Continental Resources, Inc.

has added a news release to its Investor Relations website. Title: Continental Resources Increases Daily Production 23 Percent in Third Quarter 2011 Compared With Second Quarter 2011 Date(s): 2-Nov-2011 8:39 PM For a complete listing of our news releases, please click here
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 Companys 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 Companys first horizontal test of a deeper bench in the Three Forks formation. "Were 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 Companys 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 Continentals third quarter 2011 production.

The Companys 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 Companys 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. Continentals 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 Companys average gas differential was a negative $0.08 per Mcf. During the third quarter of 2011, the Companys capital expenditures were $541 million, bringing its nine-month 2011 total capital expenditures to $1.4 billion. As of September 30, 2011, the Companys 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 Companys 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 Companys 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 Continentals 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 Continentals 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 Companys 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. Continentals standard well fracture-stimulation design is 30 stages, but varies according to local geology.

The Company recently fracked a well with 40 stages. Continentals 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 Companys 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 Companys 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 Toms 1-21XH (82% WI) in Blaine County, which will be the first multiple-unit spaced well drilled in Oklahoma.

The horizontal section of the Toms 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 Toms 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 Companys 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 Companys 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 Companys $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. Continentals 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 Companys 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 Companys 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 Companys 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 Companys 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
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 companys operating performance or liquidity.

Certain items excluded from EBITDAX are significant components in understanding and assessing a companys financial performance, such as a companys 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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