Continental Resources Reports First Quarter 2013 Results

Record Production Totaling 121,500 Boe per Day for First Quarter 2013, an Increase of 14% Sequentially and 42% Compared to First Quarter 2012
Company Reports Adjusted Net Income for First Quarter 2013 of $215 Million, or $1.17 per Diluted Share; Record EBITDAX of $622 Million, an Increase of 5% Compared to Fourth Quarter 2012 and 37% Compared to First Quarter 2012
Three Recent Successful Lower Three Forks Completions Announced; SCOOP Production Doubles Quarter over Quarter on Strong Wells

PR Newswire

OKLAHOMA CITY, May 8, 2013 /PRNewswire/ -- Continental Resources, Inc. (CLR) ("Continental" or the "Company") announced first quarter 2013 operating and financial results, reporting net income of $141 million, or $0.76 per diluted share.  Adjusted net income, which excludes items typically excluded from published analyst estimates, totaled $215 million, or $1.17 per diluted share.  EBITDAX reached a record level of $622 million, an increase of $27 million or 5% compared to fourth quarter 2012.  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)

Significant first quarter 2013 operational highlights:

  • Achieved record net production of approximately 121,500 barrels oil equivalent ("Boe") per day in first quarter 2013, which includes 71% crude oil;
  • Net Bakken production increased to approximately 76,900 Boe per day for first quarter 2013, representing 63% of total production.  Gross operated Bakken production surpassed a significant milestone, averaging more than 100,000 Boe per day for first quarter 2013;
  • Three recent successful Lower Three Forks completions expand the potential aerial extent of productivity and are performing in-line with similar Middle Bakken and Upper Three Forks wells in the surrounding areas;       
  • Ahead of plan to reduce operated Bakken average well costs to $8.2 million by year-end 2013, current operated well costs are approximately $8.3 million; and
  •  Net production from South Central Oklahoma Oil Province ("SCOOP") play increased to approximately 14,200 Boe per day, up 100% from fourth quarter 2012 and up 462% from first quarter 2012.

"We are off to an excellent start in 2013 in executing our strategy of profitably growing our world-class position in the Bakken, testing the lower benches and downspacing capability, and also delineating our exciting new play, SCOOP," said Harold G. Hamm, Continental's Chairman and Chief Executive Officer. "Our focus on driving well costs lower has been successful due to enhanced utilization of pad drilling, improved cycle times and supply chain efforts.  We intend to maintain our capital spending discipline this year, as evident in our first quarter results."

Production, Realizations and Expenses

First quarter 2013 net production totaled 10.9 million Boe, or approximately 121,500 Boe per day, a sequential increase of 14% from fourth quarter 2012.  Total production included approximately 86,100 barrels of oil per day (71% of production) and approximately 212.8 million cubic feet of natural gas per day (29% of production).  While the Company currently sells 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 Company's combined natural gas liquids and oil would account for approximately 80% of total production.

Continental's average realized sales price excluding the effects of derivative positions was $89.99 per barrel of oil and $4.99 per thousand cubic feet ("Mcf") of natural gas, or $72.31 per Boe.  Realized settlements of commodity derivative positions generated a $1.24 loss per barrel of oil and $0.14 gain per Mcf of natural gas resulting in a net realized hedging loss of $6.8 million, or $0.63 per Boe for the first quarter 2013.

Based on realizations without the effect of derivatives, the Company's first quarter 2013 oil differential, as compared to the NYMEX daily average for the period, was a negative $4.29 per barrel, favorable to annual guidance of negative $5.00 to $7.00 per barrel.  The natural gas differential for first quarter 2013 was a positive $1.65 per Mcf of natural gas, favorable to annual guidance range of positive $1.00 to $1.50 per Mcf. 

Production expense per Boe was $5.70 for first quarter 2013, sequentially below $5.90 per Boe from fourth quarter 2012, but above annual guidance range of $5.20 to $5.60 per Boe, due to typical winter weather temporarily impacting production costs in certain areas.  The Company expects per unit production expense to decrease throughout a majority of the remainder of the year.  Other select operating costs and expenses for first quarter 2013 were as follows: production taxes 8.2% of oil and natural gas sales; DD&A $19.72 per Boe and G&A (cash and non-cash, excluding relocation expenses) $3.05 per Boe, all within the range of the Company's annual guidance.  The Company's 2013 guidance can be found on the last page of this release and remains unchanged from previous guidance provided on February 27, 2013.    

W. F. "Rick" Bott, Continental's President and Chief Operating Officer, added, "Our production growth remained strong despite seasonal challenges in the Bakken.  Our realizations remain on track, driving an impressive 74% cash margin, which benefited from 80% of our operated Bakken production being transported by rail as we continue to access markets on all US coasts.  We continue to monitor oil differentials and transportation costs to ensure we realize the most attractive pricing for our premium Bakken oil."


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



1Q


4Q


1Q

Boe per day


2013


2012


2012

North Region:







North Dakota Bakken


67,575


59,019


41,895

Montana Bakken


9,352


8,503


6,129

Red River Units


15,055


14,716


15,415

Other


1,267


967


1,445








South Region:







SCOOP


14,243


7,123


2,533

NW Cana


8,323


9,716


10,293

Arkoma


3,234


3,225


3,637

Other


2,483


2,556


2,988

East Region


-


1,006


1,191

Total


121,532


106,831


85,526

The following table provides 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 are calculated using sales volumes. 








1Q


4Q


1Q


2013


2012


2012

Average daily production:






Crude oil (Bbl per day)

86,071


76,449


59,901

Natural gas (Mcf per day)

212,766


182,289


153,751

Crude oil equivalents (Boe per day)

121,532


106,831


85,526

Average sales prices, excluding effect from derivatives:






Crude oil ($/Bbl)

$89.99


$84.99


$90.58

Natural gas ($/Mcf)

$4.99


$4.82


$4.48

Crude oil equivalents ($/Boe)

$72.31


$68.89


$71.39

Production expenses ($/Boe)

$5.70


$5.90


$5.18

Production taxes (% of oil and gas revenues)

8.2%


8.3%


8.1%

DD&A ($/Boe)

$19.72


$19.76


$19.32

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

$2.20


$2.70


$2.29

Non-cash equity compensation ($/Boe)

$0.85


$0.85


$0.71

Net income (in thousands) 

$140,627


$220,511


$69,094

Diluted net income per share

$0.76


$1.19


$0.38

Adjusted net income (in thousands) (2) 

$215,386


$191,801


$137,900

Adjusted diluted net income per share (2) 

$1.17


$1.04


$0.76

EBITDAX (in thousands) (2) 

$621,528


$594,452


$454,532

(1)

General and administrative expenses exclude non-recurring corporate relocation expenses of $0.7 million ($0.06 per Boe) for first quarter 2013, $0.5 million ($0.05 per Boe) for fourth quarter 2012 and $1.7 million ($0.23 per Boe) for first quarter 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.

Financial Update  

At March 31, 2013, Continental's balance sheet included approximately $59 million in cash and cash equivalents and approximately $4.0 billion in total debt, which included approximately $1.0 billion borrowed under the Company's revolving credit facility.  On April 5, 2013, Continental completed a $1.5 billion, 4½ % senior unsecured notes offering, which matures in 2023.  Proceeds from the offering were applied to fully repay borrowings under the credit facility and for future development and exploratory drilling.       

Non-acquisition capital expenditures for first quarter 2013 totaled approximately $899 million, including $792 million in exploration and development drilling, $84 million in leasehold and seismic and $23 million in workovers, recompletions and other.  Acquisition capital expenditures totaled approximately $22 million for first quarter 2013, and are excluded from the Company's capital expenditure guidance for 2013 of $3.6 billion.    

John D. Hart, Continental's Chief Financial Officer, added, "Our recent notes offering was highly successful, and our focus on cost reduction and efficiency gains is on schedule to keep us in-line with our capital expenditure guidance.  Our significant production growth and consistent top-tier cash margins per Boe allow us to self-fund a larger portion of our planned activity." 

Strong Bakken Production Growth

Net production from the Company's activity in the Bakken play in North Dakota and Montana increased to approximately 76,900 Boe per day in first quarter 2013, an increase of 14% sequentially and 60% above first quarter 2012.  The Company's gross operated average production in first quarter 2013 in the Bakken reached a milestone of more than 100,000 Boe per day.  Continental operated 22 rigs across its industry-leading leasehold position of approximately 1.2 million net acres in the Bakken play.  The Company participated in completing 66 net (162 gross) wells in first quarter 2013, which included 21 gross wells deferred from fourth quarter 2012.  The Company's Bakken backlog of gross wells drilled, but not yet completed, is currently 80 gross wells, which is down from fourth quarter 2012, however is expected to grow at various times of the year due to increased utilization of pad drilling. 

Development drilling and completion activity for first quarter 2013 continued to meet expectations. In North Dakota, Company-operated wells completed during first quarter 2013 averaged an initial one-day test of 1,125 Boe per day, which included 84% oil.  Company-operated Montana wells completed during first quarter 2013 averaged an initial one-day test of 670 Boe per day, which included 87% oil. These results are consistent with the Company's estimated ultimate recovery ("EUR") models of 603,000 Boe for North Dakota wells and 430,000 Boe for Montana wells.

Continental continues to make progress on its 22-well Lower Three Forks exploratory program, which is testing the productive extent of the lower benches.  Initial 24-hour flow rates from Lower Three Forks tests for first quarter 2013 included the Barney 2-29H-2 well, which is a second-bench test and had an initial flow rate of 1,075 Boe per day.  The well is located 16 miles north of the Company's Charlotte pad.  At the Company-operated Stedman pad, located on the western flank of the play near the North Dakota and Montana border and 35 miles northwest of the Charlotte pad, the Stedman 2-24H-2 well, a second-bench test flowed at an initial rate of 1,030 Boe per day.  Additionally, the Stedman 3-24H-3 well, a third-bench test had initial one-day production of 465 Boe. 

Inclusive of these wells, the Company currently has six producing wells in the lower benches with average initial production rates of approximately 1,170 Boe per day.  On average, these six wells are performing in-line with typical Middle Bakken and Three Forks first-bench wells in their respective areas. 

The following table summarizes the Company's Lower Three Forks activity:



Lower Three Forks Exploration Well Status

Zone

Drilling

Completing

Producing

To Be Drilled

Total

TF1


1


3

4

TF2

2

1

4

4

11

TF3


3

2


5

TF4


2



2

Total

2

7

6

7

22

Data in table includes two wells drilled in 2012 and 20 wells drilled or planned in 2013

Cumulative approximate production from the Company's initial lower bench tests include 116,000 Boe from the Charlotte 2-22H well, a second-bench test of 18 months; 55,000 Boe from the Charlotte 3-22H well, a third-bench test of 5.5 months;  and 53,000 Boe from the Angus 2-9H-2 well, a second-bench test of 2 months. 

The Company's other Bakken exploration and appraisal initiative involves four pilot density projects to test 320-acre and 160-acre spacing in the Middle Bakken and first three benches of the Three Forks. The Company plans to complete 47 gross wells in the pilot density program, to help determine the optimum well spacing and pattern to maximize the ultimate recovery from the multiple Bakken and Three Forks reservoirs.

Continental has drilled eight wells and is currently drilling the ninth on its first 320-acre pilot density project at the Hawkinson pad in Dunn County.  Drilling is under way on the 13-well, 160-acre pilot on the Wahpeton pad in McKenzie County and the 12-well, 320-acre pilot on the Tangsrud pad in Divide County.  One additional 320-acre pilot at the Rollefstad pad is scheduled to spud in the second half of 2013.  In summary, of the 47-well pilot density program, 10 wells are currently in the drilling stage, 10 wells are waiting on completion and 27 wells have yet to be drilled.  Once each pad has reached initial production, the wells will be announced together as part of the quarterly results.

The Company plans to complete 245 net (790 gross) wells in the Bakken in 2013, including both operated and non-operated wells. Due to efficiency gains, the Company plans to reduce operated rig activity to an average of 20 rigs through the balance of the year, which should deliver the planned production growth and keep within capital expenditure guidance.   

Mr. Bott added, "Quarter after quarter, our Bakken operations continue to deliver impressive growth with highly attractive returns.  On the exploration front, we are very excited about the continual success of our Lower Three Forks productivity tests.  Our cost focus has put us ahead of target on reducing average drilling and completion well costs in the Bakken.  Based on field estimates, we are down to approximately $8.3 million in April 2013."  

SCOOP Results  

Continental has approximately 232,000 net acres of leasehold in the SCOOP play, which stretches from Grady County to the southeast to Love County.  In first quarter 2013, SCOOP net production averaged approximately 14,200 Boe per day, an increase of 100% sequentially and 462% above first quarter 2012.  The recent growth was driven by impressive initial production rates and increased activity in the play, which included nine net (15 gross) additional operated and non-operated wells in the play during the first quarter 2013.  In the condensate window, wells completed during first quarter 2013 averaged initial one-day tests of 1,050 Boe per day, which included 24% oil.  The company is currently operating nine rigs in the play with plans to increase to 12.  

Select Continental-operated wells completed in the condensate window in first quarter 2013 include:

  • Colbert 1-32H well produced 1,769 Boe per day (30% oil) in its initial one-day test period; and
  • Knox 1-1H well produced 1,151 Boe per day (26% oil) in its initial one-day test period.

The Company plans to complete 55 net (115 gross) wells in the SCOOP play in 2013, including both operated and non-operated wells.

Richard E. Muncrief, Continental's Senior Vice President of Operations, stated, "We are extremely excited about the doubling of our SCOOP production in one quarter.  It is a huge credit to our teams, who have ramped up to nine rigs in a short period of time.  We remain focused on delivering production targets, but also reducing cycle times and well costs, which is essential in order to compete for capital with our highly profitable Bakken activity."       

Conference Call Information

Continental Resources plans to host a conference call to discuss first quarter 2013 results on Thursday, May, 9, 2013 at 10 a.m. ET (9 a.m. CT). Those wishing to listen to the conference call may do so via the Company's web site at www.CLR.com or by phone:

Time and date:  

10 a.m. ET, Thursday, May 9, 2013

Dial in:

888 680 0892

Intl. dial in:

617 213 4858

Pass code:

62640885

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:             

82241170

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

https://www.theconferencingservice.com/prereg/key.process?key=PL6YUULQB

Upcoming Company Presentations

Continental management is currently scheduled to present at the following investment conferences.  Presentation materials will be available on the Company's website, www.CLR.com, the day of the event.

May 13    

FBR Energy & Industrials Conference, Boston;

May 14        

Bank of America Merrill Lynch Global Energy and Power Leveraged Finance Conference, New York City;

May 16      

Barrington Research Industrial & Business Services Conference, Chicago;

May 21       

UBS Oil and Gas Conference, Austin;

June 11       

Williams Financial Group First Annual Energy Conference, Dallas; and

June 25        

Global Hunter Securities 100 Energy Conference, Chicago.

The Company's presentations at the conferences on May 21 and June 25 will be available via webcast.  Instructions regarding how to access such webcasts will be available on the Company's web site at www.CLR.com on or prior to the day of the presentations.  Such webcasts will be available for 30 days on the Company's web site.

About Continental Resources

Continental Resources, Inc. (CLR), based in Oklahoma City, is focused on the exploration and production of onshore oil-prone plays and is a Top 10 independent oil producer in the United States.  The Company has a long and successful history of developing its industry-leading leasehold and production in the nation's premier oil play, the Bakken of North Dakota and Montana, as well as significant positions in Oklahoma in its recently discovered SCOOP play and the Northwest Cana play.  In 2013, the Company will celebrate 46 years of operation.  Further information can be found at 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 March 31,


2013


2012

Revenues:

In thousands, except per share data

Crude oil and natural gas sales

$

783,517


$

552,258

Loss on derivative instruments, net


(84,831)



(169,057)

Crude oil and natural gas service operations


11,543



11,899

Total revenues


710,229



395,100







Operating costs and expenses:






Production expenses


61,803



40,075

Production taxes and other expenses


72,429



50,740

Exploration expenses


9,814



4,151

Crude oil and natural gas service operations


8,597



9,842

Depreciation, depletion, amortization and accretion

213,678



149,455

Property impairments


40,081



29,907

General and administrative expenses 


33,817



24,966

Gain on sale of assets, net


(136)



(49,627)

Total operating costs and expenses


440,083



259,509

Income from operations


270,146



135,591

Other income (expense):






Interest expense


(47,475)



(24,278)

Other 


546



781



(46,929)



(23,497)

Income before income taxes


223,217



112,094

Provision for income taxes


82,590



43,000

Net income

$

140,627


$

69,094

Basic net income per share

$

0.76


$

0.38

Diluted net income per share

$

0.76


$

0.38

Continental Resources, Inc.
Unaudited Condensed Consolidated Balance Sheets



March 31,


December 31,


2013


2012

Assets

In thousands

Current assets

$

1,080,592


$

946,783

Net property and equipment


8,764,624



8,105,269

Other noncurrent assets


86,960



87,957

Total assets

$

9,932,176


$

9,140,009







Liabilities and shareholders' equity






Current liabilities

$

1,217,058


$

1,125,865

Long-term debt


3,976,801



3,537,771

Other noncurrent liabilities


1,426,237



1,312,674

Total shareholders' equity


3,312,080



3,163,699

Total liabilities and shareholders' equity

$

9,932,176


$

9,140,009

 


Continental Resources, Inc.
Unaudited Condensed Consolidated Statements of Cash Flows








Three months ended March 31, 


2013


2012


In thousands

Net income 

$

140,627


$

69,094

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






Non-cash expenses


428,913



306,966

Changes in assets and liabilities


(111,429)



(11,116)

Net cash provided by operating activities


458,111



364,944







Net cash used in investing activities


(873,153)



(995,115)







Net cash provided by financing activities


437,859



619,310







Net change in cash and cash equivalents


22,817



(10,861)

Cash and cash equivalents at beginning of period


35,729



53,544

Cash and cash equivalents at end of period

$

58,546


$

42,683

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.




1Q 2013



4Q 2012



1Q 2012



in thousands


Net income

$

140,627


$

220,511


$

69,094


Interest expense


47,475



45,534



24,278


Provision for income taxes


82,590



99,992



43,000


Depreciation, depletion, amortization and accretion


213,678



192,271



149,455


Property impairments


40,081



29,121



29,907


Exploration expenses


9,814



5,755



4,151


Impact from derivative instruments:










Total (gain) loss on derivatives, net


84,831



(9,639)



169,057


Total realized gain (loss) (cash flow) on derivatives, net


(6,810)



2,655



(39,925)


Non-cash (gain) loss on derivatives, net


78,021



(6,984)



129,132


Non-cash equity compensation


9,242



8,252



5,515


EBITDAX

$

621,528


$

594,452


$

454,532

 

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











1Q 2013



1Q 2012



in thousands


Net cash provided by operating activities

$

458,111


$

364,944


Current income tax provision


-



2,150


Interest expense


47,475



24,278


Exploration expenses, excluding dry hole costs


7,553



4,063


Gain on sale of assets, net


136



49,627


Other, net


(3,176)



(1,646)


Changes in assets and liabilities


111,429



11,116


EBITDAX

$

621,528


$

454,532

 

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.









1Q 2013


4Q 2012


1Q 2012

In thousands, except per share data


After-Tax $


Diluted EPS


After-Tax $


Diluted EPS


After-Tax $


Diluted EPS

Net income (GAAP)


$ 140,627


$        0.76


$ 220,511


$        1.19


$  69,094


$        0.38

Adjustments, net of tax:














Non-cash (gain) loss on derivatives, net


49,153


0.27


(4,331)


(0.02)


79,933


0.44


Property impairments


25,251


0.14


18,054


0.10


18,512


0.10


Gain on sale of assets, net


(86)


-


(42,723)


(0.23)


(30,719)


(0.17)


Corporate relocation expenses


441


-


290


-


1,080


0.01



Adjusted net income (Non-GAAP)


$ 215,386


$        1.17


$ 191,801


$        1.04


$ 137,900


$        0.76



Weighted average diluted shares outstanding


184,656




184,603




180,283





Adjusted diluted net income per share (Non-GAAP)


$      1.17




$      1.04




$      0.76



Continental Resources, Inc.
2013 Guidance Outlook
As of May 8, 2013




Production growth


35% to 40%

Capital expenditures (1)


$3.6 billion




Price differentials:



     WTI crude oil (per barrel of oil)


($5.00) to ($7.00)

     Henry Hub natural gas (per Mcf)


+$1.00 to +$1.50




Operating expenses:



     Production expense per Boe


$5.20 to $5.60

     Production tax (% of oil and gas revenues)


8% to 9%

     DD&A per Boe


$19.00 to $21.00

     G&A expense per Boe


$2.20 to $2.70

     Non-cash equity compensation per Boe


$0.70 to $0.90




Income tax rate


37%

Deferred taxes


90% to 95%

(1)

Excludes acquisition capital expenditures.

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