2014

Continental Resources Reports Third Quarter 2013 Results Hawkinson Unit Density Test Produces at an Initial Combined Rate of 14,850 Boe per Day from Middle Bakken and Three Forks Benches One, Two and Three

Adjusted Net Income for Third Quarter 2013 of $297 Million, or $1.61 per Diluted Share

Record EBITDAX of $798 Million, an Increase of 13% Compared to Second Quarter 2013 and 62% Compared to Third Quarter 2012

Record Production Totaling 141,900 Boe per Day for Third Quarter 2013, an Increase of 5% Sequentially and 38% Compared to Third Quarter 2012

OKLAHOMA CITY, Nov. 6, 2013 /PRNewswire/ -- Continental Resources, Inc. (NYSE: CLR) ("Continental" or the "Company") announced third quarter 2013 operating and financial results, reporting net income of $167 million, or $0.91 per diluted share.  Adjusted net income, which excludes items typically excluded from published analyst estimates, totaled $297 million, or $1.61 per diluted share, an increase of $51 million compared to second quarter 2013.  The Company achieved record EBITDAX of $798 million, an increase of $89 million or 13% compared to second quarter 2013.  Definitions and reconciliations of adjusted net income, adjusted earnings per share and EBITDAX to the most directly comparable U.S. GAAP financial measures can be found in the supporting tables at the conclusion of this release.

(Logo: http://photos.prnewswire.com/prnh/20120327/DA76602LOGO)

Third quarter 2013 production highlights include:

  • Record net production of approximately 141,900 barrels of oil equivalent ("Boe") per day in third quarter 2013, of which 71% was crude oil;
  • Net Bakken production increased 7% from second quarter 2013 to approximately 94,500 Boe per day for third quarter 2013, representing 67% of total production, highlighted by Montana production growth of 17% compared to second quarter 2013; and 
  • Net production from South Central Oklahoma Oil Province ("SCOOP") play increased to approximately 20,100 Boe per day for third quarter 2013, up 14% from second quarter 2013.

Harold G. Hamm, Continental's Chairman and Chief Executive Officer commented, "The Continental team performed at an exceptional level in the third quarter of this year, increasing production, generating record EBITDAX and delivering on budget.  In addition, we completed our first density test in the Hawkinson spacing unit, demonstrating very strong initial production in the Middle Bakken and the first three benches of the Three Forks.  Once again, Continental is pioneering the expansion and improved recoveries in the world-class Bakken oil play, demonstrating the productive potential of four to five stacked zones with multiple wells in each."

Bakken Delivers Oil Growth  

Net production from the Company's industry-leading activity in the Bakken play in North Dakota and Montana increased to approximately 94,500 Boe per day in third quarter 2013, an increase of 7% sequentially and 51% above third quarter 2012. The Company's gross operated Bakken production averaged approximately 119,000 Boe per day in third quarter 2013.  In the third quarter 2013, Continental operated an average of 20 rigs across its leasehold position of approximately 1.2 million net acres in the Bakken play.  

The Company participated in completing 75 net (203 gross) wells in third quarter 2013.  Given the company's increased activity on large drilling pads, the amount of gross operated wells drilled, but not yet completed increased in third quarter 2013 and is currently 85 wells.

Drilling and completion costs continued to improve in the Bakken in the third quarter. Continental's average operated completed well cost in North Dakota is now $8.0 million per well, achieving its revised year-end target two months ahead of schedule.  The Company's original operated well cost target for 2013 was $8.2 million per well, which was later reduced to $8.0 million per well.  

Bakken Downspacing Activity: The Hawkinson Unit

In October 2013 and one month ahead of schedule, Continental successfully completed the first of four pilot density projects it has under way.  The Hawkinson unit initially tested at a combined rate of 14,850 Boe per day from 14 wells.  This included 13,400 Boe per day from 11 new wells drilled this year and combined current rates of 1,450 Boe per day from three existing wells in the unit, which to-date have cumulative production of 1.3 million Boe since 2010.  The Hawkinson density project includes four Middle Bakken, three TF1 (Three Forks 1), four TF2 and three TF3 wells, which all were spaced 1,320 feet apart in the same zone and offset 660 feet in the adjacent zones.  This is the industry's first density drilling program in the basin to include all of these lower benches.  

W. F. "Rick" Bott, Continental's President and Chief Operating Officer, commented, "The Hawkinson project is a milestone event for CLR and further validates our vision for full field development of the Bakken –Three Forks reservoirs in this world class oil field.  Clearly there is more oil to be recovered than previously perceived and projects like the Hawkinson are leading the way to defining the optimum drilling density and pattern to maximize oil recovery.  The news in the Bakken just keeps getting better."

In addition to the Hawkinson project, Continental has three other density pilot tests in North Dakota underway, with results expected in the first half of 2014.  The Tangsrud project in Divide County involves 12 new wells and the Rollefstad project in McKenzie County involves 11 new wells drilled with 1,320 foot same zone inter-well spacing, similar to the Hawkinson.  The Wahpeton project in McKenzie County involves 13 new wells configured in four zones at tighter spacing, which is 660 foot same zone inter-well spacing.  During 2014, Continental plans to conduct three additional density pilots to test 660 foot inter-well spacing, further defining the density spacing across a very large portion of Continental's acreage in the Bakken.  

The Company plans to complete approximately 282 net (761 gross) wells in the Bakken in 2013, including both operated and non-operated wells.  The Company estimates its operated rig activity will average 20 rigs throughout the balance of 2013, down from 22 rigs as earlier expected due to realized efficiencies.  This activity level should deliver the planned production growth and stay within capital expenditure guidance. 

Full Development Planned for Antelope – "Ears Back" Program

The Antelope prospect area in McKenzie and Williams Counties, North Dakota will be the first area Continental will execute full field development activities in the Bakken as part of the 2013-2014 planned capital program.  The Company currently has 40 gross existing producing wells in this area, which includes the recently completed prolific Angus wells and legacy activity at the Rollefstad density pilot.  The Company plans to drill an additional 350 wells over the course of the next four to five years focusing on drilling pads with 20 to 30 wells per location.  Continental's "Ears Back" project in Antelope will dedicate four rigs in 2014 for full field development with plans to drill Middle Bakken, TF1, TF2 and TF3 wells with 1,320 foot inter-well spacing.    

Hamm added, "Antelope is a high-impact area where we have been eager to expand our activity, however, we needed to allow regional infrastructure to catch up to support our goal of limited natural gas flaring.  We are already leveraging on the success of the Hawkinson project in Antelope with well placement, completion design and facility planning for up to 30 wells on a single location.  This area will be the first in the field to see full field development including the deeper TF benches."

Growth in SCOOP Continues    

Continental continues to deliver excellent, repeatable results from its drilling activity in the SCOOP.  The play, discovered by Continental and announced in October 2012, currently extends approximately 3,300 square miles across several counties in Oklahoma and contains defined oil and condensate-rich fairways as delineated by more than 290 gross wells in the area.  Continental currently has approximately 320,000 net acres of leasehold in the play.  In third quarter 2013, SCOOP net production averaged approximately 20,100 Boe per day, an increase of 14% sequentially and 293% above third quarter 2012.  The recent growth was driven by the addition of 11 net (22 gross) operated and non-operated wells in the play during the third quarter 2013, as per the Company's capital plan. 

The Company is currently operating 12 rigs in the play with plans to increase to 15 by year-end 2013.  The Company plans to complete a total of approximately 41 net (77 gross) wells in the SCOOP play in 2013, including both operated and non-operated wells.  These wells will focus on expanding the proved productive extent of the play and de-risking the Company's leasehold.  Expected net and gross well count activity has been adjusted to account for recent increased cross-unit activity.

Production

Third quarter 2013 Company net production totaled 13.1 million Boe, or approximately 141,900 Boe per day, a sequential increase of 5% from second quarter 2013.  Total net production included approximately 100,700 barrels of oil per day (71% of production) and approximately 247 million cubic feet of natural gas per day (29% of production).  In the third quarter 2013, the Company sold its natural gas prior to processing based upon pricing provisions in its natural gas contracts.  The Company estimates that if it had sold its natural gas liquids after processing, the combined natural gas liquids and oil would account for approximately 80% of total production.

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










3Q


2Q


3Q

Boe per day


2013


2013


2012

North Region:







North Dakota Bakken


81,545


76,909


55,918

Montana Bakken


12,957


11,081


6,535

Red River Units 


14,703


14,886


14,916

Other


408


2,141


1,343








South Region:







SCOOP


20,070


17,547


5,108

NW Cana


6,985


7,763


11,395

Arkoma


3,004


3,064


4,061

Other 


2,201


2,309


2,590

East Region


-


-


1,098

Total


141,873


135,700


102,964

Financial Update 

Continental's average realized sales price excluding the effects of derivative positions was $98.02 per barrel of oil and $5.23 per thousand cubic feet ("Mcf") of natural gas, or $78.55 per Boe for third quarter 2013.  Realized settlements of commodity derivative positions generated a $5.92 loss per barrel of oil and $0.62 gain per Mcf of natural gas resulting in a net realized hedging loss of $40.3 million, or $3.11 per Boe for the third quarter 2013.  Based on realizations without the effect of derivatives, the Company's third quarter 2013 oil differential was $7.80 per barrel below the NYMEX daily average for the period.  The realized natural gas price differential for third quarter 2013 was a positive $1.65 per Mcf.

Production expense per Boe was $5.17 for third quarter 2013, an improvement of $0.69 per Boe compared to second quarter 2013.   Other select operating costs and expenses for third quarter 2013 included production taxes of 8.2% of oil and natural gas sales; DD&A of $18.87 per Boe; and G&A (cash and non-cash, excluding relocation expenses) of $2.62 per Boe.  The Company's 2013 and 2014 guidance can be found at the conclusion of this release.

As of September 30, 2013, Continental's balance sheet included approximately $92 million in cash and cash equivalents and an undrawn $1.5 billion revolving credit facility.  During third quarter 2013, the Company's long-term corporate credit rating and senior unsecured debt was increased by Standard & Poor's to BBB-, which is investment grade status.  As of September 30, 2013, the Company's Net Debt-to-EBITDAX ratio for the trailing four quarters and third quarter 2013 annualized was 1.6 and 1.4 times, respectively.  

Non-acquisition capital expenditures for third quarter 2013 totaled $910 million, including $770 million in exploration and development drilling, $100 million in leasehold and seismic and $40 million in workovers, recompletions and other.  Acquisition capital expenditures totaled approximately $74 million for third quarter 2013, and are excluded from the Company's capital expenditure guidance for 2013 of $3.6 billion

The following table provides the Company's production results, average sales prices, per-unit operating costs, results of operations and certain non-GAAP financial measures for the periods presented.  Average sales prices exclude any effect of derivative transactions.  Per-unit expenses have been calculated using sales volumes. 








3Q


2Q


3Q


2013


2013


2012

Average daily production:






Crude oil (Bbl per day)

100,684


96,029


72,235

Natural gas (Mcf per day)

247,135


238,028


184,377

Crude oil equivalents (Boe per day)

141,873


135,700


102,964

Average sales prices, excluding effect from derivatives:






Crude oil ($/Bbl)

$98.02


$87.22


$82.87

Natural gas ($/Mcf)

$5.23


$5.22


$4.00

Crude oil equivalents ($/Boe)

$78.55


$71.13


$65.62

Production expenses ($/Boe)

$5.17


$5.86


$5.62

Production taxes (% of oil and gas revenues)

8.2%


8.3%


8.4%

DD&A ($/Boe)

$18.87


$18.88


$19.62

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

$1.81


$2.03


$2.29

Non-cash equity compensation ($/Boe)

$0.81


$0.78


$0.78

Net income (in thousands) 

$167,498


$323,270


$44,096

Diluted net income per share

$0.91


$1.75


$0.24

Adjusted net income (in thousands) (2) 

$296,879


$245,728


$159,511

Adjusted diluted net income per share (2) 

$1.61


$1.33


$0.87

EBITDAX (in thousands) (2) 

$797,575


$708,107


$492,279

(1)

General and administrative expenses ($/Boe) exclude non-recurring corporate relocation expenses of $0.1 million ($0.01 per Boe) for the three months ended September 30, 2013, $0.7 million ($0.05 per Boe) for the three months ended June 30, 2013, and $2.3 million ($0.24 per Boe) for the three months ended September 30, 2012.

(2)

Adjusted net income, adjusted diluted net income per share and EBITDAX represent non-GAAP financial measures. These measures should not be considered as an alternative to, or more meaningful than, net income, diluted net income per share, or operating cash flows as determined in accordance with U.S. GAAP. Further information about these non-GAAP financial measures as well as reconciliations of adjusted net income, adjusted diluted net income per share, and EBITDAX to the most directly comparable U.S. GAAP financial measures are provided subsequently under the header Non-GAAP Financial Measures.

Conference Call Information and Summary Presentation

Continental Resources plans to host a conference call to discuss third quarter 2013 results on Thursday, November 7, 2013 at 11 a.m. ET (10 a.m. CT). Those wishing to listen to the conference call may do so via the Company's website at www.CLR.com or by phone:

Time and date:

11 a.m. ET, Thursday, November 7, 2013

Dial in:

888 679 8033

Intl. dial in:

617 213 4846

Pass code:

15871985

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

Replay number:

888 286 8010

Intl. replay:

617 801 6888

Pass code:

59553466

Callers who wish to pre-register for the call may go to:

https://www.theconferencingservice.com/prereg/key.process?key=PUDQ6BJKE

Continental plans to publish a third quarter 2013 summary presentation to its website at www.CLR.com prior to the start of its earnings conference call on November 7, 2013. 

Upcoming Conferences

Members of Continental's management team will be participating in the following upcoming investment conferences:

November 13, 2013

Jefferies 2013 Global Energy Conference: Houston

November 22, 2013

Bank of America Merrill Lynch 2013 Global Energy Conference: Miami

December 4, 2013

Cowen and Company Ultimate Energy Conference:  New York City

December 12, 2013

Capital One Southcoast 2013 Energy Conference: New Orleans

The Company's presentations at the above conferences will be available via webcast.  Instructions regarding how to access the webcasts and presentation materials will be available on the Company's website at www.CLR.com on or prior to the day of the presentations.

About Continental Resources

Continental Resources (NYSE: CLR) is a Top 10 independent oil producer in the United States. Based in Oklahoma City, Continental is the largest leaseholder and producer in the nation's premier oil field, the Bakken play of North Dakota and Montana. The company also has significant positions in Oklahoma, including its recently discovered SCOOP play and the Northwest Cana play. With a focus on the exploration and production of oil, Continental is on a mission to unlock the technology and resources vital to American energy independence. In 2013, the company will celebrate 46 years of operation. For more information, please visit www.CLR.com.

Cautionary Statement for the Purpose of the "Safe Harbor" Provisions of the Private Securities Litigation Reform Act of 1995

This press release includes "forward-looking statements" within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934. All statements included in this press release other than statements of historical fact, including, but not limited to, statements or information concerning the Company's future operations, performance, financial condition, production and reserves, schedules, plans, timing of development, returns, budgets, costs, business strategy, objectives, and cash flow, are forward-looking statements. When used in this press release, the words "could," "may," "believe," "anticipate," "intend," "estimate," "expect," "project," "budget," "plan," "continue," "potential," "guidance," "strategy," and similar expressions are intended to identify forward-looking statements, although not all forward-looking statements contain such identifying words. Forward-looking statements are based on the Company's current expectations and assumptions about future events and currently available information as to the outcome and timing of future events. Although the Company believes the expectations reflected in the forward-looking statements are reasonable and based on reasonable assumptions, no assurance can be given that such expectations will be correct or achieved or that the assumptions are accurate. When considering forward-looking statements, readers should keep in mind the risk factors and other cautionary statements described under Part I, Item 1A. Risk Factors included in the Company's Annual Report on Form 10-K for the year ended December 31, 2012, registration statements and other reports filed from time to time with the Securities and Exchange Commission ("SEC"), and other announcements the Company makes from time to time.

The Company cautions readers these forward-looking statements are subject to all of the risks and uncertainties, most of which are difficult to predict and many of which are beyond the Company's control, incident to the exploration for, and development, production, and sale of, crude oil and natural gas. These risks include, but are not limited to, commodity price volatility, inflation, lack of availability of drilling and production equipment and services, environmental risks, drilling and other operating risks, regulatory changes, the uncertainty inherent in estimating crude oil and natural gas reserves and in projecting future rates of production, cash flows and access to capital, the timing of development expenditures, and the other risks described under Part I, Item 1A. Risk Factors in the Company's Annual Report on Form 10-K for the year ended December 31, 2012, registration statements and other reports filed from time to time with the SEC, and other announcements the Company makes from time to time.

Readers are cautioned not to place undue reliance on forward-looking statements, which speak only as of the date hereof. Should one or more of the risks or uncertainties described in this press release occur, or should underlying assumptions prove incorrect, the Company's actual results and plans could differ materially from those expressed in any forward-looking statements. All forward-looking statements are expressly qualified in their entirety by this cautionary statement. This cautionary statement should also be considered in connection with any subsequent written or oral forward-looking statements that the Company, or persons acting on its behalf, may make.

Except as otherwise required by applicable law, the Company disclaims any duty to update any forward-looking statements to reflect events or circumstances after the date of this press release.

CONTACTS: Continental Resources, Inc.


Investors

Media

Warren Henry

Kristin Miskovsky

VP, Investor Relations

VP, Public Relations

405-234-9127

405-234-9480

Warren.Henry@CLR.com 

Kristin.Miskovsky@CLR.com



John J. Kilgallon


Director, Investor Relations


405-234-9330


John.Kilgallon@CLR.com


 

Continental Resources, Inc.

Unaudited Condensed Consolidated Statements of Income







Three months ended September 30,


Nine months ended September 30,



2013


2012


2013


2012


Revenues:

In thousands, except per share data

Crude oil and natural gas sales

$

1,018,784


$

633,344


$

2,694,488


$

1,708,995


Gain (loss) on derivative instruments, net


(203,774)



(158,294)



(89,548)



144,377


Crude oil and natural gas service operations


8,825



8,679



29,876



30,176


Total revenues


823,835



483,729



2,634,816



1,883,548















Operating costs and expenses:













Production expenses


67,050



54,210



202,305



138,041


Production taxes and other expenses


93,282



62,913



247,947



162,880


Exploration expenses


8,173



4,899



29,138



17,752


Crude oil and natural gas service operations


6,654



7,626



22,567



24,723


Depreciation, depletion, amortization and accretion

244,721



189,374



695,189



499,847


Property impairments


42,167



27,375



161,960



93,153


General and administrative expenses 


34,070



31,925



103,761



86,704


Gain on sale of assets, net


(325)



(115)



(112)



(67,139)


Total operating costs and expenses


495,792



378,207



1,462,755



955,961


Income from operations


328,043



105,522



1,172,061



927,587


Other income (expense):













Interest expense


(62,756)



(39,205)



(171,609)



(95,174)


Other 


584



710



1,765



2,280




(62,172)



(38,495)



(169,844)



(92,894)


Income before income taxes


265,871



67,027



1,002,217



834,693


Provision for income taxes


98,373



22,931



370,822



315,819


Net income

$

167,498


$

44,096


$

631,395


$

518,874


Basic net income per share

$

0.91


$

0.24


$

3.43


$

2.88


Diluted net income per share

$

0.91


$

0.24


$

3.42


$

2.86


 


Continental Resources, Inc.

Unaudited Condensed Consolidated Balance Sheets






September 30,


December 31,


2013


2012

Assets

In thousands

Current assets

$

1,213,181


$

946,783

Net property and equipment (1)


10,112,506



8,105,269

Other noncurrent assets


94,601



87,957

Total assets

$

11,420,288


$

9,140,009







Liabilities and shareholders' equity






Current liabilities

$

1,468,071


$

1,125,865

Long-term debt


4,439,825



3,537,771

Other noncurrent liabilities


1,691,779



1,312,674

Total shareholders' equity


3,820,613



3,163,699

Total liabilities and shareholders' equity

$

11,420,288


$

9,140,009







(1)

Balance is net of accumulated depreciation, depletion and amortization of $2.84 billion and $2.12 billion as of September 30, 2013 and December 31, 2012, respectively.

 

Continental Resources, Inc.

Unaudited Condensed Consolidated Statements of Cash Flows










Three months ended September 30, 



Nine months ended September 30, 


2013


2012


2013


2012


In thousands

Net income 

$

167,498


$

44,096


$

631,395


$

518,874

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












Non-cash expenses


558,759



412,006



1,297,762



681,891

Changes in assets and liabilities


95,251



(79,035)



49,296



(52,868)

Net cash provided by operating activities


821,508



377,067



1,978,453



1,147,897

Net cash used in investing activities


(949,211)



(817,635)



(2,799,388)



(2,591,127)

Net cash (used in) provided by financing activities


(1,203)



670,876



876,713



1,649,131

Net change in cash and cash equivalents


(128,906)



230,308



55,778



205,901

Cash and cash equivalents at beginning of period


220,413



29,137



35,729



53,544

Cash and cash equivalents at end of period

$

91,507


$

259,445


$

91,507


$

259,445

Non-GAAP Financial Measures

EBITDAX

EBITDAX represents earnings before interest expense, income taxes, depreciation, depletion, amortization and accretion, property impairments, exploration expenses, non-cash gains and losses resulting from the requirements of accounting for derivatives, and non-cash equity compensation expense. EBITDAX is not a measure of net income or operating 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 and operating cash flows 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 operating 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 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 credit facility requires that we maintain a total funded debt to EBITDAX ratio of no greater than 4.0 to 1.0 on a rolling four-quarter basis. This ratio represents the sum of outstanding borrowings and the letters of credit under our credit facility plus our note payable and Senior Note obligations, divided by total EBITDAX for the most recent four quarters. Our credit facility defines EBITDAX consistent with the presentation below. The following table provides a reconciliation of our net income to EBITDAX for the periods presented.



3Q 2013



2Q 2013



3Q 2012


in thousands

Net income

$

167,498


$

323,270


$

44,096

Interest expense


62,756



61,378



39,205

Provision for income taxes


98,373



189,858



22,931

Depreciation, depletion, amortization and accretion


244,721



236,790



189,374

Property impairments


42,167



79,712



27,375

Exploration expenses


8,173



11,151



4,899

Impact from derivative instruments:









Total (gain) loss on derivatives, net


203,774



(199,056)



158,294

Total cash paid on derivatives, net


(40,349)



(4,752)



(1,394)

Non-cash (gain) loss on derivatives, net


163,425



(203,808)



156,900

Non-cash equity compensation


10,462



9,756



7,499

EBITDAX

$

797,575


$

708,107


$

492,279

The following table provides a reconciliation of our net cash provided by operating activities to EBITDAX for the periods presented.




3Q 2013



2Q 2013



3Q 2012


in thousands

Net cash provided by operating activities

$

821,508


$

698,834


$

377,067

Current income tax provision (benefit)


4,393



5,830



(9,874)

Interest expense


62,756



61,378



39,205

Exploration expenses, excluding dry hole costs


7,055



5,349



4,678

Gain (loss) on sale of assets, net


325



(349)



115

Other, net


(3,211)



2,539



2,053

Changes in assets and liabilities


(95,251)



(65,474)



79,035

EBITDAX

$

797,575


$

708,107


$

492,279

Adjusted earnings and adjusted earnings per share

Our presentation of adjusted earnings and adjusted earnings per share that exclude the effect of certain items are non-GAAP financial measures. Adjusted earnings and adjusted earnings per share represent earnings and diluted earnings per share determined under U.S. GAAP without regard to non-cash gains and losses on derivative instruments, property impairments, gains and losses on asset sales, and corporate relocation expenses. Management believes these measures provide useful information to analysts and investors for analysis of our operating results on a recurring, comparable basis from period to period. In addition, management believes these measures are used by analysts and others in valuation, comparison and investment recommendations of companies in the oil and gas industry to allow for analysis without regard to an entity's specific derivative portfolio, impairment methodologies, and nonrecurring transactions. Adjusted earnings and adjusted earnings per share should not be considered in isolation or as a substitute for earnings or diluted earnings per share as determined in accordance with U.S. GAAP and may not be comparable to other similarly titled measures of other companies. The following table reconciles earnings and diluted earnings per share as determined under U.S. GAAP to adjusted earnings and adjusted diluted earnings per share for the periods presented.









3Q 2013


2Q 2013


3Q 2012

In thousands, except per share data


After-Tax $


Diluted EPS


After-Tax $


Diluted EPS


After-Tax $


Diluted EPS

Net income (GAAP)


$ 167,498


$        0.91


$ 323,270


$        1.75


$  44,096


$        0.24

Adjustments, net of tax:














Non-cash (gain) loss on derivatives, net


102,958


$        0.56


(128,399)


$       (0.69)


97,121


0.53


Property impairments


26,565


$        0.14


50,219


$        0.27


16,945


0.09


(Gain) loss on sale of assets, net


(205)


-


220


-


(71)


-


Corporate relocation expenses


63


-


418


-


1,420


0.01



Adjusted net income (Non-GAAP)


$ 296,879


$        1.61


$ 245,728


$        1.33


$ 159,511


$        0.87



Weighted average diluted shares outstanding


184,880




184,739




182,537





Adjusted diluted net income per share (Non-GAAP)


$      1.61




$      1.33




$      0.87



 

 

 


Continental Resources, Inc. 

2013 and 2014 Guidance Outlook

As of November 6, 2013*






2013


2014





Production growth (YOY)

38% to 40%


26% to 32%

Capital expenditures (non-acquisition)

$3.6B


$4.05B





Operating Expenses:




     Production expense per Boe

$5.60 to $6.00


$5.60 to $6.10

     Production tax (% of oil & gas revenue)**

8% to 9%


8% to 9%

     DD&A per Boe

$18.50 to $19.50


$17.50 to $19.50

     G&A expense per Boe

 $2.00 to $2.50


$2.00 to $2.50

     Non-cash equity compensation per Boe

 $0.70 to $0.80


$0.70 to $0.90





Average Price Differentials:




     NYMEX WTI crude oil (per barrel of oil)

($6.00) to ($8.00)


($8.00) to ($11.00)

     Henry Hub natural gas (per Mcf)

+$1.00 to $1.50


+$1.00 to $1.50





Income tax rate

37%


37%

Deferred taxes

 90% to 95%


 90% to 95%



*    No change from previously announced 2013 and 2014 Guidance Outlook on September 10, 2013

**  Does not include other expenses which could represent an additional 1%

SOURCE Continental Resources



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