8-K

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, DC 20549

FORM 8-K

CURRENT REPORT

Pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934

Date of report (Date of earliest event reported): November 6, 2008 (November 6, 2008)

CONTINENTAL RESOURCES, INC.

(Exact name of registrant as specified in its charter)

Oklahoma

(State or other jurisdiction of incorporation)

1-32886	73-0767549
(Commission File Number)	(IRS Employer Identification No.)

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

(580) 233-8955

(Registrant’s telephone number, including area code)

(Former name or former address, if changed since last report)

Check the appropriate box below if the Form 8-K filing is intended to simultaneously satisfy the filing obligation of the registrant under any of the following provisions ( see General Instruction A.2. below):

¨ Written communications pursuant to Rule 425 under the Securities Act (17 CFR 230.425)

¨ Soliciting material pursuant to Rule 14a-12 under the Exchange Act (17 CFR 240.14a-12)

¨ Pre-commencement communications pursuant to Rule 14d-2(b) under the Exchange Act (17 CFR 240.14d-2(b))

¨ Pre-commencement communications pursuant to Rule 13e-4(c) under the Exchange Act (17 CFR 240.13e-4(c))

Item 2.02 Results of Operations and Financial Condition

On November 6, 2008, Continental Resources, Inc. issued a press release announcing its unaudited third quarter 2008 results, 2009 capital expenditures budget, and 2009 financial guidance. A copy of the press release is being furnished as an exhibit to this report on Form 8-K.

Item 7.01 Regulation FD Disclosure

In the November 6, 2008 press release, Continental Resources also announced its participation in the Bank of America Energy Conference in Key Biscayne, Florida on November 13, 2008; at the NYSE Euronext and WJB Capital Group Boston Growth Conference on December 4, 2008; and at the Raymond James Small and Mid-Cap Equity Conference in Boston on December 11, 2008. Presentations and audio links will be posted on the Company’s web site.

In accordance with General Instruction B.2 to Form 8-K, the information being filed under Items 2.02 and 7.01 shall not be deemed “filed” for purposes of Section 18 of the Securities Exchange Act of 1934 or otherwise subject to the liabilities of that section, nor shall it be deemed incorporated by reference in any filing.

Item 9.01 Financial Statements and Exhibits.

(d) Exhibit

Exhibit Number	Description
99.1	Press release dated November 6, 2008

SIGNATURES

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 hereunto duly authorized.

	CONTINENTAL RESOURCES, INC. (Registrant)
Dated: November 6, 2008
	By:	/s/ John D. Hart
		John D. Hart
		Vice President, Chief Financial Officer and Treasurer

Exhibit Index

Exhibit Number	Description
99.1	Press release dated November 6, 2008

EX-99.1

Exhibit 99.1

CONTINENTAL RESOURCES REPORTS 87 PERCENT INCREASE IN NET INCOME

FOR THIRD QUARTER OF 2008

2009 Outlook for Production Growth and Capital Expenditures

ENID, Okla., November 6, 2008 /PRNewswire-FirstCall/ — Continental Resources, Inc. (NYSE: CLR) reported strong growth in cash flow, net income and production for the quarter ended September 30, 2008, compared with the third quarter last year.

“For the third quarter of 2008, Continental Resources again delivered strong operating and financial results,” said Harold Hamm, Chairman and Chief Executive Officer. “We increased profits, with strong cash flow margins on total revenues. Initial production results again improved in the North Dakota Bakken and Arkoma Woodford plays, and we have now completed nine Three Forks/Sanish wells in North Dakota, with strong initial production results.

“Looking to the remainder of this year and into 2009, the Company is positioned to capitalize on its strategy of strong organic growth in production and reserves and delivering industry-leading operating margins. Our balance sheet is strong, with low debt compared to cash flows. Finally, we have a large drilling inventory, including the largest acreage position in the nation’s largest onshore oil play, the Bakken shale of Montana and North Dakota,” he said.

With the rapid decline in commodity prices, Continental has begun to decrease its operated drilling rig count. Continental plans to reduce capital expenditures in line with the level of expected cash flows to minimize the need for external financing. Continental has set its 2009 capital expenditure budget at $609 million, with $541 million allocated primarily for drilling and completion operations. This compares with a 2008 capex budget of $883 million, with $663 million allocated primarily for drilling and completion operations.

For the third quarter ended September 30, 2008, the Company reported net income of $105.3 million, or $0.62 per diluted share, an increase of 87 percent over net income of $56.4 million, or $0.33 per diluted share, for the third quarter of 2007.

Oil and natural gas sales were $286.2 million for the third quarter of 2008, an increase of 72 percent over oil and gas sales for the third quarter last year. The Company’s average sales price per barrel of crude oil equivalent was $93.21 for the most recent quarter, compared with $62.61 for the third quarter last year.

EBITDAX for the third quarter of 2008 was $238.3 million, an increase of 79 percent over EBITDAX of $132.8 million for the third quarter of 2007. For the Company’s definition and reconciliation of EBITDAX to Generally Accepted Accounting Principles, see “Non-GAAP Financial Measures” at the end of this press release.

At September 30, 2008, the Company’s long-term debt was $229.4 million.

Operations Update

The following table contains financial and operational highlights for the three and nine months ended September 30, 2008 compared to the same periods in 2007.

	Three months ended September 30,				Nine Months ended September 30,
	2008		2007		2008		2007
Average daily production:
Oil (Bopd)		24,937		24,224		24,368		23,672
Natural gas (Mcfd)		50,156		31,499		44,139		29,994
Oil equivalents (Boepd)		33,297		29,474		31,725		28,671
Average prices: (1)
Oil ($/Bbl)	$	108.37	$	69.44	$	105.78	$	58.92
Natural gas ($/Mcf)		7.97		5.29		8.14		5.82
Oil equivalents ($/Boe)		93.21		62.61		92.64		54.68
Production expense ($/Boe) (1)		8.22		7.72		8.62		7.53
EBITDAX (in thousands)		238,289		132,817		665,027		332,472
Net income (in thousands) (2)		105,256		56,372		320,534		130,831
Diluted net income per share		0.62		0.33		1.89		0.80

        ⁽¹⁾ Average prices and per-unit production expense are calculated based on sales volumes. Crude oil sales volumes exceeded production in the third quarter and first nine months of 2008 by 7 MBbls and 42 MBbls, respectively. Crude oil production volumes exceeded oil sales in the third quarter and first nine months of 2007 by 49 MBbls and 96 MBbls, respectively.

        ⁽²⁾ Net income and diluted net income per share for the nine months ended September 30, 2007 are after pro forma adjustments (i) to provide for income taxes as if the Company had been a subchapter C corporation prior to the completion of its initial public offering, and (ii) to eliminate the $198.4 million charge recorded to recognize deferred taxes upon its conversion from a nontaxable subchapter S corporation to a taxable subchapter C corporation in conjunction with the Company’s May 2007 initial public offering.

The following table presents average daily production for the Company’s principal operating areas for the three months ended September 30, 2008 compared to the quarters ended June 30, 2008 and September 30, 2007.

(boe per day)	Q3 2008	Q2 2008	Q3 2007
Red River Units	13,375	13,551	13,531
Montana Bakken	6,187	6,363	7,637
North Dakota Bakken	3,444	2,082	1,119
Other Rockies	2,275	2,484	1,834
Arkoma Woodford	2,627	2,125	953
Other Mid-Continent	4,895	4,419	3,945
Gulf Coast	494	599	455
Total	33,297	31,623	29,474

Total production averaged 33,297 boepd for the third quarter of 2008, an increase of five percent over the second quarter of 2008 and 13 percent over the third quarter of 2007. The Company exited the quarter with production averaging 34,889 boepd for September 2008.

Red River Units

The Red River Units accounted for 40 percent of Continental’s production in the third quarter of 2008. As the Company anticipated, production in the Units declined slightly from the second quarter as the Company converted producer wells to injectors and continued to expand its secondary recovery program. During the third quarter, Continental also drilled two additional water source wells to increase its water injection capacity.

Continental has allocated $101 million in operational capital expenditures to the Units in 2009. The Company plans to drill 22 producer and 12 injector wells in the Units, convert 20 producer wells to injectors, convert 26 air injector

wells to water injectors, drill two water disposal wells, and complete a sixth water supply well.

Continental formerly expected production to peak in the Units at 21,000 boepd in late 2009. The Company has begun to reduce capital expenditures, decreasing its operated rig count in the Units from five to two, and consequently the production peak is now expected to be lower, but with a more gradual production decline from the peak. Overall reserves and ultimate recovery are not expected to be affected by the timing of the peak. As a result of these initiatives, the Company expects to exit 2009 with production of approximately 19,000 boepd in the Red River Units.

Bakken Shale

Third quarter production in the North Dakota Bakken increased to 3,444 boepd, an increase of 65 percent over the second quarter of 2008, primarily reflecting improved well completion techniques and superior results from Continental’s Three Forks/Sanish (TFS) completions.

During the third quarter, Continental participated in the completion of 16 gross (5.3 net) Middle Bakken and TFS wells in North Dakota. These wells had an average rate of 602 boepd during their seven-day production period tests, representing a 22% increase in performance over the Bakken completions reported by the Company for the first half of 2008.

Of particular significance were the higher initial rates that the Company observed from its Three Forks/Sanish completions, compared to those targeting the Middle Bakken formation. In 2008, of the 23 gross (9 net) completions in the North Dakota Bakken that are Company-operated, Continental has completed nine gross (3.7 net) wells in the TFS formation. These TFS wells have had an average rate of 852 boepd during their seven-day production period tests, which represents a 49% increase over the average rate of 573 boepd for Company-operated Middle Bakken completions so far in 2008.

It is also significant to note that these TFS completions were strategically distributed throughout Continental’s acreage on the Nesson anticline and achieved comparable results spanning a distance of 100 miles north-to-south.

Recent completions of Company-operated wells targeting the Three Forks/Sanish formation of the North Dakota Bakken are shown below with average seven-day production period test results in gross barrels:

— Maryann 1-15H (38% WI) in McKenzie Co. – 1,216 boepd;

— Morris 1-23H (29% WI) in Dunn Co. – 1,027 boepd;

— Kirkland 1-33H (46% WI) in McKenzie Co. – 733 boepd;

— Arvid 1-34H (42% WI) in Divide Co. – 340 boepd.

The Company also recently completed the Veigel 1-9H (46% WI) in Dunn Co. and the Malcolm 1-29H (45% WI) in Williams Co., which produced at average rates of 863 boepd and 658 boepd, respectively, during their production period tests. These two wells were completed in the Middle Bakken formation.

In Richland County, MT, the Company saw improved production results during the third quarter in its 320-acre infield and field-extension program. Third quarter 2008 infield wells averaged 391 boepd in their seven-day production period tests, 33 percent higher than wells completed in the second quarter in the infield program. Continental attributed the production increase to the use of single-leg laterals with liners and multi-staged fracture-stimulation techniques that were developed in its North Dakota Bakken operations.

Recent notable completions in Richland County are shown below with average seven-day production period test results in gross barrels:

— Ardelle 3-10H (95% WI) – 531 boepd;

— Melvin 3-3H (83% WI) – 405 boepd;

— Staci 3-11H (95% WI) – 346 boepd;

— Martin 1-27H (95% WI) – 228 boepd.

The Company recently began drilling the Joann 1-32H (89% WI) in the northern tier of its Montana Bakken acreage. It is Continental’s first Three Forks/Sanish test well in Montana.

Continental also announced that it has joined several companies to form the Montana Bakken EOR Consortium, in order to initiate a CO² injection pilot project in Richland County to determine the effectiveness of using CO² for enhanced oil recovery in the play. The consortium intends to start injecting CO² before year-end 2008, to inject CO² for one month, and then shut in the well for one month. The well will then be produced back and data analyzed to determine its enhanced oil recovery potential.

Continental currently has the largest acreage position in the Bakken Shale resource play with approximately 604,000 net acres, of which approximately 75 percent is in North Dakota. The Company has allocated $281 million in 2009 operational capex in the North Dakota and Montana Bakken, or 52 percent of its operational capex budget, to drill 131 gross (44.1 net) wells in the play.

“We have a tremendous opportunity to add reserves in North Dakota,” Mr. Hamm said. “At year-end 2007, we had 300,000 net acres in the North Dakota Bakken, and proved reserves in the play represented only five percent of our total proved reserves. We’ve expanded that acreage position to 449,000 net acres since January 1. We have completed our first nine wells in the Three Forks/Sanish formation, with seven showing very strong results, and our Middle Bakken completions have been increasingly productive. Our opportunity over the next several years to grow reserves in this play is clearly a game-changer.”

Arkoma Woodford

In the Arkoma Woodford play, Continental increased production in the third quarter by 24 percent, compared with the second quarter of 2008. The Company completed 34 gross (5.2 net) wells during the quarter.

The Company completed its strongest well to date, the Blevins 1-1H (41% WI) in Hughes Co. during the third quarter. The Blevins well averaged 8.1 MMcf per day during its seven-day production period test, but actually increased production afterward, achieving a maximum seven-day rate of 10.4 MMcf. The Blevins was drilled east of the Salt Creek area and north of where the majority of the Company’s Arkoma Woodford wells have been drilled.

Continental also continued to develop its simul-fracture technology in the Arkoma Woodford. In the third quarter, the Company completed the six-well Luna-Pratt simul-frac project. It fracture-stimulated the horizontal laterals of the six wells one pair at a time. The six wells individually averaged 3.8 gross MMcf per day during their seven-day production test periods, with little variation between the most and least productive wells.

The next planned simul-frac will involve seven Pasquali wells in the Ashland development section of the play. Five of the wells have been drilled; drilling the final two and the simul-frac completion process are scheduled for completion by year-end.

Continental has allocated $99 million in 2009 operational capital expenditures to the Arkoma Woodford and plans to drill 76 gross (14.8 net) wells in the play during the year.

Anadarko Woodford Shale and Atoka Shale

In the Anadarko Woodford shale of western Oklahoma, Continental is currently drilling two test wells, the Brown 1-2H (100% WI) in Dewey Co. and the McCalla 1-11H (90% WI) in Grady Co. The Company has approximately 111,000 net acres in the play.

In Ellis County, Oklahoma, the Company has just begun completion of its initial test well in the Atoka shale play, the Shrewder 1-22H (100% WI). Continental is also drilling the Jones-Trust 1-168H (100% WI) in Lipscomb Co., TX in the western part of the play. Continental has leased 34,000 net acres in the Atoka shale play.

Capital Budget and Guidance

Continental expects strong growth in production and reserves in the fourth quarter of 2008 and in 2009. However, the Company no longer plans to achieve its year-end exit rate target of 43,000 boepd as a result of reductions in rig count and capital expenditures.

Continental began reducing its operated rig count in October with the intention of having 17 operated rigs as of December 31, 2008, compared with the previous target of 35 operated rigs. The Company’s 2009 capital budget envisions an average of 15.5 operated rigs for the year, with eight operating in the North Dakota Bakken.

Continental expects to achieve its 2008 total production volume target of at least 12,000 Mboe. Current trends indicate that the Company may slightly exceed its guidance for production expense, which had been expected to be $7.75-to-$8.00 per boe, and its guidance for depreciation, depletion and amortization expense, which had been expected to be $9.75-to-$10.50 per boe.

Continental’s regional allocations of capital expenditures in 2009 are listed below. Operational capex includes drilling, work-over and facilities capital expenditures.

	2009 Capex Budget (in millions)		Net Wells
North Dakota Bakken	$	257	38.2
Red River Units		101	23.0
Arkoma Woodford		99	14.8
Montana Bakken		24	5.9
Anadarko Woodford		14	4.1
Atoka		12	4.5
Other		34	10.3
Operational capex		541	100.8
Land and seismic		63
Other capital expenditures		5
Total capex		609

“Based on how commodity prices trend next year, we will adjust to maintain our capital budget generally in line with expected cash flows,” Mr. Hamm said. “We have a lean, productive team of approximately 400 employees. We are not planning layoffs or a reduction in force. In fact, our efficiency and productivity are significant competitive advantages in just this kind of challenging environment.”

Continental announced the following operating and financial guidance for 2009. As forward-looking information, this guidance is subject to a variety of risks and uncertainties, including adjustments related to fluctuations in commodity prices. Risk factors are discussed further at the end of this press release and in the Company’s filings with the Securities and Exchange Commission.

	Year Ended December 31, 2009
Production volumes:
Oil (MMbls)	10.2 -11
Gas (MMcf)	22.4 - 24
Oil equivalent (MMboe)	14 - 15
Price differentials(1) :
Oil (Bbl)	$8.00 - $10.00
Gas (Mcf)	$1.50 - $2.00
Operating expenses:
Production expense (per boe)	$7.75 - $8.50
Production tax (per $ of sales)	6.25% - 6.75%
Depreciation, depletion, amortization and accretion (per boe)	$13.00 - $14.00
General and administrative expense (per boe)(2)	$1.75 - $2.25
Non-cash stock-based compensation (per boe)	$0.70 - $0.90
Income tax rate (percent of pre-tax income)	38%
Percent of income tax deferred	90%

⁽¹⁾ Differential to calendar month average NYMEX futures price for oil and to average of last three trading days of prompt NYMEX futures contract for gas.

⁽²⁾ Excludes non-cash stock-based compensation.

Conference Call Information

Continental Resources will host a conference call on Thursday, Nov. 6, 2008, at 10:00 a.m. ET (9 a.m. CT) to discuss its third quarter 2008 results. Interested parties may listen to the conference call via the Company’s website at http://www.contres.com or by phone:

Dial in:	(888) 713-4217
Intl. dial in:	(617) 213-4869
Pass code:	67361430
Replay number:	(888) 286-8010
Intl. replay:	(617) 801-6888
Pass code:	55052650

Conference Presentations

Continental management is currently scheduled to present at the Bank of America Energy Conference in Key Biscayne, Florida on November 13, 2008; at the NYSE Euronext and WJB Capital Group Boston Growth Conference on December 4, 2008; and at the Raymond James Small and Mid-Cap Equity Conference in Boston on December 11, 2008. Presentations and audio links will be posted on the Company’s web site.

Continental Resources is a crude-oil concentrated, independent oil and natural gas exploration and production company with operations in the Rocky Mountain, Mid-Continent and Gulf Coast regions of the United States. The Company focuses its operations in large new and developing 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.

This press release includes forward-looking information that is subject to a number of risks and uncertainties, many of which are beyond the Company’s control. All information, other than historical facts included in this press release, regarding strategy, future operations, drilling plans, estimated reserves, future production, estimated capital expenditures, projected costs, the potential of drilling prospects and other plans and objectives of management are forward-looking information. All forward-looking statements speak only as of the date of this press release. Although the Company believes that the plans, intentions and expectations reflected in or suggested by the forward-looking statements are reasonable, there is no assurance that these plans, intentions or expectations will be achieved. Actual results may differ materially from those anticipated due to many factors, including oil and natural gas prices, industry conditions, drilling results, uncertainties in estimating reserves, uncertainties in estimating future production from enhanced recovery operations, availability of drilling rigs and other services, availability of crude oil and natural gas transportation capacity, availability of capital resources and other factors listed in reports we have filed or may file with the Securities and Exchange Commission.

CONTACT:     Continental Resources, Inc.

J. Warren Henry	Brian Engel
Investors	Media
(580) 548-5127	(580) 249-4731

Condensed Consolidated Statements of Operations	Three months ended September 30,						Nine months ended September 30,
(in thousands, except per share amounts)	2008			2007			2008			2007
	(unaudited)
Revenues:
Oil and natural gas sales	$	286,194		$	166,704		$	809,238		$	422,734
Loss on mark-to-market derivatives		—			(14,393	)		(7,966	)		(14,393	)
Oil and natural gas service operations		7,415			4,461			23,422			14,880
Total revenues		293,609			156,772			824,694			423,221
Operating costs and expenses:
Production expense		25,247			20,561			75,273			58,201
Production tax		17,941			8,711			48,411			22,311
Exploration expense		15,285			2,758			26,278			6,664
Oil and gas service operations		5,099			2,414			15,797			8,767
Depreciation, depletion, amortization and accretion		39,120			23,568			95,828			67,306
Property impairments		9,947			4,099			17,620			12,992
General and administrative (1)		10,005			6,231			27,812			27,654
(Gain) loss on sale of assets		(194	)		62			(406	)		(338	)
Total operating costs and expenses		122,450			68,404			306,613			203,557
Income from operations		171,159			88,368			518,081			219,664
Interest expense and other		(2,321	)		(2,456	)		(8,050	)		(8,647	)
Net income before income tax expense		168,838			85,912			510,031			211,017
Income tax expense (2)		63,582			29,540			189,497			243,329
Net income (loss)	$	105,256		$	56,372		$	320,534		$	(32,312	)
Basic net income (loss) per share	$	0.63		$	0.34		$	1.91		$	(0.20	)
Diluted net income (loss) per share		0.62			0.33			1.89			(0.20	)
Basic weighted average shares outstanding		168,097			167,232			168,008			162,869
Diluted weighted average shares outstanding		169,526			169,043			169,477			162,869

(1) Includes non-cash charges for stock-based compensation of $2.6 million and $1.2 million for the three months ended September 30, 2008 and 2007, respectively, and $6.5 million and $12.1 million for the nine months ended September 30, 2008 and 2007, respectively.

(2) Income tax expense for the nine months ended September 30, 2007 includes a charge of $198.4 million to recognize deferred taxes upon the conversion from a nontaxable subchapter S corporation to a taxable subchapter C corporation in conjunction with the Company’s May 2007 initial public offering of common stock.

Condensed Consolidated Balance Sheets	September 30		December 31
(in thousands)	2008		2007
	(unaudited)
Assets:
Cash and cash equivalents	$	3,133	$	8,761
Receivables		299,764		163,090
Inventories and other		36,636		33,713
Net property and equipment		1,765,848		1,157,926
Other assets		1,296		1,683
Total assets	$	2,106,677	$	1,365,173
Liabilities and shareholders’ equity:
Current liabilities	$	467,473	$	266,106
Long-term debt		229,400		165,000
Other noncurrent liabilities		458,600		310,935
Shareholders’ equity		951,204		623,132
Total liabilities and shareholders’ equity	$	2,106,677	$	1,365,173

Condensed Consolidated Statements of Cash Flows	Nine months ended September 30,
(in thousands)	2008			2007
	(unaudited)
Net income (loss)	$	320,534		$	(32,312	)
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Non-cash expenses		251,374			351,526
Changes in assets and liabilities		18,024			(40,858	)
Net cash provided by operating activities		589,932			278,356
Net cash used in investing activities		(660,116	)		(367,933	)
Net cash provided by financing activities		64,556			87,882
Effect of exchange rate on change in cash and cash equivalents		—			160
Net change in cash and cash equivalents		(5,628	)		(1,535	)
Cash and cash equivalents at beginning of period		8,761			7,018
Cash and cash equivalents at end of period	$	3,133		$	5,483

Non-GAAP Financial Measures

EBITDAX represents earnings before interest expense, income taxes, depreciation, depletion, amortization and accretion, property impairments, exploration expense, unrealized derivative gains or losses, and non-cash compensation expense. EBITDAX is not a measure of net income or cash flow as determined by generally accepted accounting principles (GAAP). 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. The Company’s computations of EBITDAX may not be comparable to other similarly titled measures of other companies. The Company believes that EBITDAX is a widely followed measure of operating performance and may also be used by investors to measure its ability to meet future debt service requirements, if any. The Company’s credit facility requires that it 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 the Company. The following table represents a reconciliation of the Company’s net income to EBITDAX.

	Three months ended September 30,				Nine months ended September 30,
(in thousands)	2008		2007		2008		2007
	(unaudited)
Net income (loss)	$	105,256	$	56,372	$	320,534	$	(32,312	)
Unrealized loss on mark-to-market derivatives		—		12,542		—		12,542
Income tax expense		63,582		29,540		189,497		243,329
Interest expense		2,506		2,774		8,782		9,854
Depreciation, depletion, amortization and accretion		39,120		23,568		95,828		67,306
Property impairments		9,947		4,099		17,620		12,992
Exploration expense		15,285		2,758		26,278		6,664
Equity compensation		2,593		1,164		6,488		12,097
EBITDAX	$	238,289	$	132,817	$	665,027	$	332,472