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Continental Resources Increased 2010 Production 16 Percent Over 2009

Proved Reserves Increased 42 Percent to 364.7 Million Barrels of Oil Equivalent
Fourth Quarter 2010 EBITDAX Increased 40 Percent Compared with 2009 Fourth Quarter
4Q10 Bakken Production 64 Percent Higher than 4Q09

ENID, Okla., Feb. 23, 2011 /PRNewswire via COMTEX/ --

Continental Resources, Inc. (NYSE: CLR) reported strong growth in crude oil and natural gas production for 2010. Total production of 15.8 million barrels of oil equivalent (MMBoe) for the year represented a 16 percent gain over production of 13.6 MMBoe for 2009.

(Logo: http://photos.prnewswire.com/prnh/20080505/LAM014LOGO)

"We achieved our 2010 production target and again reported strong growth in oil-concentrated proved reserves," said Harold Hamm, Chairman and Chief Executive Officer. "We're on track today for 30 percent production growth in 2011."

Fourth Quarter 2010 Results

The Company reported production of 48,034 barrels of oil equivalent per day (Boepd) for the fourth quarter of 2010, a 27 percent increase over production of 37,747 Boepd for the fourth quarter of 2009 and an increase of seven percent over production in the third quarter of 2010.

Crude oil accounted for 73 percent of Continental's fourth quarter 2010 production.

Continental's proved reserves grew to 364.7 MMBoe as of December 31, 2010, 42 percent higher than proved reserves of 257.3 MMBoe at year-end 2009.

The bulk of the increase reflected its drilling program in the Bakken play, which is expected to continue leading Continental's growth.

For the fourth quarter of 2010, the Company reported a net loss of $45.0 million, or $0.27 per diluted share, compared with net income for the fourth quarter of 2009 of $49.5 million, or $0.29 per diluted share.

The net loss for the fourth quarter of 2010 included a $188.4 million loss on mark-to-market derivative instruments, a $15.6 million pre-tax property impairment charge, and a $2.2 million loss on sale of an asset. The loss on derivative instruments was comprised of a $194.4 million unrealized loss, offset partially by a $6.0 million realized gain.

In the fourth quarter, the combined impairment charge, loss on sale of asset and $194.4 million unrealized loss on derivatives reduced net income by $0.78 cents per share on an after-tax basis.

"Throughout 2010 we put in place a series of price swaps and collars to reduce the uncertainty of future cash flow in order to underpin our capital expenditures and drilling plan for the next three years," Mr. Hamm said.

Net income for 2010 as a whole was $168.3 million, or $0.99 per diluted share, compared with net income of $71.3 million, or $0.42 per diluted share for 2009. For 2010, the combined effect of unrealized derivative losses, total property impairment charges, and gain on sale of assets reduced net income by $0.74 cents per share.

Crude oil and natural gas sales were $273.1 million for the fourth quarter of 2010, compared with $203.3 million for the same period of 2009.

Continental reported EBITDAX of $220.9 million for the fourth quarter of 2010, a 40 percent increase over EBITDAX of $158.1 million for the fourth quarter of 2009 and a 12 percent increase over EBITDAX for the third quarter of 2010.

Full-year 2010 EBITDAX was $810.9 million, an increase of 80 percent over 2009 EBITDAX of $450.6 million. For the Company's definition and reconciliation of EBITDAX to net income, see "Non-GAAP Financial Measures" at the end of this press release.

Continental's average realized crude oil price was $75.41 per barrel in the fourth quarter of 2010, while the average realized natural gas price was $4.15 per Mcf, yielding a blended realized price of $61.98 per Boe. In the fourth quarter of 2009, the Company realized a blended price of $56.69 per Boe.

The Company's crude oil price differential for the fourth quarter of 2010 was $9.92 per barrel, and its natural gas price differential was a premium of $0.35 per Mcf.

Production expense was $5.31 per Boe for the fourth quarter of 2010, compared with $6.71 per Boe for the fourth quarter of 2009. The Company attributed the reduced production expense in 2010 primarily to renegotiated equipment leases and reduced injectant costs in the Red River Units, as well as new production growth.

General and administrative expense was $3.09 per Boe for the fourth quarter of 2010, compared with $3.18 per Boe for the comparable period in 2009.

As of December 31, 2010, the Company's balance sheet included $7.9 million in cash and $926.0 million in long-term debt. The Company's long-term debt at year-end 2010 included $30.0 million in borrowings under its $750 million revolving credit facility.

2010 Proved Reserves Grow 42 Percent

Continental increased its proved reserves to 364.7 MMBoe for the year ended December 31, 2010. The additions primarily reflected the Company's accelerated drilling in the North Dakota Bakken. During 2010, Continental completed or participated in completing 76.5 net wells in the Bakken.

Total reserve additions were 95.2 MMBoe, which equated to 602 percent of the year's production of 15.8 MMBoe. Essentially all of Continental's 2010 reserve additions were the result of the Company's exploration and production efforts; only 0.4 MMBoe of proved reserves were acquired by purchase. The proved reserve additions and acquisitions were at an average finding and development (F&D) cost of $12.42 per Boe, excluding revisions. The Company also reported 27.6 MMBoe in positive revisions, yielding a total F&D cost of $9.63, including revisions.

Of the total 2010 proved reserves, 38 percent were proved developed producing (PDP).

The Company's 2010 proved reserves included 1,282 gross (546.7 net) proved undeveloped locations (PUDs). Of these, 393.7 net PUDs, or 72 percent of the total, are located in the Bakken Shale play.

"We have a tremendous, multi-decade growth platform," Mr. Hamm said.

Continental's 2010 proved reserves are primarily located in three plays: The Bakken and the Red River Units in Montana, North Dakota and South Dakota; and in the Oklahoma Woodford play. The Bakken accounted for 54 percent of proved reserves, followed by the Oklahoma Woodford with 26 percent and the Red River Units with 15 percent.

Continental's 2010 proved reserves represented $12.0 billion in undiscounted future net cash flows, before income taxes, with a net present value discounted at 10 percent (PV-10) of $4.6 billion. Continental's standardized measure of discounted future net cash flows, which differs from PV-10 by including the effects of income taxes on future net cash flows, was $3.8 billion at December 31, 2010, representing an $0.8 million difference from PV-10, because of the tax effect.

Ryder Scott Company, L.P. evaluated properties representing 100 percent of the Company's PUDs and 94 percent of Continental's PV-10 at year-end 2010, with Continental reserve engineers evaluating the remaining properties.

Operating Highlights


Three months ended


Year ended


December 31,


December 31,


2010


2009


2010


2009

Average daily production:












Crude oil (Bopd)


35,296



28,034



32,385



27,459

Natural gas (Mcfpd)


76,427



58,277



65,598



59,194

Crude oil equivalents (Boepd)


48,034



37,747



43,318



37,324

Average sales prices: (1)












Crude oil ($/Bbl)

$

75.41


$

66.91


$

70.69


$

54.44

Natural gas ($/Mcf)


4.15



4.31



4.49



3.22

Crude oil equivalents ($/Boe)


61.98



56.69



59.70



45.10

Production expense ($/Boe) (1)


5.31



6.71



5.87



6.89

EBITDAX (in thousands)


220,917



158,070



810,877



450,648

Net income (loss) (in thousands)


(45,028)



49,514



168,255



71,338

Diluted net income (loss) per share


(0.27)



0.29



0.99



0.42


(1) Average sales prices and per-unit expenses are calculated based on sales volumes, and

exclude any effect of derivatives. Crude oil production exceeded sales volumes in the fourth

quarter of 2010 by 12 thousand barrels (MBbls); crude oil sales exceeded production volumes

in the fourth quarter of 2009 by 114 MBbls. Crude oil sales exceeded production volumes for

fiscal 2010 by 78 MBbls; crude oil production exceeded sales volumes in fiscal 2009 by 82 MBbls.

The following table presents the Company's average daily production by region for the periods presented.




4Q


3Q


4Q

Boe per day


2010


2010


2009

North Region:







North Dakota Bakken


17,834


15,062


8,384

Montana Bakken


4,686


4,891


5,368

Red River Units


13,896


14,167


14,396

Other


1,207


993


983

South Region:







Anadarko Woodford


1,705


1,377


741

Arkoma Woodford


4,403


4,413


3,573

Other


2,989


2,640


2,831

East Region


1,314


1,232


1,471

Total


48,034


44,775


37,747


Bakken Shale Play (North Dakota and Montana)

For the fourth quarter of 2010, Bakken production climbed to 22,520 Boepd, or 47 percent of Continental's total production, compared with 36 percent of production in the fourth quarter of 2009. On a year-over-year basis, Continental's Bakken production increased 64 percent over the fourth quarter of 2009.

In the North Dakota portion of the Bakken, Continental's fourth quarter 2010 production was 17,834 Boepd, an increase of 113 percent over the total for the fourth quarter of 2009.

The Company participated in completing 77 gross (26.4 net) wells in the North Dakota Bakken in the fourth quarter of 2010, with initial production rates averaging 1,002 Boepd during single-day test periods. During 2010 as a whole, the Company completed or participated in completing 222 gross (71.1 net) wells in the North Dakota Bakken, bringing its total wells drilled in this part of the play to 475 gross (150.2 net) wells at December 31, 2010.

Continental has restricted initial production rates on a significant number of its Bakken wells to minimize natural gas flaring and in response to constraints in transportation capacity primarily related to periodic severe winter weather conditions.

Notable Company-operated wells completed in North Dakota during the fourth quarter of 2010 (with initial test period gross production results) included:

  • Rolfsrud 1-11H (43% WI) in McKenzie Co. - 1,713 Boepd;
  • Jerol 1-27H (28% WI) in Williams Co. - 1,663 Boepd;
  • Brandvik 2-25H (45% WI) in Dunn Co. - 1,630 Boepd;
  • Olson 2-8H (33% WI) in McKenzie Co. - 1,613 Boepd;
  • Evenson 1-19H (69% WI) in Divide Co. - 1,426 Boepd;
  • Hendrickson 2-36H (83% WI) in McKenzie Co. - 1,323 Boepd; and
  • Tangsrud 2-1H (92% WI) in Divide Co. - 1,023 Boepd.

In addition, Continental completed three ECO-Pad(R) projects in North Dakota during the fourth quarter of 2010. ECO-Pad technology allows four wells (two Middle Bakken, two Three Forks) to be drilled from a single pad on two adjoining 1,280-acre spacing units. Application of ECO-Pad technology is expected to increase recoveries per well and to reduce drilling costs, completion costs and environmental impact by centralizing operations on a single pad. The three ECO-pad projects are listed below with their gross initial production results.

The Miles-Kennedy ECO-Pad wells were drilled in McKenzie County. This project involved the Miles 1-6H and 2-6H (31% WI for each) and the Kennedy 1-31H (31% WI) and 2-31H (67% WI). Initial production averaged 1,377 Boepd, with the strongest well testing at 1,448 Boepd.

The Glasoe-Raymo ECO-Pad project was drilled in Divide County. This involved the Glasoe 2-19H (46% WI) and 3-19H (50% WI) and the Raymo 1-30H (71% WI) and 2-30H (76% WI). Initial production averaged 940 Boepd per well for the four wells, with the strongest well testing at 1,129 Boepd.

The Bridger-Bonneville ECO-Pad project was drilled in Dunn County. It involved the Bridger 2-14H and 3-14H (47% WI for each) and the Bonneville 2-23H and 3-23H (47% WI for each). Initial production (restricted) averaged 745 Boepd per well for the four wells, with the strongest well testing at a restricted 883 Boepd.

In Montana, Continental announced the completion of two notable wells in Richland County in the fourth quarter of 2010. The Tolksdorf 1-1H (95% WI) and the Baxter 1-5H (33% WI) were completed in the extension area north and northeast of the Elm Coulee Field fairway, and had initial production test rates of 642 gross Boepd and 412 gross Boepd, respectively. The two wells were fracture-stimulated with 24 stages each.

"We're pleased with the outcome on these two wells. This sets up the area for continued development, expanding the field with new technology," Mr. Hamm said. At year-end 2010, Continental had 165,316 net undeveloped acres leased in the Montana Bakken.

Continental completed or participated in 11 gross (5.5 net) wells in the Montana Bakken during 2010. As of year-end 2010, the Company had completed 171 gross (108.6 net) wells in the Montana portion of the play.

"Continental completed the first commercially viable well in the North Dakota Bakken that used both horizontal drilling and fracture stimulation - the Robert Heuer 1-17R in Divide County in March 2004," Mr. Hamm said. "We were an early pioneer in the play, and since then we've established Continental as the leading leaseholder. We expect the Bakken to drive our growth for many years."

At year-end 2010, Continental had a total of 855,936 net acres leased in the Bakken play, with 623,649 net acres leased in North Dakota and 232,287 net acres in Montana. The Company has 21 operated drilling rigs in North Dakota and two in Montana.

Red River Units (Montana, North Dakota and South Dakota)

The Company's production in the Red River Units averaged 13,896 Boepd in the fourth quarter of 2010. Continental currently has two operated rigs active in the Units, completing its increased density drilling pattern in the water-flood secondary recovery project.

Niobrara Shale Play (Colorado and Wyoming)

Continental began drilling the Newton 1-4H (87% WI) in early February 2011 in Weld County, Colorado. The Newton 1-4H is the first 1,280-acre spaced well in the Niobrara, which the Company expects will yield superior economics compared with 640-acre spaced wells.

The Company plans to drill five gross (3.3 net) wells in the Niobrara in 2011. It currently has 71,712 net acres leased in the DJ Basin - Niobrara.

Fort Union (Wyoming)

During 2010, the Company participated in completing two conventional Fort Union sand wells in Sweetwater County, Wyoming. The Barricade 24-36 (22% WI) was completed November 10 with an initial production test rate of 5.0 gross MMcfpd of natural gas and 198 gross Bopd.

The Barricade 11-7 (40% WI) was completed November 18 with an initial production test rate of 4.4 gross MMcfpd of natural gas and 100 gross Bopd.

Continental owns an average 22 percent working interest in the 12,970 gross acre Barricade Unit and a seven percent average working interest in the adjacent 8,640 gross acre Endurance Unit. Based on well control in the area, Continental believes its entire acreage position is prospective for development on 40-acre spacing. The two Barricade wells indicate an average estimated ultimate recovery (EUR) of 2.65 Bcf of natural gas and 58,000 Bo per well.

Woodford Shale Play (Oklahoma)

Production in the Anadarko Woodford Shale play in western Oklahoma was 1,705 Boepd in the fourth quarter of 2010, an increase of 130 percent over the fourth quarter of 2009 and an increase of 24 percent over the third quarter of 2010. Increased production reflects the Company's quickening pace of drilling in late 2010.

During 2010, the Company completed or participated in 16 gross (8.2 net) wells in the Anadarko Woodford, delineating the productive potential of the play from the Northwest Cana to the Southeast Cana, a distance of 90 miles.

In January 2011, Continental completed the Sprowls 1-14H (100% WI) in Grady County, 17 miles northwest of the Dana 1-29H, which the Company announced in October 2010. The Company previously established production in the Dana 1-29H, which is 41 miles southeast of the center of the Cana Play.

The Sprowls 1-14H was completed flowing at 2.8 gross MMcfpd and 96 gross Bopd in its initial test period. It is producing rich gas, 1313 Btu per Mcf , which is characteristic of the Southeast Cana. At a residue price of $3.95 per MMBtu, the Sprowls 1-14H had a wellhead price of $8.45 per Mcf for its January gas production.

"The Sprowls 1-14H gives us a pair of strong wells at the southeast end of the current extent of the Anadarko Woodford," Mr. Hamm said. "In the Northwest Cana, we completed the Brown 1-2H and the Doris 1-25H. In the Southeast Cana, we now have the Dana 1-29H confirmed by the Sprowls 1-14H.

"We are currently working to extend the Southeast Cana even farther, drilling a test well 24 miles southeast of the Dana 1-29H to determine how far the Southeast Cana's productivity extends."

In Northwest Cana, Continental's type curve on wells completed to date reflects an EUR of 6.6 Bcf of natural gas and 85,000 barrels of crude oil. BTU content of the gas is typically about 1200. In Southeast Cana, the Company's type curve for wells completed in the silica-rich section reflects an EUR of 4.6 Bcf of natural gas and 88,000 barrels of crude oil.The Southeast Cana typically produces gas with a BTU content in excess of 1300.

Continental has now completed four wells in the Southeast Cana: The McCalla 1-11H, Ballard 1-17H, Dana 1-29H and the Sprowls 1-14H. January 2011 natural gas sales prices for these wells were in a range of $7.00 to $8.45 on a wellhead Mcf basis.

"Given the rich gas and oil production, even at current low gas prices, we're seeing 40 percent-plus rates of return in the Northwest Cana and 30 percent-plus in the Southeast," Mr. Hamm said.

Continental plans to complete or participate in 99 gross (28.8 net) wells in the Anadarko Woodford in 2011. It currently has 10 operated rigs in the play, with nine in the Northwest Cana part of the play and one in the Southeast Cana.

In the Arkoma Woodford Shale play of Oklahoma, the Company's production was 4,403 Boepd in the fourth quarter of 2010, an increase of 23 percent over production in the fourth quarter of 2009. The increase reflected drilling activity in the East Krebs portion of the Arkoma Woodford in the past year. The Company currently has one operated rig active in the area.

At year-end 2010, the Company had 322,194 net acres leased in the Oklahoma Woodford, of which 267,542 net acres are in the Anadarko Woodford.

Paris Basin Opportunity

Continental initiated a process in the fourth quarter of 2010 to secure permits to develop four blocks covering approximately 67,000 net acres in the Paris Basin in France. The permits would be valid for five years. Continental is pursuing the Paris Basin opportunity in an 80/20 joint venture with Jordan Oil and Gas of Healdsburg, California. The two companies have worked together on several projects in North Dakota, and Jordan Oil and Gas has operating experience in France and other international oil and gas plays.

If awarded the permits, Continental and Jordan together would commit to invest a minimum of approximately $13.8 million over a four-year period. The French government is expected to rule on the permit applications by year-end 2011.

"We believe there is the potential for significant recoverable oil reserves, using technology that we've developed in the Bakken," Mr. Hamm said.

Conference Call Information

Continental Resources plans to host its fourth quarter 2010 earnings conference call on Thursday, Feb. 24, 2011 at 10 a.m. ET to discuss its results for the quarter. Those wishing to listen to the conference call may do so via the Company's web site at www.contres.com or by phone:

Time and date:

10 a.m. ET

Thursday, Feb. 24, 2011


Dial in:

888 680 0860

Intl. dial in:

617 213 4852

Pass code:

78472653

A replay of the call will be available later for 30 days on the Company's web site or by dialing:

Replay number:

888 286 8010

Intl. replay

617 801 6888

Pass code:

37956881



Conference Presentations


Continental management is currently scheduled to present at the following research conferences. Presentation materials will be available on the Company's web site.

March 8

Raymond James 32nd Annual Institutional Investors Conference, Orlando

March 30

Howard Weil 39th Annual Energy Conference, New Orleans

April 15

Platt's Rockies Oil and Gas Conference, Denver

Continental Resources is a crude-oil concentrated, independent oil and natural gas exploration and production company. The Company focuses its operations in large new and developing 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.

Forward-Looking Statements

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. Other than historical facts included in this press release, all information 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, changes in estimates of projected crude oil and natural gas recoveries from certain fields, 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, changes in regulatory constraints, and other factors listed in reports we have filed or may file with the Securities and Exchange Commission. The Company undertakes no obligation to publicly update any forward-looking statement to reflect events or circumstances that may arise after the date of this press release.

Contact:

Investor Relations

Media


Warren Henry, VP Investor Relations

Brian Engel, VP Public Affairs


(580) 548-5127

(580) 249-4731

Consolidated Statements of Income


Three Months


Year Ended


Ended December 31,


December 31,

In thousands, except per share data

2010



2009


2010



2009

Revenues:












Crude oil and natural gas sales

$

273,148


$

203,319


$

948,524


$

610,698

Gain (loss) on mark-to-market derivative instruments


(188,388)



(305)



(130,762)



(1,520)

Crude oil and natural gas service operations


6,619



4,624



21,303



17,033

Total revenues


91,379



207,638



839,065



626,211













Operating costs and expenses:












Production expenses


23,397



24,059



93,203



93,242

Production taxes and other expenses


22,904



14,816



76,659



45,645

Exploration expenses


5,178



2,889



12,763



12,615

Crude oil and natural gas service operations


5,083



3,317



18,065



10,740

Depreciation, depletion, amortization and accretion


69,274



52,727



243,601



207,602

Property impairments


15,564



13,203



64,951



83,694

General and administrative expenses (1)


13,599



11,410



49,090



41,094

(Gain) loss on sale of assets


3,267



(36)



(29,588)



(709)

Total operating costs and expenses


158,266



122,385



528,744



493,923

Income (loss) from operations


(66,887)



85,253



310,321



132,288

Other income (expense):












Interest expense


(20,272)



(9,159)



(53,147)



(23,232)

Other


272



310



1,293



952



(20,000)



(8,849)



(51,854)



(22,280)

Income (loss) before income taxes


(86,887)



76,404



258,467



110,008

Provision (benefit) for income taxes


(41,859)



26,890



90,212



38,670

Net income (loss)

$

(45,028)


$

49,514


$

168,255


$

71,338

Basic net income (loss) per share

$

(0.27)


$

0.29


$

1.00


$

0.42

Diluted net income (loss) per share

$

(0.27)


$

0.29


$

0.99


$

0.42

Basic weighted average shares outstanding


169,268



168,758



168,985



168,559

Diluted weighted average shares outstanding


169,268



169,784



169,779



169,529


(1) Includes non-cash charges for stock-based compensation of $3.1 million and $2.8 million for the three

months ended December 31, 2010 and 2009, respectively, and $11.7 million and $11.4 million for

the years ended December 31, 2010 and 2009, respectively.


Consolidated Balance Sheets

December 31

December 31

(in thousands)

2010

2009




Assets:



Cash and cash equivalents

$7,916

$14,222

Receivables

482,838

183,358

Derivative assets

21,365

2,218

Inventories and other current assets

70,207

36,230

Net property and equipment

2,981,991

2,068,055

Debt issuance costs, net

27,468

10,844

Total assets

$3,591,785

$2,314,927




Liabilities and shareholders' equity:



Current liabilities

$702,222

$219,710

Long-term debt

925,991

523,524

Other noncurrent liabilities

755,417

541,414

Shareholders' equity

1,208,155

1,030,279

Total liabilities and shareholders' equity

$3,591,785

$2,314,927



Consolidated Statements of Cash Flows

Year ended

December 31,

(in thousands)

2010

2009




Net income

$168,255

$71,338

Adjustments to reconcile net income to net cash provided by operating activities:



Non-cash expenses

535,578

347,698

Changes in assets and liabilities

(50,666)

(46,050)

Net cash provided by operating activities

653,167

372,986




Net cash used in investing activities

(1,039,416)

(499,822)




Net cash provided by financing activities

379,943

135,829







Net change in cash and cash equivalents

(6,306)

8,993

Cash and cash equivalents at beginning of period

14,222

5,229

Cash and cash equivalents at end of period

$7,916

$14,222


Non-GAAP Financial Measures

EBITDAX represents earnings before interest expense, income taxes, depreciation, depletion, amortization and accretion, property impairments, exploration expenses, unrealized derivative gains and losses, and non-cash equity compensation expense. EBITDAX is not a measure of net income or cash flows as determined by U.S. GAAP. Management believes EBITDAX is useful because it allows them to more effectively evaluate our operating performance and compare the results of our operations from period to period without regard to our financing methods or capital structure. We exclude the items listed above from net income in arriving at EBITDAX because these amounts can vary substantially from company to company within our 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 flows as determined in accordance with U.S. 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 revolving credit facility requires that we maintain a total debt to EBITDAX ratio of no greater than 3.75 to 1.0 on a rolling four-quarter basis. Our revolving 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


Year ended


ended December 31,


December 31,

in thousands

2010


2009


2010


2009

Net income (loss)

$

(45,028)


$

49,514


$

168,255


$

71,338

Interest expense


20,272



9,159



53,147



23,232

Provision (benefit) for income taxes


(41,859)



26,890



90,212



38,670

Depreciation, depletion, amortization and accretion

69,274



52,727



243,601



207,602

Property impairments


15,564



13,203



64,951



83,694

Exploration expenses


5,178



2,889



12,763



12,615

Unrealized losses on derivatives


194,420



874



166,257



2,089

Non-cash equity compensation


3,096



2,814



11,691



11,408

EBITDAX

$

220,917


$

158,070


$

810,877


$

450,648


SOURCE Continental Resources

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