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Continental Resources Increases Production 20 Percent in Third Quarter of 2010, Compared With Third Quarter 2009
Third Quarter Daily Production Seven Percent Higher Than Second Quarter 2010
EBITDAX Increases 53 Percent Over Third Quarter 2009
Company Plans to Spud First Long-Lateral Niobrara Shale Well Next Month

ENID, Okla., Nov. 3, 2010 /PRNewswire via COMTEX/ --

Continental Resources, Inc. (NYSE: CLR) reported strong growth in crude oil and natural gas production and strong year-over-year EBITDAX growth for the three months ended September 30, 2010.

Production was 44,775 barrels of oil equivalent per day (Boepd) for the third quarter of 2010, a 20 percent increase over production of 37,384 Boepd for the third quarter of 2009 and seven percent higher than daily production for the second quarter of 2010. Crude oil accounted for 75 percent of third quarter 2010 production.

Continental's production increased to 47,336 Boepd in September 2010, the final month in the third quarter.

Continental reported net income of $39.1 million, or $0.23 per diluted share, for the third quarter of 2010. Net income included a pre-tax property impairment charge of $14.7 million and a $24.2 million loss on mark-to-market derivative instruments. The loss on derivative instruments was comprised of a $36.6 million unrealized loss, offset partially by a $12.4 million realized gain. The third quarter 2010 impairment charge and $36.6 million unrealized loss together reduced net income per share by $0.19.

Net income for the third quarter of 2009 was $34.9 million, or $0.21 per diluted share. Net income for the third quarter of 2009 included an impairments charge of $11.8 million and a $2.1 million unrealized loss on mark-to-market derivative instruments.

Oil and natural gas sales were $238.8 million for the third quarter of 2010, compared with $168.4 million for the same period last year.

Continental reported EBITDAX of $196.9 million for the third quarter of 2010, a 53 percent increase over EBITDAX of $128.7 million for the third quarter of 2009. For the Company's definition and reconciliation of EBITDAX to net income, see "Non-GAAP Financial Measures" at the end of this press release.

"Strong production growth has us firmly on track for a solid 2010 and an even stronger year in 2011," said Harold Hamm, Chairman and Chief Executive Officer. "Our teams continue to operate at a very high level, and we have the liquids-rich inventory in hand to support years of continued growth."

Continental's average realized crude oil price was $67.26 per barrel in the third quarter of 2010, while the average realized natural gas price was $4.28 per Mcf, yielding a blended realized price of $56.92 per Boe. In the third quarter of 2009, the Company reported a blended price of $48.19 per Boe.

The Company's crude oil price differential for the third quarter of 2010 averaged $8.93 per barrel. The Company's natural gas differential was $0.08 per Mcf for the third quarter of 2010.

Production expense was $5.92 per Boe for the third quarter of 2010, compared with $6.50 per Boe for the third quarter of 2009.

General and administrative expense was $2.90 per Boe, compared with $2.88 per Boe for the third quarter of 2009. These included non-cash equity compensation of $0.63 per Boe for the third quarter of 2010 and $0.92 per Boe for the third quarter of 2009.

At September 30, 2010, the Company's balance sheet included $149.5 million in cash and $895.9 million in long-term debt. At the end of the third quarter of 2010, the Company had no borrowings under its revolving credit facility.

Operating Highlights


Three months ended Sept. 30,


Nine months ended Sept. 30,


2010


2009


2010


2009

Average daily production:












Crude oil (Bopd)


33,432



27,552



31,404



27,265

Natural gas (Mcfd)


68,057



58,995



61,948



59,503

Crude oil equivalents (Boepd)


44,775



37,384



41,728



37,182

Average prices: (1)












Crude oil ($/Bbl)

$

67.26


$

58.78


$

68.92


$

49.81

Natural gas ($/Mcf)


4.28



2.98



4.63



2.86

Crude oil equivalents ($/Boe)


56.92



48.19



58.82



40.92

Production expense ($/Boe) (1)


5.92



6.50



6.08



6.95

General and admin. exp. ($/Boe) (1)


2.90



2.88



3.09



2.98

EBITDAX (in thousands)


196,917



128,655



589,962



292,578

Net income (in thousands)


39,077



34,929



213,283



21,824

Diluted net income per share


0.23



0.21



1.26



0.13

1) Average prices and per-unit expenses are calculated based on sales volumes. Crude oil sales exceeded production volumes in the third quarter of 2010 by 78 MBbls. Crude oil sales exceeded production volumes in the third quarter of 2009 by 55 MBbls. Crude oil sales exceeded production volumes in the first nine months of 2010 by 90 MBbls. Crude oil production exceeded sales volumes in the first nine months of 2009 by 196 MBbls.

Production by Region



3Q


2Q


3Q

Boe per day


2010


2010


2009

North Region:







Red River Units


14,953


15,080


14,917

Montana Bakken


5,098


5,196


5,986

North Dakota Bakken


15,062


13,046


7,436

South Region:







Arkoma Woodford


4,413


3,721


4,260

Anadarko Woodford


1,377


1,079


294

Other


2,640


2,617


3,012

East Region


1,232


1,174


1,479

Total


44,775


41,913


37,384


Bakken Shale Play (North Dakota and Montana)

Continental's Bakken Shale production of 20,160 Boepd represented 45 percent of the Company's total production for the third quarter of 2010, compared with 36 percent in the third quarter last year. Bakken production for the third quarter of 2010 was 50 percent higher than that for the third quarter of 2009.

In the North Dakota Bakken, Continental reported a 103 percent increase in production, compared to the third quarter of 2009. The Company participated in completing 53 gross wells (19.3 net) in the North Dakota Bakken during the quarter. Initial production rates averaged 1,017 Boepd during single-day test periods. All initial well results in this press release are 24-hour tests.

In terms of Company-operated wells, Continental completed 26 gross operated wells (16.4 net) during the quarter, with an average 1,011 Boepd.

Continental's operated wells included its first ECO-Pad(R) project completion. The ECO-Pad design involves drilling, from a single pad, four wells on two adjoining 1,280-acre spacing units. Expected benefits from the innovative approach include higher production from longer horizontal bores, more efficient drilling and completion, and reduced environmental impact due to the smaller surface footprint, compared with four individual drilling sites.

The Company's first ECO-Pad project involved the Hegler 1-13H and 2-13H wells (both 83% WI) and the Arthur 1-12H and 2-12H wells (both 94% WI). Of the two wells that targeted the Three Forks zone, the Hegler 1-13H produced 1,195 Boe at 1,400 psi on a 22 choke, and the Arthur 1-12H produced 849 Boe at 1,150 psi on a 22 choke. In terms of the Middle Bakken wells, the Hegler 2-13H produced 1,203 Boe at 2,200 psi on an 18 choke, and the Arthur 2-12H produced 1,103 Boe at 2,350 psi on an 18 choke.

"The different flowing pressures clearly demonstrate that the Middle Bakken and Three Forks reservoirs are separate and not communicating in this part of western Dunn County," Mr. Hamm said.

The Company has 20 operated rigs in the North Dakota Bakken and two rigs in the Montana Bakken.

The Company has 864,559 net acres leased in the Bakken Shale play, with 620,620 net acres in North Dakota and 243,939 net acres in Montana portion.

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

Red River Units' production was 14,953 Boepd in the third quarter, or 33 percent of total production. Continental has two operated drilling rigs in the Units and is drilling wells to complete its increased density sweep pattern in the secondary recovery program. The Company also continues to convert producer wells to injection wells.

Woodford Shale Play (Oklahoma)

Production in the Anadarko Woodford shale play in western Oklahoma was 1,377 Boepd in the third quarter of 2010, reflecting a significant increase in drilling activity this year.

During the quarter, Continental completed a key confirmation well in the southeastern part of the play, the Dana 1-29H (78% WI) in Grady County. The Dana flowed at 2.5 MMcfd of liquids-rich natural gas and 88 Bopd in its initial one-day test period, by far the most productive well completed in the southeast extension of the play.

"The Southeast Cana clearly has an even higher liquids component than the core and the northwest," Mr. Hamm said. "We are very bullish on the southeastern part of the play, especially as we continue to improve the productivity of wells in the area." The Company expects to have additional data in early 2011 on another confirmation well in the Southeast Cana.

The Company has leased 258,816 net acres in the Anadarko Woodford. Continental currently has six operated rigs in the Anadarko Woodford play and plans to add two more by year end.

Continental's production in the eastern part of the Woodford Shale play, the Arkoma Woodford, was 4,413 Boepd in the third quarter of 2010. The Company currently has one operated rig in the Arkoma Woodford, where its acreage position totals 47,201 net acres.

Niobrara Shale Play (Colorado and Wyoming)

Continental today announced plans to spud its first long-lateral Niobrara shale well - the Newton 1-9H (87% WI) - in early December 2010 in northern Weld County, Colorado. The Newton 1-9H is the first Niobrara well permitted for 1,280-acre spacing in the Colorado portion of the play. The Company is planning to drill a 9,200-foot lateral section in the well, similar to the well design approach it is using in the North Dakota Bakken Shale play.

The Company is in the process of permitting additional Niobrara wells in northern Colorado and southern Wyoming. "If the results of the Newton 1-9H go as planned, we expect to spud additional Niobrara wells early in the second quarter next year," Mr. Hamm said.

Continental has 73,009 net acres leased in the Niobrara Shale play, with acreage in Weld County, Colorado and Platte, Laramie and Goshen counties, Wyoming.

Conference Call Information

Continental Resources will host a conference call on Thursday, November 4, 2010, at 10:00 a.m. ET (9 a.m. CT) to discuss its third quarter 2010 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) 713-4216


Intl. dial-in:

(617) 213-4868


Pass code:

60117799





Replay number:

(888) 286-8010


Intl. replay:

(617) 801-6888


Pass code:

59215224

Conference Presentations

Continental management is currently scheduled to present at the following research conferences:

Nov. 12

Bank of America Energy Conference, Miami

Nov. 17-18

Bank of America High Yield Conference, New York

Nov. 30

JP Morgan Oil & Gas Conference, Boston

Dec. 1

Jefferies &. Co. Energy Summit, Houston

Dec. 7

Raymond James Fall Investor Conference, Boston

Dec. 8

Wells Fargo Energy Symposium, New York

Dec. 8

Capital One Southcoast 5th Annual Energy Conference, New Orleans

Presentation materials will be available on the Company's web site on the day of each presentation.

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. 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. 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

Unaudited Condensed Consolidated Statements of Income


Three Months


Nine Months


Ended September 30,


Ended September 30,

In thousands, except per share data

2010



2009


2010



2009

Revenues:












Oil and natural gas sales

$

238,826


$

168,372


$

675,376


$

407,379

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


(24,183)



(2,105)



57,626



(1,215)

Oil and natural gas service operations


4,807



3,937



14,684



12,409

Total revenues


219,450



170,204



747,686



418,573













Operating costs and expenses:












Production expenses


24,857



22,719



69,806



69,183

Production taxes and other expenses


19,517



12,378



53,755



30,829

Exploration expenses


3,530



1,077



7,585



9,726

Oil and natural gas service operations


4,935



2,326



12,982



7,423

Depreciation, depletion, amortization and accretion


62,918



51,030



174,327



154,875

Property impairments


14,698



11,791



49,387



70,491

General and administrative expenses (1)


12,148



10,049



35,491



29,684

(Gain) loss on sale of assets


491



(452)



(32,855)



(673)

Total operating costs and expenses


143,094



110,918



370,478



371,538

Income from operations


76,356



59,286



377,208



47,035

Other income (expense):












Interest expense


(12,612)



(4,763)



(32,875)



(14,073)

Other


237



194



1,021



642



(12,375)



(4,569)



(31,854)



(13,431)

Income before income taxes


63,981



54,717



345,354



33,604

Provision for income taxes


24,904



19,788



132,071



11,780

Net income

$

39,077


$

34,929


$

213,283


$

21,824

Basic net income per share

$

0.23


$

0.21


$

1.26


$

0.13

Diluted net income per share

$

0.23


$

0.21


$

1.26


$

0.13

Basic weighted average shares outstanding


168,925



168,516



168,889



168,492

Diluted weighted average shares outstanding


169,949



169,706



169,904



169,399

(1) Includes non-cash charges for stock-based compensation of $2.6 million and $3.2 million for the three months ended September 30, 2010 and 2009, respectively, and $8.6 million for both the nine months ended September 30, 2010 and 2009.


Condensed Consolidated Balance Sheets

September 30

December 31

(in thousands)

2010

2009


(unaudited)


Assets:



Cash and cash equivalents

$149,477

$14,222

Receivables

376,328

183,358

Derivative assets

39,511

2,218

Inventories, prepaid expenses and other

37,366

36,230

Net property and equipment

2,703,867

2,068,055

Debt issuance costs, net

28,076

10,844

Total assets

$3,334,625

$2,314,927




Liabilities and shareholders' equity:



Current liabilities

$527,306

$219,710

Long-term debt

895,917

523,524

Other noncurrent liabilities

662,651

541,414

Shareholders' equity

1,248,751

1,030,279

Total liabilities and shareholders' equity

$3,334,625

$2,314,927



Unaudited Condensed Consolidated Statements of Cash Flows

Nine months ended

September 30,

(in thousands)

2010

2009




Net income

$213,283

$21,824

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



Non-cash expenses

292,026

255,831

Changes in assets and liabilities

(9,969)

(61,660)

Net cash provided by operating activities

495,340

215,995




Net cash used in investing activities

(708,953)

(375,421)




Net cash provided by financing activities

348,868

159,492







Net change in cash and cash equivalents

135,255

66

Cash and cash equivalents at beginning of period

14,222

5,229

Cash and cash equivalents at end of period

$149,477

$5,295


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 the Company's operating performance and compare the results of the Company's operations from period to period without regard to the Company's 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 the 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. The Company's 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. The revolving credit facility defines EBITDAX consistently with the definition of EBITDAX utilized and presented by the Company. The following table is a reconciliation of our net income to EBITDAX.



Three months


Nine months


ended September 30,


ended September 30,

in thousands

2010


2009


2010


2009

Net income

$

39,077


$

34,929


$

213,283


$

21,824

Interest expense


12,612



4,763



32,875



14,073

Provision for income taxes


24,904



19,788



132,071



11,780

Depreciation, depletion, amortization and accretion


62,918



51,030



174,327



154,875

Property impairments


14,698



11,791



49,387



70,491

Exploration expenses


3,530



1,077



7,585



9,726

Unrealized derivative (gain) loss


36,552



2,105



(28,162)



1,215

Non-cash equity compensation


2,626



3,172



8,596



8,594

EBITDAX

$

196,917


$

128,655


$

589,962


$

292,578


SOURCE Continental Resources

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