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Continental Resources Increases Daily Production 23 Percent in Third Quarter 2011 Compared With Second Quarter 2011

Successful Charlotte 2-22H Well in North Dakota Indicates Additional, Deeper Three Forks Potential
Company Reports $337.8 Million in EBITDAX and $439.1 Million in Net Income
$1.75 Billion Budgeted for 2012 Capital Expenditures

ENID, Okla., Nov. 2, 2011 /PRNewswire via COMTEX/ --

Continental Resources, Inc. (NYSE: CLR) today reported average production of 66,289 barrels of oil equivalent per day (Boepd) for the third quarter ended September 30, 2011. This was 23 percent higher than production of 53,984 Boepd for the second quarter of 2011 and 48 percent higher than production for the third quarter of 2010.

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

Total production growth from the second quarter of 2011 to the third quarter this year included:

  • 27 percent growth to 34,505 Boepd in the Bakken play of North Dakota and Montana from the second quarter consecutively to the third quarter of 2011;
  • 78 percent consecutive quarter growth to 7,164 Boepd in the Oklahoma Anadarko Woodford; and
  • Four percent consecutive quarter growth to 14,954 Boepd in the Red River Units of Montana, North Dakota and South Dakota.

Continental reported third quarter 2011 net income of $439.1 million, or $2.44 per diluted share, compared with $39.1 million, or $0.23 per diluted share, in net income for the third quarter of 2010.

Third quarter 2011 net income reflected the effects of an after-tax unrealized gain of $332.5 million on mark-to-market derivative instruments and an after-tax charge of $16.3 million for property impairments. Third quarter 2011 earnings were increased by $1.76 per diluted share by the combined effect of the non-cash, unrealized derivatives gain less the impairments charge.

The Company reported EBITDAX of $337.8 million for the third quarter of 2011, a 72 percent increase over EBITDAX of $196.9 million for the third quarter of 2010. For the Company's definition and reconciliation of EBITDAX to net income, see "Non-GAAP Financial Measures" at the end of this press release.

The Company successfully completed the Charlotte 2-22H (91% WI) in McKenzie County, North Dakota, in October 2011, with the well producing 1,140 gross Boepd in its initial one-day test period. This is the Company's first horizontal test of a deeper bench in the Three Forks formation.

"We're very pleased with such a solid well in our first test of the lower benches of the Three Forks," said Harold Hamm, Chairman and Chief Executive Officer.

Continental is a pioneer in developing the Three Forks formation, initially targeting the first bench of the Three Forks approximately 20 feet below the Lower Bakken Shale in mid-2008. In 2011 Continental expanded its evaluation of the Three Forks by acquiring six cores of the entire vertical thickness of the formation over a distance of 115 miles north to south. The cores revealed that the Three Forks formation, which ranges from 180 feet to 270 feet thick under the Company's acreage, contains up to four separate benches of dolomite that contain oil.

"The Charlotte 2-22H was drilled horizontally in the second bench, approximately 50 feet below a typical first-bench horizontal well," Mr. Hamm said. "This successful test demonstrates that the Three Forks second bench has the potential to add incremental reserves to our estimated 24 billion Boe of technically recoverable oil and natural gas in the total Bakken."

Today Continental also announced a $1.75 billion capital expenditures budget for 2012, which is expected to yield production growth in a range of 26 percent to 28 percent. The 2012 capital expenditure budget is less than the Company plans to spend in 2011, reflecting a slightly lower growth rate next year as North Dakota builds infrastructure to cope with the demands of accelerated drilling in the Bakken play since mid-2009. Continental also plans to spend less on new lease acquisitions in 2012 than it has in 2011.

"Superior rates of return in the Bakken are the key to our 2012 drilling program and production growth," Mr. Hamm said. "Our rate of return in the Bakken currently ranges from 40-to-50 percent, based on an average well cost of $8 million and our current estimated ultimate recovery of 603,000 Boe per well. The Bakken remains the focus of our growth plan.

"Our key operating focus is improved drilling and completion efficiencies," he said.

"Looking ahead, we are solidly on track to achieve our goal of tripling production and proved reserves from year-end 2009 to year-end 2014."

Operating and Financial Highlights

Crude oil and natural gas sales were $423.9 million for the third quarter of 2011, a 77 percent increase over sales of $238.8 million for the third quarter of 2010.

Crude oil accounted for 72 percent of Continental's third quarter 2011 production. The Company's average realized crude oil price was $84.02 per barrel for the third quarter of 2011, while the average realized natural gas price was $5.50 per Mcf, yielding a blended realized price of $69.57 per Boe. In the third quarter of 2010, the Company realized a blended price of $56.92 per Boe.

The Company's crude oil price differential was $5.62 per barrel below West Texas Intermediate for the third quarter of 2011, compared with $8.93 per barrel in the third quarter of 2010. A significant portion of its oil production is being delivered to premium-priced markets instead of Cushing, Oklahoma.

Continental's third quarter 2011 natural gas price differential was a premium of $1.30 per Mcf, reflecting the high liquids and BTU content in Anadarko Woodford and Bakken natural gas. In the third quarter of 2010, the Company's average gas differential was a negative $0.08 per Mcf.

During the third quarter of 2011, the Company's capital expenditures were $541 million, bringing its nine-month 2011 total capital expenditures to $1.4 billion.

As of September 30, 2011, the Company's balance sheet included $42.3 million in cash and $896 million in long-term debt. At October 31, 2011, the Company had $750 million committed under its revolving credit facility, with available borrowing capacity of $617.2 million. The Company's borrowing base is $2.25 billion.

Operating Highlights




Three months ended September 30,


Nine months ended September 30,



2011


2010


2011


2010


Average daily production:













Crude oil (Bbl per day)


47,552



33,432



42,160



31,404


Natural gas (Mcf per day)


112,423



68,057



91,231



61,948


Crude oil equivalents (Boe per day)


66,289



44,775



57,365



41,728


Average sales prices: (1)













Crude oil ($/Bbl)

$

84.02


$

67.26


$

88.19


$

68.92


Natural gas ($/Mcf)


5.50



4.28



5.37



4.63


Crude oil equivalents ($/Boe)


69.57



56.92



73.25



58.82


Production expenses ($/Boe) (1)


5.98



5.92



6.31



6.08


General and administrative expenses ($/Boe) (1) (2)


2.98



2.90



3.32



3.09


Net income (in thousands)


439,143



39,077



541,136



213,283


Diluted net income per share


2.44



0.23



3.05



1.26


EBITDAX (in thousands) (3)


337,754



196,917



892,040



589,962

(1)

Average sales prices and per unit expenses have been calculated using sales volumes and exclude any effect of derivative transactions.

(2)

General and administrative expense ($/Boe) includes non-cash equity compensation expense of $0.70 per Boe and $0.63 per Boe for the three months ended September 30, 2011 and 2010, respectively, and $0.76 per Boe and $0.75 per Boe for the nine months ended September 30, 2011 and 2010, respectively.

(3)

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. A reconciliation of net income to EBITDAX is provided subsequently under the header Non-GAAP Financial Measures.

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





3Q


2Q


3Q


Boe per day


2011


2011


2010


North Region:








North Dakota Bakken


28,987


21,682


15,062


Montana Bakken


5,518


5,495


4,891


Red River Units


14,954


14,328


14,167


Other


1,052


1,024


993










South Region:








Anadarko Woodford


7,164


4,031


1,377


Arkoma Woodford


4,099


3,236


4,413


Other


3,387


3,118


2,640


East Region


1,128


1,070


1,232


Total


66,289


53,984


44,775

Bakken Production Increases

Continental's Bakken production of 34,505 Boepd in the third quarter of 2011 was 27 percent higher than production of 27,177 Boepd in the second quarter of 2011 and 73 percent higher than Bakken production of 19,953 Boepd in the third quarter of 2010.

Third quarter 2011 Bakken production accounted for 52 percent of Continental's total production in the period, compared with 45 percent in the third quarter of 2010.

Continental participated in the completion of 83 gross (28.5 net) wells in the Bakken in the third quarter of 2011.

In terms of Company-operated wells, Continental completed 46 gross (24.5 net) wells in the Bakken in the third quarter. Average initial one-day test period production was 1,096 Boepd for the Company's operated wells in the third quarter. The Company currently has 45 gross operated wells in various stages of completion. Of these, 20 are scheduled to be fracture-stimulated, and 25 have been fracked and are being readied to go into production.

Continental previously reported individual well highlights for its third quarter 2011 in a press release issued on October 7, 2011.

Continental's standard well fracture-stimulation design is 30 stages, but varies according to local geology. The Company recently fracked a well with 40 stages.

Continental's Bakken lease position was 901,098 net acres at September 30, 2011, with 72 percent of its acreage in the North Dakota portion of the play. Sixty-eight percent of the Company's Bakken net acreage is undeveloped.

The Company has 23 operated drilling rigs in the Bakken - 21 in North Dakota and two in Montana - and four dedicated crews performing hydraulic fracturing services. The Company plans to add back a fifth crew later this month.

Oklahoma Woodford

Third quarter 2011 production in the Anadarko Woodford was 7,164 Boepd, a 78 percent increase over production of 4,031 Boepd in the second quarter of 2011. The Company's production was 1,377 Boepd in the third quarter of 2010. The Company participated in completing 31 gross (13.5 net) wells during the third quarter of 2011. Of these wells, 15 gross (10.3 net) were Company-operated completions.

Continental successfully completed and is flowing back the Lyle 1-30H (99% WI) in Grady County, with initial oil and gas production expected to start shortly. The Lyle is an offset to and confirmation test for the Lambakis 1-11H (98% WI). The Company expects to announce initial test production results on the Lyle 1-30H by year end.

The Lambakis 1-11H flowed 5.4 MMcfpd of natural gas and 160 Bopd in its initial one-day test period, as announced in August 2011. Continental projects it has an estimated ultimate recovery (EUR) of more than 8 Bcfe, or 1.33 million Boe, due to its high liquids production. The Lambakis is especially significant due to its location 25 miles south of previously known horizontal Woodford production.

The Company is preparing to spud the Tom's 1-21XH (82% WI) in Blaine County, which will be the first multiple-unit spaced well drilled in Oklahoma. The horizontal section of the Tom's well is planned to be twice the length of previous Anadarko Woodford wells drilled in the play. Continental expects longer laterals will have a significant, positive impact on well productivity and economics in the Anadarko Woodford. The Company expects to complete the Tom's well in the first quarter of 2012.

Using 3-D seismic, Continental has already identified 48 potential multi-unit drilling opportunities in the play and continues to acquire 3-D seismic over additional prospective areas.

Third quarter production in the Arkoma Woodford was 4,099 Boepd, compared with 3,236 Boepd in the second quarter of 2011. The Company participated in completing three gross (1.6 net) wells in the Arkoma, including the Ward 1-33H (88% WI), which flowed at 4.7 MMcfpd in its initial test period.

Continental currently has 14 operated rigs in the Oklahoma Woodford, with 11 in the Northwest Cana portion of the Anadarko Woodford, two in Southeast Cana, and one in the Arkoma Woodford.

The Company has 330,540 net acres leased in the Oklahoma Woodford, including 275,605 net acres in the Anadarko portion of the play, where it continues to acquire acreage.

Red River Units

The Company's production in the Red River Units averaged 14,954 Boepd in the third quarter of 2011, an increase of four percent over second quarter 2011 production of 14,328 Boepd and six percent over production of 14,167 Boepd for the third quarter of 2010. Continental has a one-rig drilling program in the enhanced oil-recovery units.

"Our team in the Units continues to do an outstanding job extending the peak performance life of this field, primarily by increasing our water and air injection capabilities and taking other measures to optimize production in the field," Mr. Hamm said.

Niobrara

Continental is currently completing its second and third Niobrara test wells in Weld County, Colorado. The two are designed to test a high resistivity, porous chalk fairway in the play, where the Company has approximately 25,000 net acres.

The Marconi 1-1H (62% WI) is being completed on 1,280-acre spacing and is located 12 miles south of the Company's initial test well. The Perrin 1-10H (51% WI) was drilled on 640-acre spacing two miles west of the Marconi.

Continental has a total of 90,293 net acres leased in the DJ Basin-Niobrara.

2012 Capital Expenditures and Production Guidance

For 2012, 93 percent of the Company's $1.75 billion capital expenditures budget is allocated to drilling operations, which includes facilities and work-overs. The majority of capex will be devoted to the Bakken play.

The Company plans to participate in 759 gross (249 net) wells, including 126 net wells in the Bakken and 46 net wells in the Anadarko Woodford. Continental plans to operate an average of 40 drilling rigs in 2012, with 24 of these rigs in the Bakken, 10 rigs in the Anadarko Woodford and six rigs in the Niobrara, Red River Units and other domestic plays.

Continental's 2012 operating guidance includes the following:

Production growth

26% to 28%

Price differentials:


WTI crude oil (Bo)

$7 to $9

Henry Hub natural gas (Mcf)

+$1.00 to +$1.50

Operating expenses per Boe:


Production expense

$6 to $7

Production tax

8% to 8.75%

DD&A per Boe

$17 to $20

G&A per Boe(1)

$2.50 to $2.75

Non-cash compensation per Boe

$0.70 to $0.90

Income tax rate

38%

Deferred taxes

90% to 95%

(1) Excludes an estimated $15 million to $25 million associated with relocation of headquarters, and excludes non-cash stock-based compensation.

Conference Call Information

Continental Resources plans to host its third quarter 2011 earnings conference call on Thursday, November 3, 2011, at 10 a.m. ET. Those wishing to listen to the 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, November 3, 2011

Dial in:

888-679-8038

Intl. dial in:

617-213-4850

Pass code:

49494581



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:

99185698

Conference Presentations

Continental management is currently scheduled to present on November 15, 2011, at the 2011 Bank of America Energy Conference in Miami.

Other research conferences at which the Company plans to present include:

Jefferies Global Energy Summit, Houston, Nov. 30

Bank of America Merrill Lynch Leveraged Finance Conference, Orlando, Dec. 2

J.P. Morgan Oil and Gas Day, Boston, Dec. 6

Capital One Southcoast Securities Annual Energy Conference, New Orleans, Dec. 7

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 and enhanced recovery technologies provide the means to economically develop and produce oil and natural gas reserves in U.S. resource plays.

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 the plans, intentions and expectations reflected in or suggested by the forward-looking statements are reasonable, there is no assurance 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

Kristin Miskovsky, VP Public Relations


(580) 548-5127

(405) 234-9480


warrenhenry@contres.com

kristinmiskovsky@contres.com

Unaudited Condensed Consolidated Statements of Income




Three months ended September 30,


Nine months ended September 30,



2011


2010


2011


2010

Revenues:


In thousands, except per share data

Crude oil and natural gas sales


$

423,859


$

238,826


$

1,139,110


$

675,376

Gain (loss) on derivative instruments, net



537,340



(24,183)



372,490



57,626

Crude oil and natural gas service operations



7,790



4,807



24,071



14,684

Total revenues



968,989



219,450



1,535,671



747,686














Operating costs and expenses:













Production expenses



36,459



24,857



98,090



69,806

Production taxes and other expenses



39,262



19,517



100,315



53,755

Exploration expenses



9,814



3,530



21,660



7,585

Crude oil and natural gas service operations



6,198



4,935



19,713



12,982

Depreciation, depletion, amortization and accretion



105,085



62,918



264,236



174,327

Property impairments



26,225



14,698



66,315



49,387

General and administrative expenses (1)



18,140



12,148



51,696



35,491

(Gain) loss on sale of assets



188



491



(15,387)



(32,855)

Total operating costs and expenses



241,371



143,094



606,638



370,478

Income from operations



727,618



76,356



929,033



377,208

Other income (expense):













Interest expense



(18,981)



(12,612)



(56,737)



(32,875)

Other



994



237



2,525



1,021




(17,987)



(12,375)



(54,212)



(31,854)

Income before income taxes



709,631



63,981



874,821



345,354

Provision for income taxes



270,488



24,904



333,685



132,071

Net income


$

439,143


$

39,077


$

541,136


$

213,283

Basic net income per share


$

2.45


$

0.23


$

3.06


$

1.26

Diluted net income per share


$

2.44


$

0.23


$

3.05


$

1.26





(1)

Includes non-cash charges for stock-based compensation of $4.2 million and $2.6 million for the three months ended September 30, 2011 and 2010, respectively, and $11.7 million and $8.6 million for the nine months ended September 30, 2011 and 2010, respectively.

Condensed Consolidated Balance Sheets



September 30,


December 31,


2011


2010


(Unaudited)



Assets

In thousands

Current assets

$

907,824


$

582,326

Net property and equipment


4,046,235



2,981,991

Other noncurrent assets


145,518



27,468

Total assets

$

5,099,577


$

3,591,785







Liabilities and shareholders' equity






Current liabilities

$

880,727


$

702,222

Long-term debt


896,220



925,991

Other noncurrent liabilities


904,012



755,417

Total shareholders' equity


2,418,618



1,208,155

Total liabilities and shareholders' equity

$

5,099,577


$

3,591,785

Unaudited Condensed Consolidated Statements of Cash Flows



Nine months ended September 30,


2011


2010


In thousands

Net income

$

541,136


$

213,283

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






Non-cash expenses


256,392



292,026

Changes in assets and liabilities


(127,714)



(9,969)

Net cash provided by operating activities


669,814



495,340







Net cash used in investing activities


(1,263,139)



(708,953)







Net cash provided by financing activities


627,684



348,868







Net change in cash and cash equivalents


34,359



135,255

Cash and cash equivalents at beginning of period


7,916



14,222

Cash and cash equivalents at end of period

$

42,275


$

149,477

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 us 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 ended September 30,


Nine months ended September 30,




2011


2010


2011


2010




in thousands


in thousands


Net income


$

439,143


$

39,077


$

541,136


$

213,283


Interest expense



18,981



12,612



56,737



32,875


Provision for income taxes



270,488



24,904



333,685



132,071


Depreciation, depletion, amortization and accretion



105,085



62,918



264,236



174,327


Property impairments



26,225



14,698



66,315



49,387


Exploration expenses



9,814



3,530



21,660



7,585


Unrealized (gains) losses on derivatives



(536,227)



36,552



(403,471)



(28,162)


Non-cash equity compensation



4,245



2,626



11,742



8,596


EBITDAX


$

337,754


$

196,917


$

892,040


$

589,962

SOURCE Continental Resources, Inc.

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