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Continental Resources Reports Increased Production, Net Income and EBITDAX for the Second Quarter of 2011


Company Raises North Dakota Bakken Well Model to 603,000 Boe
Lambakis 1-11H Discovery Well Extends Oklahoma Anadarko Woodford Play by 25 Miles
Mid-Year Proved Reserves of 421 Million Boe Are 15 Percent Higher Than YE2010
Company Planning to Test Deeper Three Forks Objective in the Bakken
Continental Increases 2011 Capital Expenditure and Production Guidance

ENID, Okla., Aug. 3, 2011 /PRNewswire via COMTEX/ -- Continental Resources, Inc. (NYSE: CLR) today announced strong growth in production, net income and EBITDAX for the second quarter ended June 30, 2011.

Continental grew production 29 percent to 53,984 Boepd (barrels of oil equivalent per day) in the second quarter, compared with 41,913 Boepd in the second quarter of 2010. The second quarter 2011 gain was accomplished while overcoming weather-related challenges in North Dakota.

The Company accelerated production growth since early June. Continental estimated that July 2011 production was 61,000 net Boepd and that it averaged 62,000 Boepd in the last seven days of July.

"We've regained our momentum, as evidenced by production of 61,000 Boepd in July," said Harold Hamm, Chairman and Chief Executive Officer. "Our Bakken team and vendors did a tremendous job in May and June adapting to road closings and building gathering systems to ship oil and natural gas directly from completed well sites."

Continental currently has 46 gross (25 net) Bakken operated wells waiting to be completed or in the completion stage. This is approximately 50 percent more than normal levels and reflects deferred production due to abnormal weather in the second quarter.

Net income was $239.2 million, or $1.33 per diluted share, for the second quarter of 2011, an increase of 135 percent over net income for the second quarter of 2010.

The Company's second quarter 2011 net income reflected an after-tax unrealized gain on mark-to-market derivative instruments of $143.4 million and an after-tax $11.9 million property impairments charge. Second quarter 2011 earnings were increased by $0.73 per diluted share by the combined effects of the non-cash, unrealized derivatives gain, the impairments charge and a small gain on sale of assets.

The Company reported EBITDAX of $285.6 million for the second quarter of 2011, a 31 percent increase over EBITDAX for the second 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.

Based on well performance over the last 12 months, Mr. Hamm said the Company has increased its estimated ultimate recovery model to 603,000 Boe per well in the North Dakota Bakken, compared with the previous EUR model of 518,000 Boe.

"Like all world-class oil plays, the Bakken just keeps getting better," he said. "This higher EUR per well reflects technical advances in well completion and the quality of our acreage."

Continental also announced a significant exploratory well completion in its Southeast Cana project in the Oklahoma Anadarko Woodford. The Lambakis 1-11H (98% WI) was completed flowing 5.4 MMcfpd of natural gas and 160 Bopd in its initial one-day test period. The Lambakis 1-11H is located 25 miles south of previously known horizontal Woodford production. The Company has already begun drilling an offset well to the Lambakis and plans to add additional drilling rigs to the Southeast Cana by year-end 2011.

"The Lambakis 1-11H is a strong well that validates our geologic model for the Southeast Cana," Mr. Hamm said. "Southeast Cana accounts for a third of our 270,000 net acres in the Anadarko Woodford."

Proved Reserves Increase to 421 Million Boe

Continental announced a 15 percent increase in proved reserves to 421 MMBoe at June 30, 2011, based on its internal evaluation. This compared with the total proved reserves of 365 MMBoe at year-end 2010. The increase in the first half of 2011 resulted from extensive drilling activity in the Bakken and Anadarko Woodford plays.

The mid-year report was prepared based on 12-month unweighted average prices of $90.09 per barrel for oil and $4.21 per Mcf for natural gas, and further adjusted for location differentials. This compares to $79.43 per barrel for oil and $4.38 per Mcf for gas for the Company's year-end 2010 reserve report.

Operating and Financial Highlights

Crude oil and natural gas sales were $388.8 million for the second quarter of 2011, a 77 percent increase over sales of $219.4 million for the second quarter of 2010.

Crude oil accounted for 75 percent of Continental's second quarter 2011 production. The Company's average realized crude oil price was $95.88 per barrel for the second quarter of 2011, while the average realized natural gas price was $5.47 per Mcf, yielding a blended realized price of $79.86 per Boe. In the second quarter of 2010, the Company realized a blended price of $57.94 per Boe.

The Company's crude oil price differential was $6.59 per barrel for the second quarter of 2011, and its natural gas price differential was a premium of $1.16 per Mcf, reflecting the high liquids and BTU content in Anadarko Woodford and Bakken natural gas.

During the second quarter of 2011, the Company's capital expenditures were $455.7 million, bringing its mid-year total to $868.5 million.

As of June 30, 2011, the Company's balance sheet included $261.4 million in cash and $896.1 million in long-term debt. At the end of the second quarter of 2011, the Company had $747.6 million of borrowing capacity available under its revolving credit facility.

The Company's borrowing base was redetermined and increased to $2.0 billion in the second quarter of 2011, compared with the previous base of $1.5 billion. The Company elected to retain commitments under the facility at $750 million.

Operating Highlights







Three months ended June 30,


Six months ended June 30,


2011


2010


2011


2010

Average daily production:












Crude oil (Bbl per day)


40,382



31,611



39,420



30,373

Natural gas (Mcf per day)


81,609



61,815



80,459



58,844

Crude oil equivalents (Boe per day)


53,984



41,913



52,830



40,180

Average sales prices: (1)












Crude oil ($/Bbl)

$

95.88


$

68.44


$

90.78


$

69.87

Natural gas ($/Mcf)


5.47



4.33



5.29



4.84

Crude oil equivalents ($/Boe)


79.86



57.94



75.63



59.92

Production expenses ($/Boe) (1)


6.65



5.90



6.52



6.17

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

3.53



3.03



3.55



3.20

Net income (in thousands)


239,194



101,741



101,993



174,206

Diluted net income per share


1.33



0.60



0.58



1.03

EBITDAX (in thousands)(3)


285,631



217,462



554,286



393,045













(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 $0.79 per Boe and $0.82 per Boe for the three and six months ended June 30, 2011 and 2010.


(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 production by region for the periods presented.



2Q


1Q


2Q

Boe per day


2011


2011


2010

North Region:







North Dakota Bakken


21,682


20,238


13,046

Montana Bakken


5,495


5,285


4,939

Red River Units


14,328


14,066


14,281

Other


1,024


1,072


1,056








South Region:







Anadarko Woodford


4,031


2,685


1,079

Arkoma Woodford


3,236


4,065


3,721

Other


3,118


3,097


2,617

East Region


1,070


1,155


1,174

Total


53,984


51,663


41,913

Bakken Production Increases

Continental's total Bakken production increased to 27,177 Boepd in the second quarter of 2011, six percent higher than production of 25,523 Boepd in the first quarter of 2011 and 51 percent higher than Bakken production in the second quarter of 2010. Bakken production accounted for half of Continental's total production in the second quarter of 2011.

Continental participated in the completion of 78 gross (21.9 net) wells in the Bakken in the second quarter of 2011.

In terms of Company-operated wells, Continental completed 34 gross (18.2 net) wells in the Bakken in the second quarter. Average initial one-day test period production was 1,188 Boepd for the Company's operated wells in the second quarter in the Bakken.

Notable Company-operated wells in North Dakota (with initial one-day test period gross production results) included:

  • Carson Peak 2-35H (39% WI) in Dunn Co. - 2,239 Boepd;
  • Carson Peak 3-35H (39% WI) in Dunn Co. - 2,237 Boepd;
  • Morris 3-26H (39% WI) in Dunn Co. - 1,917 Boepd;
  • Don 1-23H (47% WI) in McKenzie Co. - 1,680 Boepd;
  • Vardon 1-14H (42% WI) in McKenzie Co. - 1,550 Boepd;
  • Winston 1-12H (64% WI) in Williams Co. - 1,525 Boepd;
  • Pittsburgh 1-19H (95% WI) in McKenzie Co. - 1,504 Boepd;
  • Dolezal 2-5H (50% WI) in Dunn Co. - 1,456 Boepd;
  • Akron 1-27H (74% WI) in McKenzie Co. - 1,407 Boepd;
  • Morris 2-26H (39% WI) in Dunn Co. - 1,400 Boepd;
  • Nordeng 1-8H (53% WI) in McKenzie Co. - 1,400 Boepd; and
  • Chicago 1-26H (44% WI) in McKenzie Co. - 1,395 Boepd.

In late July, an additional North Dakota Bakken completion of note was the Debrecen 1-3H (39% WI) completed in Stark County. The Debrecen 1-3H targeted the Three Forks zone and tested in early production at 1,667 Boepd, flowing at 2,052 psi on a 24 choke. It is Continental's strongest well to date in the Normandy prospect.

"This is a key test that sets up accelerated drilling activity in future years," Mr. Hamm said. The Company has 103,334 net acres in Normandy, which covers parts of Billings, Dunn, McKenzie and Stark counties.

In the Montana Bakken, notable second quarter completions included the Earl 2-25H (40% WI), which produced 1,024 Boepd in its initial test period, and the David 2-20H (77% WI), which produced 831 Boepd. Both wells are located in Richland County.

The Company is currently drilling a North Dakota Bakken horizontal well to test the productivity of a deeper oil-bearing zone in the Three Forks formation. Five cores taken by the Company across the play reveal several oil-saturated dolomitic layers in the Three Forks as much as 220 feet below the bottom of the Lower Bakken shale. "Evidence from the cores indicates the potential for incremental reserves in the Three Forks," Mr. Hamm said.

Continental's Bakken lease position has grown to 901,370 net acres at June 30, 2011, with 72 percent of its acreage in the North Dakota portion of the play.

The Company has 23 operated drilling rigs in the Bakken - 21 in North Dakota and two in Montana - and five dedicated crews performing hydraulic fracturing services. The Company plans to replace a rig it recently lost in North Dakota, and plans to increase further its operated rigs in the Bakken in early 2012.

Oklahoma Anadarko Woodford Extended South

Continental's Lambakis 1-11H validates the Company's geologic model for the Southeast Cana and extends it 25 miles south of previously known Anadarko Woodford horizontal production. The Lambakis proves up an additional 15,000 net acres in the southern part of the 90,000 net acre Southeast Cana.

The well is producing 1350 Btu gas, which in May had a realized price of $6.25 per MMcf, compared with NYMEX's posted price of $3.95. It has been producing since late May and continues to flow at 4.2 MMcfpd and 110 Bopd, showing a shallow decline curve.

The Lambakis' lateral section was completed in 10 stages over a total length of 4,200 feet at a true vertical depth of 15,000 feet. The lateral was landed in a siliceous zone, which in the southern portion of the Southeast Cana is very thick and may present multiple horizons for drilling.

Continental's second quarter 2011 production in the Anadarko Woodford was 4,031 Boepd, a 50 percent increase over production in the first quarter of 2011. The Company participated in completing 28 gross (9.9 net) wells during the second quarter of 2011. Of these wells, 11 gross (7.6 net) were Company-operated well completions.

Other notable Company-operated wells in the Anadarko Woodford in the second quarter of 2011 (with initial one-day test period gross production results) included:

  • Wray 1-1H (46% WI) in Blaine Co. - 6.3 MMcfpd and 53 Bopd;
  • Barnett 1-5H (54% WI) in Blaine Co. - 6.1 MMcfpd and 10 Bopd;
  • Elias 1-12H (58% WI) in Blaine Co. - 4.2 MMcfpd and 60 Bopd;
  • Ruble 1-12H (62% WI) in Dewey Co. - 3.9 MMcfpd and 70 Bopd; and
  • Trook 1-1H (66% WI) in Dewey Co. - 2.1 MMcfpd and 165 Bopd.

In July 2011, Continental completed the Cromwell 1-1H (97% WI) in Custer County, flowing 4.5 MMcfpd and 63 Bopd in its initial one-day test period. The Justice 1-15H (59% WI) was also completed in Blaine County, flowing 4.3 MMcfpd and 20 Bopd in its initial test period.

The Company noted that Anadarko Woodford drilling times continue to improve, with several Company-operated wells being drilled in approximately 40 days each, 43 percent faster than the 2010 average.

Continental currently has 14 operated rigs in the Oklahoma Woodford, with 11 in Northwest Cana, two in Southeast Cana, and a single rig in the Arkoma Woodford. It plans to increase its operated rig count in the Anadarko Woodford by year-end.

The Company has 324,273 net acres leased in the Oklahoma Woodford, including 270,529 net acres in the Anadarko Woodford portion of the play, where it continues to acquire acreage.

Red River Units

The Company's production in the Red River Units averaged 14,328 Boepd in the second quarter of 2011, a two percent increase over first quarter 2011 production. The increased production reflects the ongoing one-rig drilling program and production optimization in these enhanced oil-recovery units.

"Our team working in the Red River Units is doing a tremendous job of enhancing the value of this legacy field," Mr. Hamm said.

Niobrara

During the second quarter of 2011, Continental completed the Newton 1-4H (89% WI) in Weld County, Colorado. Initial production results were below expectations. "The well confirmed in our minds that the Niobrara is a matrix-driven play, and productive areas can be identified on that basis," Mr. Hamm said. The Company plans to drill in mid-August its second Niobrara well approximately 12 miles south of the Newton 1-4H, where industry activity has demonstrated economic results.

Continental has 83,100 net acres leased in the DJ Basin-Niobrara.

2011 Guidance: Capital Expenditures and Production Increased

Continental has increased its 2011 capital expenditures budget to $2.0 billion and expects full-year 2011 production growth in a range of 36 percent to 39 percent. The Company's previous guidance was for a capex budget of $1.75 billion and production growth of 35 percent to 37 percent.

Of the $250 million increase in the revised budget, 86 percent is allocated to drilling operations and the rest to strategic lease acquisition and conventional leasing activity. Strategic acquisitions included 9,300 net acres in the North Dakota Bakken in the second quarter of 2011. "We continue to pursue additional acreage in the Bakken and Anadarko Woodford plays," Mr. Hamm said.

The additional capital expenditures this year reflect additional drilling rigs deployed and additional frac stages per well, which together will impact production growth primarily in 2012.

The Company noted the following factors contributed to the new guidance:

  • Its standard completion design for North Dakota Bakken wells is now 30 stages, compared with the previous 24, yielding an average cost of $8.0 million per well;
  • The Company is expanding its drilling program in the Anadarko Woodford, taking four rigs from another operator in the play for the next six months;
  • Continental will construct an increased number of Bakken pre-built drilling sites in the second half of 2011 prior to the onset of winter weather, and additional capex has been allocated for non-operated drilling activity;
  • The revised budget includes Bakken lease activity and the purchase of the Company's new headquarters building in Oklahoma City; and
  • Strengthened well results in the Bakken and Anadarko Woodford have increased the Company's anticipated production growth rate.

Based on the revised budget, the Company expects to exit 2011 with approximately $250 million drawn on its revolving credit facility and with a low debt-to-EBITDAX ratio, compared to its peers.

Conference Call Information

Continental Resources plans to host its second quarter 2011 earnings conference call on Thursday, August 4, 2011, at 10 a.m. ET. Those wishing to listen to the call may do so via the Company's web site at http://www.contres.com/ or by phone:

Dial in:

888 713-4218

Intl dial in:

617 213-4870

Pass code:

97913800

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

Replay number:

888 286-8010

Intl. replay:

617 801-6888

Pass code:

81452084

Conference Presentations

Continental management is currently scheduled to present Monday, August 15, at the 2011 ENERCOM Oil & Gas Conference in Denver. Presentation materials will be available on the Company's web site on the day of the 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

Brian Engel, VP Public Affairs


(580) 548-5127

(405) 605-0784

Unaudited Condensed Consolidated Statements of Income






Three months ended June 30,


Six months ended June 30,


2011


2010


2011


2010

Revenues:

In thousands, except per share data

Crude oil and natural gas sales

$

388,784


$

219,426


$

715,251


$

436,550

Gain (loss) on derivative instruments, net


204,453



55,465



(164,850)



81,809

Crude oil and natural gas service operations


9,655



5,077



16,281



9,877

Total revenues


602,892



279,968



566,682



528,236













Operating costs and expenses:












Production expenses


32,361



22,348



61,631



44,949

Production taxes and other expenses


33,491



18,231



61,053



34,238

Exploration expenses


5,034



2,269



11,846



4,055

Crude oil and natural gas service operations


8,064



4,091



13,515



8,047

Depreciation, depletion, amortization and accretion


83,501



58,822



159,151



111,409

Property impairments


19,242



19,514



40,090



34,689

General and administrative expenses(1)


17,209



11,494



33,556



23,343

Gain on sale of assets


(318)



(33,124)



(15,575)



(33,346)

Total operating costs and expenses


198,584



103,645



365,267



227,384

Income from operations


404,308



176,323



201,415



300,852

Other income (expense):












Interest expense


(18,785)



(11,903)



(37,756)



(20,263)

Other


1,022



78



1,531



784



(17,763)



(11,825)



(36,225)



(19,479)

Income before income taxes


386,545



164,498



165,190



281,373

Provision for income taxes


147,351



62,757



63,197



107,167

Net income

$

239,194


$

101,741


$

101,993


$

174,206

Basic net income per share

$

1.33


$

0.60


$

0.58


$

1.03

Diluted net income per share

$

1.33


$

0.60


$

0.58


$

1.03













(1) Includes non-cash charges for stock-based compensation of $3.9 million and $3.1 million for the three months ended June 30, 2011 and 2010, respectively, and $7.5 million and $6.0 million for the six months ended June 30, 2011 and 2010, respectively.

Condensed Consolidated Balance Sheets






June 30,


December 31,


2011


2010

Assets

(Unaudited)




In thousands

Current assets

$

991,501


$

582,326

Net property and equipment


3,635,046



2,981,991

Debt issuance costs and other assets


25,824



27,468

Total assets

$

4,652,371


$

3,591,785







Liabilities and shareholders' equity






Current liabilities

$

858,556


$

702,222

Long-term debt


896,141



925,991

Other noncurrent liabilities


921,986



755,417

Total shareholders' equity


1,975,688



1,208,155

Total liabilities and shareholders' equity

$

4,652,371


$

3,591,785

Unaudited Condensed Consolidated Statements of Cash Flows




Six months ended June 30,


2011


2010


In thousands

Net income

$

101,993


$

174,206

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






Non-cash expenses


393,358



152,671

Changes in assets and liabilities


(66,385)



63,348

Net cash provided by operating activities


428,966



390,225







Net cash used in investing activities


(803,616)



(462,564)







Net cash provided by financing activities


628,142



73,349







Net change in cash and cash equivalents


253,492



1,010

Cash and cash equivalents at beginning of period


7,916



14,222

Cash and cash equivalents at end of period

$

261,408


$

15,232

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 operating performance and compare the results of operations from period to period without regard to financing methods or capital structure. Management excludes the items listed above from net income in arriving at EBITDAX because these amounts can vary substantially from company to company within the Company's 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. Management believes EBITDAX is a widely followed measure of operating performance and may also be used by investors to measure the Company's ability to meet future debt service requirements, if any. Continental's revolving credit facility requires it to maintain a total debt to EBITDAX ratio of no greater than 3.75 to 1.0 on a rolling four-quarter basis. The Company's revolving credit facility defines EBITDAX consistently with the definition of EBITDAX utilized and presented by the Company. The following table is a reconciliation of its net income to EBITDAX.


Three months ended June 30,


Six months ended June 30,


2011


2010


2011


2010


in thousands

Net income

$

239,194


$

101,741


$

101,993


$

174,206

Interest expense


18,785



11,903



37,756



20,263

Provision for income taxes


147,351



62,757



63,197



107,167

Depreciation, depletion, amortization and accretion


83,501



58,822



159,151



111,409

Property impairments


19,242



19,514



40,090



34,689

Exploration expenses


5,034



2,269



11,846



4,055

Unrealized (gains) losses on derivatives


(231,331)



(42,662)



132,756



(64,714)

Non-cash equity compensation


3,855



3,118



7,497



5,970

EBITDAX

$

285,631


$

217,462


$

554,286


$

393,045

SOURCE Continental Resources

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