should,” “would,” “could” or other similar expressions are intended to identify forward-looking statements, which are generally not historical in nature. These forward-looking statements are based on our current expectations and beliefs concerning future developments and their potential effect on us. While management believes that these forward-looking statements are reasonable as and when made, there can be no assurance that future developments affecting us will be those that we currently anticipate. All comments concerning our expectations for future revenues and operating results are based on our forecasts for our existing operations and do not include the potential impact of any future acquisitions. Our forward-looking statements involve significant risks and uncertainties (some of which are beyond our control) and assumptions that could cause actual results to differ materially from our historical experience and our present expectations or projections. Important factors that could cause actual results to differ materially from those in the forward-looking statements include, but are not limited to, those summarized below:

•

business strategy;

•

reserves;

•

technology;

•

financial strategy;

•

oil and natural gas realized prices;

•

timing and amount of future production of oil and natural gas;

•

the amount, nature and timing of capital expenditures;

•

drilling of wells;

•

competition and government regulations;

•

marketing of oil and natural gas;

•

exploitation or property acquisitions;

•

costs of exploiting and developing our properties and conducting other operations;

•

general economic conditions;

•

credit markets;

•

liquidity and access to capital;

•

uncertainty regarding our future operating results; and

•

plans, objectives, expectations and intentions contained in this report that are not historical.

Other factors that could cause our actual results to differ from our projected results are described in (1) our Annual Report on Form 10-K for the fiscal year ended December 31, 2008, (2) our reports and registration statements filed from time to time with the SEC and (3) 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. We undertake no obligation to publicly update or revise any forward-looking statements after the date they are made, whether as a result of new information, future events or otherwise.

ITEM 2.

Management’s Discussion and Analysis of Financial Condition and Results of Operations

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 gas prices have declined dramatically over the past nine months and have materially impacted our operating results as we discuss in detail below.

For the first three months of 2009, our oil and gas production increased to 3,313 MBoe (36,808 Boe per day), up 20% from the first three 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 material increase in production, our oil and natural gas revenues for the first quarter of 2009 decreased by 59% to $92.6 million due to a greater than 60% decrease in commodity prices compared to the same period in 2008. Our realized price per Boe decreased $51.45 to $29.90 for the three months ended March 31, 2009 compared to the three months ended March 31, 2008. While we experienced decreases in production expense and production tax and other of a combined total of $6.6 million, or 18%, due to a decrease in workover expense and a decrease in commodity prices, respectively, our decrease in combined per unit cost was $3.49 per Boe, or 27%, as a result of increases in sales volumes. For the three months ended March 31, 2009, oil sales volumes were 216 MBbls less than oil production due to temporary storage of barrels in response to low prices and pipeline line fill. Oil sales volumes were 19 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 three months ended March 31, 2009, was $40.1 million, a decrease of $84.7 million from $124.8 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 three months ended March 31, 2009, we invested $153.1 million (excluding payments to reduce accruals of $54.8 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 a response to significantly lower oil and natural gas prices during the fourth quarter of 2008 and the first quarter of 2009 and the resulting decrease in cash flows, we have significantly reduced our capital expenditures budget for 2009. We have an approved capital expenditures budget for 2009 of $275 million. Even though capital expenditures for the three months ended March 31, 2009 exceeded cash flow from operations, we still expect to manage our capital expenditures for the year to be inline with our cash flows from operations. To the extent continued weakness in commodity prices causes us to generate insufficient cash flow to finance this budget, we may decrease our actual capital expenditures during 2009. Conversely, a significant improvement in product prices could result in an increase in our capital expenditures. See “—Liquidity and Capital Resources.”

How We Evaluate Our Operations

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

•

volumes of oil and natural gas produced,

•

oil and natural gas prices realized,

•

per unit operating and administrative costs, and

•

EBITDAX.

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


	Three Months ended March 31,
	2009			2008
Average daily production:
Oil (Bbl)		26,578			24,043
Natural gas (Mcf)		61,382			37,160
Oil equivalents (Boe)		36,808			30,237
Average prices: ⁽¹⁾
Oil ($/Bbl)	$	34.99		$	90.55
Natural gas ($/Mcf)		2.98			7.55
Oil equivalents ($/Boe)		29.90			81.35
Production expense ($/Boe) ⁽¹⁾		7.24			8.33
General and administrative expense ($/Boe) ⁽¹⁾		3.32			2.72
EBITDAX (in thousands) ⁽²⁾		57,673			183,968
Net income (loss) (in thousands)		(26,613	)		87,971
Diluted net income (loss) per share		(0.16	)		0.52

(1)

For the three months ended March 31, 2009, oil sales volumes were 216 MBbls less than oil production due to temporary storage of volumes in response to low prices and pipeline line fill. Oil sales volumes were 19 MBbls more than oil production for the three months ended March 31, 2008 due to the sale of temporarily stored barrels. Average prices and per unit expenses have been calculated using sales volumes and excluding any effect of derivative transactions.

(2)

EBITDAX represents earnings before interest expense, income taxes , depreciation, depletion, amortization and accretion, property impairments, exploration expense, unrealized derivative gains and losses and non-cash compensation expense. EBITDAX is not a measure of net income or cash flow as determined by U. S. GAAP. A reconciliation of net income to EBITDAX is provided below under the header “ – Non-GAAP Financial Measures.”

Results of Operations

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


	March 31,
(in thousands, except volume and price data)	2009			2008
Oil and natural gas sales	$	92,568		$	225,425
Derivatives		—			(4,608	)
Total revenues		96,608			227,651
Operating costs and expenses		135,040			85,958
Other expense		4,440			3,112

Net income (loss), before income taxes		(42,872	)		138,581
Provision (benefit) for income taxes		(16,259	)		50,610

Net (loss) income	$	(26,613	)	$	87,971
Production Volumes:
Oil (MBbl)		2,392			2,188
Natural gas (MMcf)		5,524			3,382
Oil equivalents (MBoe)		3,313			2,752
Sales Volumes:
Oil (MBbl)		2,176			2,207
Natural gas (MMcf)		5,524			3,382
Oil equivalents (MBoe)		3,096			2,771
Average Prices: ⁽¹⁾
Oil ($/Bbl)	$	34.99		$	90.55
Natural gas ($/Mcf)	$	2.98		$	7.55
Oil equivalents ($/Boe)	$	29.90		$	81.35

(1)

For the three months ended March 31, 2009, oil sales volumes were 216 MBbls less than oil production due to temporary storage of volumes in response to low prices and pipeline line fill. Oil sales volumes were 19 MBbls more than oil production for the three months ended March 31, 2008 due to the sale of crude oil inventory. Average prices and per unit expenses have been calculated using sales volumes and excluding any effect of derivative transactions.

Production

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


	1st Quarter
	2009			2008
	Volume	Percent		Volume	Percent		Volume Increase	Percent Increase
Oil (MBbl)	2,392	72	%	2,188	80	%	204	9	%
Natural Gas (MMcf)	5,524	28	%	3,382	20	%	2,142	63	%

Total (MBoe)	3,313	100	%	2,752	100	%	561	20	%


	1st Quarter
	2009			2008
	MBoe	Percent		MBoe	Percent		Volume Increase	Percent Increase
Rocky Mountain	2,441	74	%	2,174	79	%	267	12	%
Mid-Continent	815	24	%	522	19	%	293	56	%
Gulf Coast	57	2	%	56	2	%	1	2	%

Total (MBoe)	3,313	100	%	2,752	100	%	561	20	%

Oil production volumes increased 9% during the three months ended March 31, 2009 compared to the three months ended March 31, 2008. Production increases in the Bakken field area contributed incremental volumes in excess of production for the first quarter of 2008 of 233 MBbls. The Mid-Continent area contributed incremental volumes of 8 MBbls in excess of production for the first quarter of 2008 levels. Favorable results from drilling have been the primary contributors to production growth in these areas. These increases were partially offset by decreases in other areas, most notably a 22 MBbl decrease in the Red River units. Gas volumes increased 2,142 MMcf, or 63%, during the three months ended March 31, 2009 compared to the same period in 2008. The majority of the increase, 1.7 Bcf, was from the Mid-Continent region due to the results of our exploration efforts in the Arkoma Woodford. The Rocky Mountain region gas production was up 370 MMcf for the three months ended March 31, 2009 compared to the same period in 2008 due to additional gas being connected and sold through the Hiland Partners Badlands plant.

Revenues

Oil and Natural Gas Sales. Oil and natural gas sales for the three months ended March 31, 2009 were $92.6 million, a 59% decrease from sales of $225.4 million for the same period in 2008. Our sales volumes increased 325 MBoe or 12% over the same period in 2008 volumes due to the continuing success of our enhanced oil recovery and drilling programs. Our realized price per Boe decreased $51.45 to $29.90 for the three months ended March 31, 2009 from $81.35 for the three months ended March 31, 2008. The differential between NYMEX calendar month average crude oil prices and our realized crude oil per barrel for the three months ended March 31, 2009 was $8.32 compared to $7.41 for the three months ended March 31, 2008, $14.45 for the fourth quarter 2008, 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 reduced seasonal demand for gasoline.

Derivatives. In July 2007, we entered into fixed-price swap contracts covering 10,000 barrels of oil per day for the period from August 2007 through April 2008. During each month of the contract, we 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. SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities” requires recognition of 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 under the provisions of SFAS No. 133. As a result, we marked our derivative instruments to fair value in accordance with the provisions of SFAS No. 133 and recognized the realized and unrealized change in fair value as a gain (loss) on derivative instruments in the statements of operations. During the three months ended March 31, 2008 we had realized losses on derivatives of $2.4 million and unrealized losses on derivatives of $2.2 million. These contracts expired in April 2008 and during the three months ended March 31, 2009 we did not have any open derivative positions.

Oil and Natural Gas Service Operations. Our oil and natural gas service operations consist primarily of sales of high-pressure air and the treatment and sale of lower quality crude oil, or reclaimed oil. Prices for reclaimed oil sold from our central treating unit were lower for the three months ended March 31, 2009 than the comparable 2008 period. The price decreased $56.01 per barrel which decreased reclaimed oil income by $3.2 million contributing to an overall decrease in oil and gas service operations revenue of $2.8 million for the three months ended March 31, 2009. Associated oil and natural gas service operations expenses decreased $1.8 million to $2.4 million during the three months ended March 31, 2009 from $4.2 million during the three months ended March 31, 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 $0.7 million for the three months ended March 31, 2009 and 2008.

Operating Costs and Expenses

Production Expense and Production Tax and Other. Production expense decreased slightly by $0.7 million, or 3%, during the three months ended March 31, 2009 to $22.4 million from $23.1 million during the three months ended March 31, 2008. During the three months ended March 31, 2009, we participated in the completion of 78 gross (32.1 net) wells. Production expense per Boe decreased to $7.24 for the three months ended March 31, 2009 from $8.33 per Boe for the three months ended March 31, 2008 due to a decrease in workover expenses coupled with an increase in sales volumes.

Production tax and other decreased $6.0 million, or 47%, during the three months ended March 31, 2009 compared to the three months ended March 31, 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 on the unaudited condensed consolidated statement of operations includes other charges for marketing, gathering, dehydration and compression fees

primarily related to natural gas sales in the Arkoma area of $1.3 million and $0.5 million for the three months ended March 31, 2009 and 2008, respectively. Production tax, excluding other charges, as a percentage of oil and natural gas sales was 6.10% for the three months ended March 31, 2009 compared to 5.54% for the three months ended March 31, 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 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 were as follows:


	1st Quarter				Percent
($/Boe)	2009		2008		Decrease
Production expense	$	7.24	$	8.33	(13	)%
Production tax and other		2.20		4.61	(52	)%

Production expense and tax	$	9.44	$	12.94	(27	)%

Exploration Expense. Exploration expense consists primarily of dry hole costs and exploratory geological and geophysical costs that are expensed as incurred. Exploration expense increased $1.9 million in the three months ended March 31, 2009 to $7.1 million due primarily to an increase in dry hole expense of $4.4 million to $4.8 million partially offset by a decrease in seismic expense of $3.2 million to $0.9 million. The majority of the dry hole costs were in the Mid-Continent region for the three months ended March 31, 2009 and were attributable to three dry holes in Ohio ($3.6 million) and one non-operated North Dakota Bakken dry hole ($1.0 million).

Depreciation, Depletion, Amortization and Accretion (DD&A). Total DD&A increased $22.0 million in the first quarter of 2009 primarily due to an increase in oil and gas DD&A of $21.8 million as a result of increased production and additional properties being added through our drilling program. Additionally, DD&A increased as a result of the decrease in commodity prices used to calculate year end 2008 reserves volumes. Lower prices have the effect of decreasing the economic life of oil and gas properties, which lowers future reserve volumes and increases DD&A. The following table shows the components of our DD&A rate per Boe.


	Three Months Ended March 31,
($/Boe)	2009		2008
Oil and gas	$	15.95	$	9.97
Other equipment		0.25		0.19
Asset retirement obligation accretion		0.18		0.18

Depreciation, depletion, amortization and accretion	$	16.38	$	10.34

Property Impairments. Property impairments, non-producing and developed, increased in the three months ended March 31, 2009 by $30.9 million to $35.4 million compared to $4.5 million during the three months ended March 31, 2008. Impairment of non-producing properties increased $6.2 million during the three months ended March 31, 2009 to $9.4 million compared to $3.2 million for the three months ended March 31, 2008 reflecting higher amortization of lease costs in our existing fields resulting from further defining likely drilling locations, capital constraints, and amortization of new fields. Non-producing properties consist of undeveloped leasehold costs and costs associated with the purchase of certain proved undeveloped reserves. Non-producing properties are amortized on a composite method based on our estimated experience of successful drilling and the average holding period.

Impairment provisions for developed oil and gas properties were approximately $26.0 million for the three months ended March 31, 2009 compared to approximately $1.3 million for the three months ended March 31, 2008, an increase of $24.7 million. We evaluate our developed oil and gas properties for impairment by comparing their cost basis to the estimated future cash flows on a field basis. If the cost basis is in excess of estimated future cash flows, then we impair it based on an estimate of fair market value based on discounted cash flows. Impairments in 2009 reflect uneconomic drilling results in two single well fields completed in the first quarter of 2009 in our Mid-Continent region which resulted in impairments of $14.1 million for the three months ended March 31, 2009. The remaining impairments are the result of decreases in reserves and prices.

General and Administrative Expense. General and administrative expense increased $2.8 million to $10.3 million during the three months ended March 31, 2009 from $7.5 million during the comparable period of 2008. General and administrative expense includes non-cash charges for stock-based compensation of $2.7 million and $1.4 million for the three

months ended March 31, 2009 and 2008, respectively. General and administrative expense excluding equity compensation increased $1.4 million for the three months ended March 31, 2009 compared to the three months ended March 31, 2008. The increase was primarily related to an increase in litigation expense of $0.9 million and an increase in personnel costs. On a volumetric basis, general and administrative expense was $3.32 per Boe for the three months ended March 31, 2009 compared to $2.72 per Boe for the three months ended March 31, 2008.

Interest Expense. Interest expense increased 34%, or $1.2 million, for the three months ended March 31, 2009 compared to the three months ended March 31, 2008, due to higher debt balances. Our average debt balance increased to $473.5 million for the three months ended March 31, 2009 compared to $207.7 million for the three months ended March 31, 2008, but the weighted average interest rate on our revolving credit facility was 3.52% for the three months ended March 31, 2009 compared to 5.77% for the same period in 2008. As described in greater detail below, a significant portion of the increased borrowings were used to pay for capital expenditures incurred during the fourth quarter of 2008 and the first quarter of 2009 that could not be funded from cash flows from operations due to the significant decrease in commodity prices. At March 31, 2009 our outstanding debt balance was $544.0 million with a weighted average interest rate of 3.31%.

Income Taxes. We recorded an income tax benefit for the three months ended March 31, 2009 of $16.3 million compared to a $50.6 million expense for the three months ended March 31, 2008. We provide taxes at a combined federal and state tax rate of approximately 38% after taking into account permanent taxable differences.

Liquidity and Capital Resources

Our primary sources of liquidity have been cash flows generated from operating activities and financing provided by our revolving credit facility. As we exited the fourth quarter of 2008, oil and natural gas prices had declined significantly from their recent record levels which reduced our operational cash flows. In response, we began reducing capital expenditures during the last quarter of 2008 and have prepared our capital expenditure budget for 2009 assuming lower commodity prices. However, realigning capital expenditures to reflect lower cash flows is not an instantaneous process; accordingly our debt has increased and will continue to increase as operating activities and expenses are matched with the reduced level of cash flow. Additionally, as in the past, we will consider selling non-strategic assets in order for us to focus on our core projects if and when appropriate.

The recent problems in the credit markets, steep stock market declines, financial institution failures and government bail-outs are evidence of a weakening global economy. If the unsettled conditions, including sustained declines in commodity prices, continue long term it may impact our ability to develop all of our projects. Our current revolving credit facility is backed by a syndicate of 14 banks and we believe that all of the syndicate banks currently have the capability to fund up to our current commitment. If one or more banks should not be able to do so, we may not have the full availability of $672.5 million commitment.

We believe that funds from operating cash flows and the revolving credit facility should be sufficient to meet our cash requirements inclusive of, but not limited to, normal operating needs, debt service obligations, planned capital expenditures, and commitments and contingencies for the next 12 months.

We currently anticipate that we will be able to generate or obtain funds sufficient to meet our long-term cash requirements. We intend to finance our future capital expenditures primarily through cash flow from operations and through borrowings under our revolving credit facility; however, our financing needs may require us to alter or increase our capitalization substantially through the issuance of debt or equity securities or the sale of assets. Furthermore, the issuance of additional debt may require that a portion of our cash flow from operations be used for the payment of interest and principal on our debt, thereby reducing our ability to use cash flow to fund working capital, capital expenditures and acquisitions. The issuance of additional equity securities could have a dilutive effect on the value of our common stock.

In the future, we may not be able to access adequate funding under our bank credit facilities as a result of (i) a decrease in our borrowing base due to the outcome of a subsequent borrowing base redetermination, or (ii) an unwillingness or inability on the part of our lending counterparties to meet their funding obligations. The recent declines in commodity prices, or a continuing decline in those prices, could result in a determination to lower the borrowing base in the future and, in such case, we could be required to repay any indebtedness in excess of the borrowing base. The turmoil in the financial markets has adversely impacted the stability and solvency of a number of large global financial institutions.

The current credit crisis makes it difficult to obtain funding in the public and private capital markets. In particular, the cost of raising money in the debt and equity capital markets has increased substantially while the availability of funds from those markets generally has diminished significantly. Also, as a result of concerns about the general stability of financial

markets and the solvency of specific counterparties, the cost of obtaining money from the credit markets has increased as many lenders and institutional investors have increased interest rates, imposed tighter lending standards, refused to refinance existing debt at maturity or on terms similar to existing debt or at all, and reduced and, in some cases, ceased to provide any new funding.

The credit crisis also has impacted the level of activity in the oil and natural gas property sales market. The lack of available credit and access to capital has limited and will likely continue to limit the parties interested in any proposed asset transactions and will likely reduce the values we could realize in those transactions.

Due to these factors, we cannot be certain that funding, if needed, will be available to the extent required and on acceptable terms. If we are unable to access funding when needed on acceptable terms, we may not be able to fully implement our business plans, complete new property acquisitions to replace our reserves, take advantage of business opportunities, respond to competitive pressures, or refinance our debt obligations as they come due, any of which could have a material adverse effect on our operations and financial results.

Cash Flow from Operating Activities

Our net cash provided by operating activities was $40.1 million and $124.8 million for the three months ended March 31, 2009 and 2008, respectively. The decrease in operating cash flows was mainly due to decreases in revenue as a result of lower commodity prices as explained in greater detail above.

Cash Flow from Investing Activities

During the three months ended March 31, 2009 and 2008 we had cash flows used in investing activities (excluding asset sales) of $207.1 million and $177.5 million, respectively, related to our capital program, inclusive of dry hole costs. The increase in our cash flow used in investing activities in the first quarter of 2009 was primarily due to amounts paid related to expenditures that were incurred prior to year end.

Cash Flow from Financing Activities

Net cash provided by financing activities of $166.3 million for the three months ended March 31, 2009, primarily represents amounts borrowed under our revolving credit facility to fund capital expenditures, including the reduction in accounts payable. Net cash provided by financing activities of $46.8 million for the three months ended March 31, 2008 was mainly used for acquisitions.

Credit Facility

We had $544.0 million and $376.4 million outstanding under our revolving credit facility at March 31, 2009 and December 31, 2008, respectively. The increase was largely due to borrowings to cover capital expenditures incurred in the fourth quarter of 2008 that could not be funded from cash flow from operations due to the continued deterioration in oil and natural gas prices in early 2009. The revolving credit facility currently has a borrowing base of $850.0 million, subject to semi-annual redetermination. We expect the next redetermination to occur in the second quarter of 2009. The commitment level is $672.5 million and the note amount remains at $750.0 million. The terms of the revolving credit facility provide for the commitment level to be increased up to the lesser of the borrowing base or note amount subject to bank agreement.

Capital Expenditures and Commitments

We evaluate opportunities to purchase or sell oil and natural gas properties in the marketplace and could participate as a buyer or seller of properties at various times. We seek acquisitions that utilize our technical expertise or offer opportunities to expand our existing core areas. Acquisition expenditures are not budgeted.

During the first three months of 2009, we participated in the completion of 78 gross (32.7 net) wells and invested a total of $153.1 million (excluding payments to reduce accruals of $54.8 million) for capital and exploration expenditures in 2009 as follows (in millions):


	Amount
Exploration and development drilling	$	122.0
Acquisition of producing properties		0.4
Capital facilities, workovers and re-completions		8.5
Land costs		21.0
Seismic		0.8
Vehicles, computers and other equipment		0.4

Total	$	153.1

Expenditures for exploration and development of oil and natural gas properties are the primary use of our capital resources. In response to significantly lower oil and natural gas prices during the fourth quarter of 2008 and the first quarter of 2009 and the resulting decrease in expected cash flows, we have significantly reduced our capital expenditures budgeted for 2009 to $275.0 million. In addition, we have reduced our rig count from 32 operated rigs in October 2008 to 4 operated rigs on April 30, 2009. Contracts on two of these rigs expired in April 2009, one contract expires in August 2009 and one contract expires in August 2011. Even though capital expenditures for the three months ended March 31, 2009 exceeded cash flow from operations, we still expect to manage our capital expenditures for the year to be inline with our cash flows from operations. We currently have budgeted for significantly lower capital expenditures throughout the remainder of 2009. To the extent continued weakness in commodity prices causes us to generate insufficient cash flow to finance this budget, we may decrease our actual capital expenditures during 2009. Conversely, a significant improvement in commodity prices could result in an increase in our actual capital expenditures during 2009.

Although we cannot provide any assurance, assuming successful implementation of our strategy, including the future development of our proved reserves and realization of our cash flows as anticipated, we believe that our remaining cash balance, cash flows from operations and borrowings available under our revolving credit facility will be sufficient to satisfy our 2009 capital budget. The actual amount and timing of our capital expenditures may differ materially from our estimates as a result of, among other things, available cash flow, actual drilling results, the availability of drilling rigs and other services and equipment, and regulatory, technological and competitive developments.

Recent Accounting Pronouncements

•

Consideration of new technologies in evaluating oil and natural gas reserves,

•

Disclosure of probable and possible oil and natural gas reserves,

•

Use of an average price based on the prior twelve month period rather than year-end prices, and

•

Revisions of the oil and natural gas disclosure requirements for operations.

We have not yet evaluated the effects of the above on our financial statements and disclosures.

In April 2009, the FASB issued FSP FAS 107-1 and APB 28-1, Interim Disclosures about Fair Value of Financial Instruments, which requires that disclosures concerning the fair value of financial instruments be presented in interim as well as annual financial statements. FSP FAS 107-1 and APB 28-1 is prospectively effective for interim reporting periods ending after June 15, 2009. The adoption of FSP FAS 107-1 and APB 28-1 will require additional disclosures regarding our financial instruments; however, it will not impact our results of operations or financial condition.

Critical Accounting Policies

There has been no change in our critical accounting policies from those disclosed in our Form 10-K for the year ended December 31, 2008.

Non-GAAP Financial Measures

expense. EBITDAX is not a measure of net income or cash flow as determined by U. S. GAAP. Management believes EBITDAX is useful because it allows them to more effectively evaluate the Company’s operating performance and compare the results of its operations from period to period without regard to its financing methods or capital structure. The Company excludes the items listed above from net income in arriving at EBITDAX because these amounts can vary substantially from company to company within its industry depending upon accounting methods and book values of assets, capital structures and the method by which the assets were acquired. EBITDAX should not be considered as an alternative to, or more meaningful than, net income or cash flow as determined in accordance with GAAP or as an indicator of a company’s operating performance or liquidity. Certain items excluded from EBITDAX are significant components in understanding and assessing a company’s financial performance, such as a company’s cost of capital and tax structure, as well as the historic costs of depreciable assets, none of which are components of EBITDAX. Our computations of EBITDAX may not be comparable to other similarly titled measures of other companies. We believe that EBITDAX is a widely followed measure of operating performance and may also be used by investors to measure our ability to meet future debt service requirements, if any. Our credit facility requires that we maintain a total debt to EBITDAX ratio of no greater than 3.75 to 1 on a rolling four-quarter basis. The credit facility defines EBITDAX consistently with the definition of EBITDAX utilized and presented by us. The following table is a reconciliation of our net income to EBITDAX.


	Three months ended
	March 31,
	2009			2008
Net income (loss)	$	(26,613	)	$	87,971
Unrealized derivative loss		—			2,180
Interest expense		4,587			3,411
Provision (benefit) for income taxes		(16,259	)		50,610
Depreciation, depletion, amortization and accretion		50,697			28,646
Property impairments		35,425			4,520
Exploration expense		7,119			5,262
Equity compensation		2,717			1,368

	$	57,673		$	183,968

ITEM 3.

Quantitative and Qualitative Disclosures About Market Risk

General

We are exposed to a variety of market risks including credit risk, commodity price risk and interest rate risk. We address these risks through a program of risk management which may include the use of derivative instruments.

Commodity Price Risk. Our primary market risk exposure is in the pricing applicable to our oil and natural gas production. Realized pricing is primarily driven by the prevailing worldwide price for crude oil and spot market prices applicable to our U.S. natural gas production. Pricing for natural gas and oil production has been volatile and unpredictable for several years, and we expect this volatility to continue in the future. The prices we receive for production depend on many factors outside of our control including volatility in the differences between product prices at sales points and the applicable index price. Based on our average daily production for the three months ended March 31, 2009, our annual revenue would increase or decrease by approximately $9.7 million for each $1.00 per barrel change in crude oil prices and $2.2 million for each $0.10 per MMBtu change in natural gas prices.

We currently have no hedges in place. To partially reduce price risk caused by these market fluctuations, we have occasionally hedged crude oil and natural gas prices in the past, through the utilization of derivatives, including zero-cost collars and fixed price contracts. Most recently, in July 2007, we entered into fixed-price swap contracts covering 10,000 barrels of oil per day for the period from August 2007 through April 2008. As of March 31, 2008 we recorded a liability for unrealized losses on derivatives of $8.5 million. During the three months ended March 31, 2008 we had realized losses on derivatives of $2.4 million. These contracts expired in April 2008.

Credit Risk. We monitor our risk of loss due to non-performance by counterparties of their contractual obligations. Our principal exposure to credit risk is through joint interest receivables ($97.2 million at March 31, 2009) and the sale of our oil and gas production, which we market to energy marketing companies, refineries and affiliates ($77.7 million in receivables at March 31, 2009). Joint interest receivables arise from billing entities who own partial interest in the wells we operate. These entities participate in our wells primarily based on their ownership in leases on which we wish to drill. We can do very little

to choose who participates in our wells. In order to minimize our exposure to credit risk we request prepayment of drilling costs where it is allowed by contract or state law. For such prepayments, a liability is recorded and subsequently reduced as the associated work is performed. In this manner, we reduce credit risk. We also have the right to place a lien on our co-owners interest in the well to redirect production proceeds in order to secure payment or, if necessary, foreclose on the lien. Historically, our credit losses on joint interest receivables have been immaterial.

We monitor our exposure to counterparties on oil and natural gas sales primarily by reviewing credit ratings, financial statements and payment history. We extend credit terms based on our evaluation of each counterparty’s credit worthiness. We have not generally required our counterparties to provide collateral to support oil and natural gas sales receivables owed to us.

Interest Rate Risk. Our exposure to changes in interest rates relates primarily to long-term debt obligations. We manage our interest rate exposure by limiting our variable-rate debt to a certain percentage of total capitalization and by monitoring the effects of market changes in interest rates. We may utilize interest rate derivatives to alter interest rate exposure in an attempt to reduce interest rate expense related to existing debt issues. Interest rate derivatives are used solely to modify interest rate exposure and not to modify the overall leverage of the debt portfolio. We are exposed to changes in interest rates as a result of our credit facility. We had total indebtedness of $577.0 million outstanding under our credit facility at April 30, 2009. The impact of a 1% increase in interest rates on this amount of debt would result in increased interest expense of approximately $5.7 million per year. Our long-term debt matures in 2011 and the weighted-average interest rate at April 30, 2009 was 2.62%.

ITEM 4.

Controls and Procedures

Evaluation of Disclosure Controls and Procedures

Based on our management’s evaluation, under the supervision and with the participation of our principal executive officer and principal financial officer, as of the end of the period covered by this report, our principal executive officer and principal financial officer have concluded that our disclosure controls and procedures (which are defined in rules 13a-15(e) and 15d-15(e) of the Securities Exchange Act of 1934, as amended, (the “Exchange Act”) as controls and other procedures of a company that are designed to ensure that information required to be disclosed by a company in the reports that it files or submits under the Exchange Act is recorded, processed, summarized and reported within required time periods), were effective as of March 31, 2009. Disclosure controls and procedures include, without limitation, controls and procedures designed to ensure that information required to be disclosed by us in the reports we file or submit under the Exchange Act is accumulated and communicated to our management, including our Chief Executive Officer and our Chief Financial Officer, to allow timely decisions regarding required disclosures.

Changes in Internal Control over Financial Reporting

During the quarter ended March 31, 2009, there were no changes in our internal control over financial reporting (as such term is defined in Rules 13a-15(f) and 15d-15(f) under the Exchange Act) that had materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.

Inherent Limitations on Controls and Procedures

A control system, no matter how well conceived and operated, can provide only reasonable, not absolute, assurance that the objectives of the control system are met. Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risks that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate. Accordingly, even an effective system of internal control will provide only reasonable assurance that the objectives of the internal control system are met.

ITEM 4T.

Controls and Procedures

Not applicable.

PART II . Other Information

ITEM 1.

Legal Proceedings

From time to time, we are a party to litigation or other legal proceedings that we consider to be a part of the ordinary course of our business. We are not involved in any legal proceedings nor are we a party to any pending or threatened claims that could reasonably be expected to have a material adverse effect on our financial condition or results of operations.

ITEM 1A.

Risk Factors

There has been no change in our risk factors from those disclosed in our Annual Report on Form 10-K for the year ended December 31, 2008 other than the addition of the following risk factor.

Our operations may incur substantial liabilities in connection with climate change legislation and regulatory initiatives.

On April 17, 2009, the Environmental Protection Agency (“EPA”) issued a notice of its finding and determination that emissions of carbon dioxide, methane, and other “greenhouse gases” (“GHGs”) presented an endangerment to human health and the environment because emissions of such gases are, according to EPA, contributing to warming of the earth’s atmosphere. EPA’s finding and determination allows it to begin regulating emissions of GHGs under existing provisions of the federal Clean Air Act. Although it may take EPA several years to adopt and impose regulations limiting emissions of GHGs, any limitation on emissions of GHGs from our equipment and operations could require us to incur costs to reduce emissions of GHGs associated with our operations. In addition, the U.S. Congress is currently considering adopting, and the Obama Administration has expressed strong support for, legislation that would impose a national cap on emissions of GHGs and would require major sources of GHG emissions to purchase “allowances” that would permit such sources to continue to emit GHGs into the atmosphere. The legislation currently under consideration by Congress could require GHG emission reductions by as much as 20% from present levels by 2020 and by as much as 80% by 2050, which would likely result in significant escalations in allowance costs over time. Significant increases in allowance costs could ultimately reduce demand for carbon-based fuels such as oil, refined petroleum products, and natural gas. Even if such legislation is not adopted at the national level, more than one-third of the states have begun taking actions to control and/or reduce emissions of GHGs. Although most of the state-level initiatives have to date been focused on large sources of GHG emissions, such as coal-fired electric power plants, it is possible that smaller sources of emissions could become subject to GHG emission limitations or allowance purchase requirements in the future. In addition, California is currently considering adopting low-carbon fuel requirements for motor vehicles that could eventually reduce demand for traditional diesel and gasoline.

ITEM 2.

Unregistered Sales of Equity Securities and Use of Proceeds

(a) Not applicable.

(b) Not applicable.

The following table provides information about purchases of equity securities that are registered by us pursuant to Section 12 of the Exchange Act during the quarter ended March 31, 2009:


Period	(a) Total number of shares purchased	(b) Average price paid per share		(c) Total number of shares purchased as part of publicly announced plans or programs	(d) Maximum number of shares that may yet be purchased under the plans or program
January 1, 2009 to January 31, 2009	1,296	$	24.57	—	—
February 1, 2009 to February 28, 2009	0	$	—	—	—
March 1, 2009 to March 31, 2009	1,639	$	20.26	—	—

Total	2,935	$	22.16	—	—

In connection with stock option exercises or restricted stock grants under our 2000 Plan and our 2005 Plan, we adopted a policy that enables employees to surrender shares to cover their tax liability. See Note 8. Stock Compensation in Notes to Unaudited Condensed Consolidated Financial Statements. All shares purchased above represent shares surrendered to cover tax liabilities. The Company paid the associated taxes to the Internal Revenue Service.

ITEM 3.

Defaults Upon Senior Securities

Not applicable.

ITEM 4.

Submission of Matters to a Vote of Security Holders

Not applicable.

ITEM 5.

Other Information

Not applicable.

ITEM 6.

Exhibits

See the Index to Exhibits accompanying this report.

SIGNATURE

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.


	Continental Resources, Inc.

Date: May 8, 2009	By:	/s/ John D. Hart
		John D. Hart
		Vice President, Chief Financial Officer and Treasurer (Duly Authorized Officer and Principal Financial Officer)

Index to Exhibits

The exhibits marked with the asterisk symbol (*) are filed or furnished (in the case of Exhibit 32) with this Form 10-Q. The exhibits marked with the cross symbol (†) are management contracts or compensatory plans or arrangements filed pursuant to Item 601(b)(10)(iii) of Regulation S-K.


3.1		Third Amended and Restated Certificate of Incorporation of Continental Resources, Inc. filed as Exhibit 3.1 to the Company’s Current Report on Form 8-K (Commission File No. 001-328861) filed May 22, 2007 and incorporated herein by reference.

3.2		Second Amended and Restated Bylaws of Continental Resources, Inc. filed as Exhibit 3.2 to the Company’s Current Report on Form 8-K (Commission File No. 001-328861) filed May 22, 2007 and incorporated herein by reference.

4.1		Registration Rights Agreement filed as Exhibit 10.1 to the Company’s Current Report on Form 8-K (Commission File No. 001-328861) filed May 22, 2007 and incorporated herein by reference.

4.2		Specimen Common Stock Certificate filed as Exhibit 4.1 to the Company’s registration statement on Form S-1 (Commission File No. 333-132257) filed April 14, 2006 and incorporated herein by reference.

31.1*		Certification of the Company’s Chief Executive Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 (18 U.S.C. Section 7241).

31.2*		Certification of the Company’s Chief Financial Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 (18 U.S.C. Section 7241).

32*		Certification of the Company’s Chief Executive Officer and Chief Financial Officer Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 (18 U.S.C. Section 1350).