Continental Resources Reports Second Quarter 2014 Results Record EBITDAX of $868 Million; Adjusted Net Income Totaled $277 Million, or $1.50 per Diluted Share

Production Increase of Approximately 15,500 Boe per Day to an Average of 167,953 Boe per Day, a 10% Increase Compared to First Quarter 2014; Bakken and SCOOP Production Up 11% and 17% Sequentially

Enhanced Completions Continue to Show Increased Early Production Uplift

Completed First 660-Foot Density Pilot at the Wahpeton Pad With Initial Rates on 12 New Wells Averaging 1,015 Boe per day

OKLAHOMA CITY, Aug. 5, 2014 /PRNewswire/ -- Continental Resources, Inc. (NYSE: CLR) ("Continental" or the "Company") today announced second quarter 2014 operating and financial results.  Net income for the quarter ended June 30, 2014 was $104 million, or $0.56 per diluted share.  Excluding items typically excluded from published analyst estimates, adjusted net income for second quarter 2014 was $277 million, or $1.50 per diluted share, a 13% increase over adjusted net income of $246 million, or $1.33 per diluted share, for second quarter 2013. 

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EBITDAX for second quarter 2014 was $868 million, a 12% increase over EBITDAX of $775 million for first quarter 2014 and 23% above EBITDAX for second quarter 2013.  Definitions and reconciliations of adjusted net income, adjusted earnings per share and EBITDAX to the most directly comparable U.S. generally accepted accounting principles ("GAAP") financial measures can be found in the supporting tables at the conclusion of this press release.

Harold G. Hamm, Chairman and Chief Executive Officer, commented, "Our team executed very well this quarter, evidenced by sequential quarterly production growth of 15,500 Boe per day, putting us on track to achieve our annual production growth target for 2014.  Our superior asset base is gaining value each quarter from our work in density development, exploration drilling and production improvements.  We are making great progress with enhanced completions and are encouraged with early results."   

Production and Sales Volumes

Second quarter 2014 net production totaled 15.3 million barrels of oil equivalent ("Boe"), or 167,953 Boe per day, a sequential increase of 10% from first quarter 2014 and 24% higher than second quarter 2013.  Total net production included 116,441 barrels of oil per day (69% of production) and approximately 309 million cubic feet of natural gas ("MMcf") per day (31% of production).  In second quarter 2014, sales volumes totaled approximately 15.4 million Boe, or 168,810 Boe per day, which was approximately 78,000 barrels above the amount produced for the quarter.  This overlift (sales exceeding production) partially offsets prior quarter underlift due to logistical management of volumes during the winter and initial line and tank fill at new oil storage facilities.  Going forward, the Company anticipates oil inventories will increase in the second half of 2014 as line fill requirements are satisfied for new pipeline infrastructure being developed in key operating areas. This could result in reduced sales volumes in the third and fourth quarters by an aggregate total of approximately 500,000 net barrels, although such impact may be partially offset by sales of previously stored production throughout the Company's facilities in the Bakken.    

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



2Q


1Q


2Q

Boe per day


2014


2014


2013

North Region:







North Dakota Bakken


94,702


83,725


76,909

Montana Bakken


13,871


13,732


11,081

Red River Units 


14,125


14,140


14,886

Other


961


824


2,141








South Region:







SCOOP


34,265


29,363


17,547

NW Cana


5,223


5,685


7,763

Arkoma


2,599


2,565


3,064

Other 


2,207


2,437


2,309

Total


167,953


152,471


135,700

Bakken Development

Continental's Bakken production totaled 108,573 Boe per day in second quarter 2014, an increase of 11% compared to first quarter 2014 and an increase of 23% compared to second quarter 2013.  The Company participated in completing 93 net (224 gross) wells in the Bakken during second quarter 2014. 

The Company concluded second quarter 2014 with an inventory of approximately 84 gross operated (66 net) Bakken wells drilled, but not yet completed, which is down from 100 gross operated wells at the end of first quarter 2014.  The Company currently expects to complete approximately 870 gross (287 net) wells in the Bakken in full-year 2014, including both operated and non-operated wells. 

Encouraging Results From Enhanced Completions

The Company planned to test enhanced well completion methods across 20% of its Bakken wells in 2014 and the Company has exceeded this goal.  Various tests are ongoing, including combinations of fluid types, increased proppant volumes and shorter stage lengths.  The tests completed to date have yielded encouraging early results.  As an example of the Company's effort in one geological area of the play, three slick water completions resulted in an average early cumulative production increase of 35% higher than the production trend for Continental's 603,000 Boe estimated ultimate recovery ("EUR") model for North Dakota, and 25% higher than the production trend for nearby offsetting wells completed with the Company's standard design.

Additionally, in this same geological area, early production was also stronger for three wells completed with increased proppant volumes, which averaged between 200,000 to 300,000 pounds of proppant per stage.  Early production results were 39% higher than the 603,000 Boe EUR production trend, and 30% higher than the production trend for nearby wells completed with the Company's standard design.

Continental's Bakken team continues to evaluate the performance and overall well economics for its enhanced completion program, which thus far has averaged an additional cost of $1.5 million to $2.0 million per well. 

W. F. "Rick" Bott, Continental's President and Chief Operating Officer commented, "We're pleased with several of the new completion methods we are testing and early results show significant improvements in well performance.  We are studying the broader implications of applying enhanced completions across the play and plan to update the market next month at our Investor & Analyst Day on September 18 in Oklahoma City."

Bakken Density Pilot Project Update

In 2013, the Company embarked on a plan to test different areas across the Bakken field to determine what well density and pattern best maximizes crude oil recovery and returns.  In all, the Company has initiated seven density pilot projects, all designed to include the Middle Bakken ("MB") and Three Forks One, Two and Three ("TF1", "TF2", "TF3") across a broad section of Continental's approximately 1.2 million net acres of leasehold.  Three of these projects are testing 1,320-foot inter-well spacing and four are testing 660-foot inter-well spacing. 

The Hawkinson 1,320-foot pilot project was the first to be completed by the Company and was announced as a fourth quarter 2013 completion, followed by additional 1,320-foot spacing tests at the Rollefstad and Tangsrud units.  The Hawkinson pilot continues to be a strong producer with all of the 14 wells trending on average 50% above the Company's 603,000 Boe EUR model after 190 to 250 producing days.  The Rollefstad pilot is also performing well, with 10 of the 11 wells on the unit producing an average rate that is 10% above the 603,000 Boe EUR model after approximately 60 producing days.  Four wells at the Rollefstad unit are still flowing naturally without the aid of artificial lift.  The Tangsrud pilot was designed to test the extent of the Lower Three Forks productive footprint in the northern portion of the play.  On average the MB and TF1 wells are producing similarly to neighboring wells in the area.  The TF2 and TF3 producers in the Tangsrud pilot continue to underperform offset MB and TF1 producers and do not appear to deliver economic results that compete with the Company's substantial inventory of high rate-of-return development opportunities, based on current technology and cost structure

In late May 2014, the Company began producing its first 660-foot inter-well spacing test at the Wahpeton pilot in McKenzie County, North Dakota.  The new wells were completed using the Company's standard completion design of 30 stages with 100,000 pounds of proppant per stage.  Initial production rates for the 12 new wells in the unit averaged approximately 1,015 Boe per day, which included three new MB wells averaging approximately 1,730 Boe per day.  

Mr. Bott added, "Continental continues to lead the industry in seeking the optimum density and enhanced completions in order to maximize recovery, enhance returns and increase net present value.  It is too early to estimate recoveries at the Wahpeton pilot; however, we are encouraged by the early performance and potential for 660-foot inter-well spacing."

The three remaining pilot projects are 660-foot inter-well spacing tests that are in various stages of drilling or completion.  These include the Mack, Lawrence and Hartman units, which include a combined 18 new wells and six existing producers.  The new wells are expected to be completed in the second half of 2014.

Growth in SCOOP Continues    

Continental continues to deliver solid results from its drilling activity in the South Central Oklahoma Oil Province ("SCOOP").  The play, discovered by Continental and announced in October 2012, currently extends approximately 120 miles across several counties in Oklahoma and contains oil and condensate-rich fairways as delineated by approximately 510 gross industry wells.  Continental operates or has a working interest in approximately 210 wells in the play.  The Company's leasehold position increased by 35,000 net acres during second quarter 2014 to reach a total of approximately 460,000 net acres.    

In second quarter 2014, SCOOP net production averaged 34,265 Boe per day, an increase of 17% sequentially and 95% above second quarter 2013.  The recent growth was driven by the addition of 14 net (19 gross) operated and 2 net (16 gross) non-operated wells during second quarter 2014.    

In SCOOP, Continental's primary focus continues to be exploration and appraisal, as well as drilling to hold acreage by production ("HBP"), with an increasing shift to 1.5 to 2-mile extended lateral wells for superior returns.  Approximately 50% of the Company's current operated well activity consists of extended laterals.  Operated well costs in the play are targeted by year-end 2014 to be approximately $8.7 million for an average 1-mile lateral across the play and approximately $13.5 million for an average 2-mile lateral.

Continental has initiated its first density pilot in the SCOOP play at the Poteet unit in northeast Stephens County.  The pilot will consist of 10 wells, placing five wells in the upper portion of the Woodford and five wells in the lower portion of the Woodford, and spaced approximately 1,000 feet apart within the same zone.  The wells are being drilled from five separate two-well pads and the Company expects production to begin towards the end of the fourth quarter 2014.

In second quarter 2014, average initial one-day test rates from operated wells within the oil fairway of SCOOP included the following:

  • The Kolt 1-17H well in Grady County initially tested at 668 Boe per day (77% oil) from 4,283 feet of completed lateral.  The well had a 30-day average rate of 435 Boe per day and Continental has a 46% working interest in the well; and
  • The Mackey 1-28H well in Garvin County initially tested at 620 Boe per day (70% oil) from 4,195 feet of completed lateral.  The well had a 30-day average rate of 423 Boe per day and Continental has a 94% working interest in the well. 

In second quarter 2014, average initial one-day test rates from operated wells within the condensate fairway of SCOOP included:

  • The Lambakis 2-11-2XH well in Grady County initially tested at 14.0 million cubic feet of natural gas equivalent ("MMcfe") per day, which included 320 barrels of oil from 9,793 feet of completed lateral.  The gas stream is estimated at 1,262 British thermal units per standard cubic foot ("Btu/scf") and had a 30-day average rate of 13.2 MMcfe per day with pipeline limitations.  Continental has a 77% working interest in the well; and 
  • The Goff 1-15-10XH well in Grady County initially tested at 9.3 MMcfe per day, which included 140 barrels of oil from 8,183 feet of completed lateral.  The gas stream is estimated at 1,231 Btu/scf and had a 30-day average rate of 8.8 MMcfe per day with pipeline limitations.  Continental has a 65% working interest in the well.   

Mid-Year 2014 Proved Reserve Update

Continental estimates mid-year 2014 proved reserves of 1.2 billion Boe, an increase of 11% from year-end 2013, based on internal estimates.  The PV-10 value of proved reserves is estimated at $23.4 billion, up 16% from $20.2 billion at year-end 2013 and up 76% from $13.3 billion at year-end 2012.

Financial Update

Continental's average realized sales price excluding the effects of derivative positions was $92.31 per barrel of oil and $5.43 per thousand cubic feet of natural gas ("Mcf"), or $74.09 per Boe for second quarter 2014.  Settlements of matured commodity derivative positions generated a $4.87 loss per barrel of oil and $0.43 loss per Mcf of natural gas, resulting in a net loss on matured derivatives of $64.1 million, or $4.18 per Boe for the second quarter 2014.  Based on realizations without the effect of derivatives, the Company's second quarter 2014 oil differential was $10.69 per barrel below the NYMEX daily average for the period.  The realized natural gas price differential for second quarter 2014 was a positive $0.76 per Mcf, unfavorably outside the Company's annual guidance due to weaker than expected natural gas liquids prices, however year-to-date within guidance.    

Production expense per Boe was $5.50 for second quarter 2014.  Other select operating costs and expenses for second quarter 2014 included production taxes of 8.3% of oil and natural gas sales; DD&A of $21.28 per Boe; and G&A (cash and non-cash) of $3.06 per Boe.  Year-to-date, the Company's DD&A rate per Boe is above annual guidance due to exploratory efforts designed to expand the extent of both the Bakken and SCOOP fields and incremental costs associated with enhanced completions and larger density pilots, both of which have limited production history at this point.

Non-acquisition capital expenditures for second quarter 2014 totaled approximately $1,091 million, including $980 million in exploration and development drilling, $66 million in leasehold and seismic and $45 million in facilities, workovers, recompletions and other.  Acquisition capital expenditures totaled approximately $41 million for second quarter 2014. 

In second quarter 2014, the Company executed a new 5-year unsecured credit facility with $1.75 billion of commitments.  The Company also issued $1.0 billion of 3.8% senior notes due 2024 and $700 million of 4.9% senior notes due 2044.  This is the Company's first debt issuance since being upgraded to investment grade in late 2013.   

As of June 30, 2014, Continental's balance sheet included approximately $777 million in cash and cash equivalents and no borrowings against the Company's revolving credit facility.  On July 11, 2014, the Company's cash balance was reduced by $324 million to redeem all of its outstanding 8.25% senior notes due 2019.

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.   

 


2Q 2014


1Q 2014


2Q 2013

Average daily production:






Crude oil (Bbl per day)

116,441


106,398


96,029

Natural gas (Mcf per day)

309,074


276,439


238,028

Crude oil equivalents (Boe per day)

167,953


152,471


135,700

Average sales prices, excluding effect from derivatives:






Crude oil ($/Bbl)

$92.31


$89.73


$87.22

Natural gas ($/Mcf)

$5.43


$7.06


$4.87

Crude oil equivalents ($/Boe)

$74.09


$75.03


$70.52

Production expenses ($/Boe) 

$5.50


$5.76


$5.86

Production taxes (% of oil and gas revenues)

8.3%


7.7%


8.4%

DD&A ($/Boe)

$21.28


$20.43


$18.88

General and administrative expenses ($/Boe) 

$2.08


$2.43


$2.08

Non-cash equity compensation ($/Boe)

$0.98


$0.83


$0.78

Net income (in thousands) 

$103,538


$226,234


$323,270

Diluted net income per share

$0.56


$1.22


$1.75

Adjusted net income (in thousands) (1) 

$277,143


$272,297


$245,728

Adjusted diluted net income per share (1) 

$1.50


$1.47


$1.33

EBITDAX (in thousands) (1)

$867,938


$775,407


$708,107



(1)

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 second quarter 2014 results on Wednesday, August 6, 2014 at 12 p.m. ET (11 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:

12 p.m. ET, Wednesday, August 6, 2014

Dial in:

888 895 5271

Intl. dial in: 

847 619 6547

Pass code:

37638923

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

Replay number:

888 843 7419

Intl. replay 

630 652 3042

Pass code:

37638923

Continental plans to publish a second quarter 2014 supplement presentation to its website at www.CLR.com prior to the start of its earnings conference call on August 6, 2014. 

Upcoming Conference and the CLR 2014 Investor & Analyst Day 

Members of Continental's management team will be participating in the following upcoming investment conference and Company hosted event:

August 20, 2014

Enercom Oil & Gas Conference, Denver, CO



September 18, 2014 

CLR 2014 Investor & Analyst Day, Oklahoma City, OK

Enercom conference materials will be available on the Company's website at www.CLR.com on or prior to the day of the presentation. 

Continental will hold its 2014 Investor & Analyst Day meeting on Thursday, September 18, 2014 at 8:00 a.m. Central time in Oklahoma City, Oklahoma. The event and presentation materials will be available to the public via internet webcast and by posting on the Company's website at www.CLR.com. A link to the webcast will be accessible from the Company's website on the date of the event. A link to presentation materials will be accessible from the Company's website the evening prior to the date of the event or on the date of the event prior to 8:00 a.m. Central time.

Individuals interested in attending the Company's 2014 Investor & Analyst Day will find a registration link on the Company's homepage at www.CLR.com.

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 2014, the Company will celebrate 47 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, 2013, 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, completion and production equipment and services and transportation infrastructure, environmental risks, drilling and other operating risks, lack of availability and security of computer-based systems, 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, 2013, 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.

Investor Contact: 

Media Contact:

John Kilgallon  

Kristin Miskovsky

Vice President, Investor Relations 

Vice President, Public Relations

405-234-9330 

405-234-9480

John.Kilgallon@CLR.com

Kristin.Miskovsky@CLR.com

 

Continental Resources, Inc.
Unaudited Condensed Consolidated Statements of Income



Three months ended June 30,


Six months ended June 30,


2014


2013


2014


2013

Revenues:

In thousands, except per share data

Crude oil and natural gas sales

$

1,138,085


$

884,492


$

2,140,418


$

1,660,423

Gain (loss) on derivative instruments, net


(262,524)



199,056



(302,198)



114,225

Crude oil and natural gas service operations


10,534



9,509



20,370



21,052

Total revenues


886,095



1,093,057



1,858,590



1,795,700













Operating costs and expenses:












Production expenses


84,521



73,452



161,407



135,255

Production taxes and other expenses


97,025



74,541



175,327



139,384

Exploration expenses


11,205



11,151



16,018



20,965

Crude oil and natural gas service operations


5,979



7,317



14,053



15,914

Depreciation, depletion, amortization and accretion


326,871



236,790



599,732



450,468

Property impairments


79,316



79,712



137,524



119,793

General and administrative expenses 


46,919



35,873



90,455



69,690

(Gain) loss on sale of assets, net


(2,135)



349



6,363



213

Total operating costs and expenses


649,701



519,185



1,200,879



951,682

Income from operations


236,394



573,872



657,711



844,018

Other income (expense):












Interest expense


(72,841)



(61,378)



(135,816)



(108,853)

Other 


793



634



1,552



1,180



(72,048)



(60,744)



(134,264)



(107,673)

Income before income taxes


164,346



513,128



523,447



736,345

Provision for income taxes


60,808



189,858



193,675



272,448

Net income

$

103,538


$

323,270


$

329,772


$

463,897

Basic net income per share

$

0.56


$

1.76


$

1.79


$

2.52

Diluted net income per share

$

0.56


$

1.75


$

1.78


$

2.51

 

 


Continental Resources, Inc.
Unaudited Condensed Consolidated Balance Sheets



June 30, 2014


December 31, 2013

Assets

In thousands

Current assets

$

2,123,036


$

1,147,266

Net property and equipment (1)


12,166,106



10,721,272

Other noncurrent assets


88,364



72,644

Total assets

$

14,377,506


$

11,941,182







Liabilities and shareholders' equity






Current liabilities (2) 

$

2,129,142


$

1,473,156

Long-term debt


5,832,872



4,713,821

Other noncurrent liabilities


2,111,231



1,801,087

Total shareholders' equity


4,304,261



3,953,118

Total liabilities and shareholders' equity

$

14,377,506


$

11,941,182








(1)

 Balance is net of accumulated depreciation, depletion and amortization of $3.65 billion and $3.12 billion as of June 30, 2014 and December 31, 2013, respectively.

(2)

 Balance at June 30, 2014 includes the $298.4 million carrying amount of the Company's 8.25% senior notes due 2019 that were redeemed on July 11, 2014.

 

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




Three months ended June 30, 


Six months ended June 30, 

In thousands


2014


2013


2014


2013

Net income 


$

103,538


$

323,270


$

329,772


$

463,897

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













Non-cash expenses



682,359



310,090



1,180,698



739,003

Changes in assets and liabilities



(44,106)



65,474



(78,017)



(45,955)

Net cash provided by operating activities



741,791



698,834



1,432,453



1,156,945

Net cash used in investing activities



(1,057,807)



(977,024)



(2,077,287)



(1,850,177)

Net cash provided by financing activities



1,041,444



440,057



1,393,315



877,916

Net change in cash and cash equivalents



725,428



161,867



748,481



184,684

Cash and cash equivalents at beginning of period



51,535



58,546



28,482



35,729

Cash and cash equivalents at end of period


$

776,963


$

220,413


$

776,963


$

220,413

Non-GAAP Financial Measures

EBITDAX

We use a variety of financial and operational measures to assess our performance. Among these measures is 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. Further, 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. 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.

The following table provides a reconciliation of our net income to EBITDAX for the periods presented.

In thousands



2Q 2014



1Q 2014


2Q 2013

Net income


$

103,538


$

226,234


$

323,270

Interest expense



72,841



62,975



61,378

Provision for income taxes



60,808



132,867



189,858

Depreciation, depletion, amortization and accretion



326,871



272,861



236,790

Property impairments



79,316



58,208



79,712

Exploration expenses



11,205



4,813



11,151

Impact from derivative instruments:










Total (gain) loss on derivatives, net



262,524



39,674



(199,056)

Total cash paid on derivatives, net



(64,143)



(33,264)



(4,752)

Non-cash loss on derivatives, net



198,381



6,410



(203,808)

Non-cash equity compensation



14,978



11,039



9,756

EBITDAX


$

867,938


$

775,407


$

708,107











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







In thousands



2Q 2014



1Q 2014


2Q 2013

Net cash provided by operating activities


$

741,791


$

690,662


$

698,834

Current income tax provision



1,552



1,552



5,830

Interest expense



72,841



62,975



61,378

Exploration expenses, excluding dry hole costs



6,822



4,813



5,349

Gain (loss) on sale of assets, net



2,135



(8,498)



(349)

Other, net



(1,309)



(10,008)



2,539

Changes in assets and liabilities



44,106



33,911



(65,474)

EBITDAX


$

867,938


$

775,407


$

708,107

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.









2Q 2014


1Q 2014


2Q 2013

In thousands, except per share data


After-Tax $


Diluted
EPS


After-Tax $


Diluted
EPS


After-Tax $


Diluted
EPS

Net income (GAAP)


$  103,538


$  0.56


$  226,234


$  1.22


$ 323,270


$ 1.75

Adjustments, net of tax:














Non-cash (gain) loss on derivatives, net


124,981


0.68


4,038


0.02


(128,399)


(0.69)


Property impairments


49,969


0.27


36,671


0.20


50,219


0.27


(Gain) loss on sale of assets, net


(1,345)


(0.01)


5,354


0.03


220


-


Corporate relocation expenses


-


-


-


-


418


-



Adjusted net income (Non-GAAP)


$  277,143


$  1.50


$  272,297


$  1.47


$ 245,728


$ 1.33



Weighted average diluted shares outstanding


185,167




185,028




184,739





Adjusted diluted net income per share (Non-GAAP)


$        1.50




$        1.47




$      1.33



 

 

SOURCE Continental Resources



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