Continental Resources Reports Fourth Quarter 2013 And Full-Year Results Fourth Quarter Adjusted Net Income Totals $228.1 Million, or $1.23 per Diluted Share

Fourth Quarter EBITDAX of $712 Million Brings Full-Year 2013 EBITDAX to Record $2.84 Billion

Strong Early Performance of Hawkinson Density Pilot Wells

2014 Production on Track for 26% to 32% Growth in 2014

OKLAHOMA CITY, Feb. 26, 2014 /PRNewswire/ -- Continental Resources, Inc. (NYSE: CLR) ("Continental" or the "Company") today announced fourth quarter and full-year 2013 operating and financial results.  Net income for the quarter ended December 31, 2013 was $132.8 million, or $0.72 per diluted share, compared with net income of $220.5 million, or $1.19 per diluted share, for the fourth quarter of 2012.  Excluding items typically excluded from published analyst estimates, adjusted net income for the fourth quarter of 2013 was $228.1 million, or $1.23 per diluted share, a 19% increase over adjusted net income of $191.8 million, or $1.04 per diluted share, for the fourth quarter of 2012.

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

Net income for full-year 2013 was $764.2 million, or $4.13 per diluted share, compared with net income of $739.4 million, or $4.07 per diluted share, for full-year 2012.  Excluding items typically excluded from published analyst estimates, adjusted net income for full-year 2013 was $986.1 million, or $5.33 per diluted share, a 61% increase over adjusted net income of $611.9 million, or $3.36 per diluted share, for full-year 2012.

EBITDAX for the fourth quarter of 2013 was $712 million, a 20% increase over EBITDAX of $595 million for the fourth quarter of 2012.  Full-year 2013 EBITDAX was a record $2.84 billion, a 45% increase over EBITDAX of $1.96 billion for full-year 2012.  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.

"Our teams performed at an exceptional level in 2013, achieving our key growth targets for the initial year in our five-year plan to triple production and proved reserves," said Harold G. Hamm, Chairman and Chief Executive Officer.   "The foundation of our plan is an unmatched inventory of oil and liquid-rich assets in the Bakken play of North Dakota and Montana and in the South Central Oklahoma Oil Province, or SCOOP.  Our goal is to deliver exceptional production growth and cash margins, while maintaining a strong, conservative balance sheet.  Both S&P and Moody's upgraded the Company to investment grade in the second half of 2013, clear evidence we are generating growth while maintaining financial strength and discipline."

Fourth quarter and full-year 2013 highlights included:

  • Achieved the Company's original 2013 production and capital expenditures targets;
  • Record proved reserves of 1.08 billion barrels of oil equivalent ("Boe") as of December 31, 2013, a 38% increase over year-end 2012 and a compounded annual growth of 47% since year-end 2008; and
  • Record fourth quarter 2013 production of 144,254 Boe per day, a 35% increase over the fourth quarter of 2012.

Production

Fourth quarter 2013 Company net production totaled 13.3 million Boe, or 144,254 Boe per day, a sequential increase of 2% from third quarter 2013 and 35% higher than fourth quarter 2012.  Total net production included approximately 100,400 barrels of oil per day (70% of production) and approximately 263 million cubic feet of natural gas per day (30% of production).  In the fourth quarter 2013, the Company sold its operated natural gas production prior to processing based upon pricing provisions in its natural gas contracts.  The Company estimates 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 for fourth quarter 2013.

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



4Q


3Q


4Q

Boe per day


2013


2013


2012

North Region:







North Dakota Bakken


80,374


81,545


59,019

Montana Bakken


12,961


12,957


8,503

Red River Units 


14,398


14,703


14,716

Other


812


408


967








South Region:







SCOOP


23,754


20,070


7,123

NW Cana


6,696


6,985


9,716

Arkoma


2,769


3,004


3,225

Other 


2,490


2,201


2,556

East Region


-


-


1,006

Total


144,254


141,873


106,831

Bakken Development

Continental's Bakken production totaled 93,335 Boe per day in the fourth quarter of 2013, essentially flat compared to third quarter 2013 and an increase of 38% compared to fourth quarter 2012.  Base production and growth, including operated and non-operated production, were adversely affected by winter weather conditions in the quarter, especially during December 2013.   As a result, Continental currently has approximately 110 gross wells that have been drilled but are awaiting completion or infrastructure in the Bakken.  This is approximately 35 gross wells above the Company's typical run rate level of activity.  The Company has added additional third-party completion services in order to reduce the inventory and expedite initial production of recent drilled wells. 

The Company plans to complete approximately 287 net (870 gross) wells in the Bakken in 2014, including both operated and non-operated wells, and is subject to change.  The Company operated 20 rigs in the play in fourth quarter 2013 and anticipates operating an average rig count of 22 throughout 2014.  Continental's average operated well costs in the Bakken continue to trend lower.  Fourth quarter 2013 operated Bakken well costs were approximately $8.0 million per well.  The Company is targeting even lower well costs with a goal of $7.5 million per operated Bakken well by year-end 2014 for its typical completion design.  As previously indicated, Continental plans to test several different completion design techniques on approximately 20% of its Bakken completions in 2014 to evaluate possible performance enhancements.  Projected capital expenditures for the Northern region, which includes the Bakken and the Red River units, are approximately $2.9 billion for 2014. 

Bakken Density and Productivity Update: The Hawkinson Unit

In North Dakota during October 2013, Continental successfully completed the first pilot density project at the Hawkinson unit in Dunn County.  The 14 individual wells within the unit tested at a combined rate of 14,850 Boe per day, which included three existing producing wells.  The project included four Middle Bakken, three TF1 (Three Forks 1), four TF2 and three TF3 wells spaced 1,320 feet apart in the same zone and offset 660 feet in the adjacent zones.

Based on the first 120 days of production, 12 of the 14 wells on the Hawkinson unit are performing very well and average production is trending 50% above the Company's 603,000 Boe estimated ultimate recovery ("EUR") model for a typical North Dakota Bakken well.  The two exception wells are in the TF3 zone and were recently put on pump. They are producing on trend just below the 603,000 Boe EUR model, but improving.  Given the limited amount of production history, these trends could change over time.  Continental has an approximate 55% working interest in the Hawkinson Unit.   

W. F. "Rick" Bott, Continental's President and Chief Operating Officer, commented, "The Hawkinson project has been a huge success and the culmination of efforts across the entire company – geology, micro-seismic, drilling, completions, surface logistics and marketing, to name a few.  This is a landmark event for our Company and the industry – unique production from four different producing intervals and spaced 1,320 feet apart.  This first test validates our vision for full-field development of the Bakken and the vast resource potential across our acreage position."   

In addition to the Hawkinson project, Continental has three other density pilot tests in North Dakota which the Company began drilling in 2013, including wells in the Middle Bakken, TF1, TF2 and TF3.  The Tangsrud project in Divide County is a 1,320 feet inter-well spacing test including 12 new wells.  Ten of the wells are currently beginning the initial flowback stage and the two remaining wells should commence production by early March.  The Rollefstad project in eastern McKenzie County involves 11 new wells drilled with 1,320 feet same zone inter-well spacing, similar to the Hawkinson and Tangsrud.  Completion activities are in progress at the Rollefstad unit, including well clean out and tubing installation and full production is expected in late March.  The Wahpeton density pilot in western McKenzie County involves 13 new wells configured in four zones at increased density spacing of 660 feet inter-well spacing.  Full unit production startup is expected in early May.  The original completion schedule for the Tangsrud, Rollefstad and Wahpeton units was delayed due to challenging weather conditions.  During 2014, Continental has begun drilling three additional density pilots to test 660 feet inter-well spacing at the Lawrence, Mack and Hartman units, which include 18 new wells and six existing producers.  

Antelope "Ears Back" Program Update

Continental announced in November 2013 the Company would begin its first full-field development in the Bakken, including the deeper Three Forks benches, in McKenzie and Mountrail counties in the Antelope area and plans to drill between 350 to 400 gross wells over the next five years.  The area was selected due to the Company's large operated footprint and historical results that are among the Company's highest rates of return.  Continental currently has three rigs running in the Antelope area and has 18 wells in various stages of drilling or completion. 

Growth in SCOOP Continues    

Continental continues to deliver excellent, repeatable 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 450 gross industry wells.  Continental currently operates or has a working interest in approximately 155 wells across its approximately 400,000 net acres of leasehold in the play. 

In fourth quarter 2013, SCOOP net production averaged approximately 23,750 Boe per day, an increase of 18% sequentially and 233% above fourth quarter 2012.  The recent growth was driven by the addition of 12 net (23 gross) operated and non-operated wells in the play during the fourth quarter 2013.    

In SCOOP, Continental's primary focus continues to be exploration, appraisal and drilling to hold acreage (HBP), with an increasing shift to 2-mile lateral wells.  The Company operated an average of 14 rigs during fourth quarter 2013 and plans to average 18 operated rigs in the play in 2014, with 40% of the activity on 2-mile lateral wells.  Well costs in the play are targeted by year-end 2014 to be approximately $8.7 million for a standard 1-mile lateral across the play within the exploration program and approximately $13.5 million for a 2-mile lateral.  Continental plans a number of spacing tests and one density pilot in 2014.  Continental projects capital expenditures of approximately $1.1 billion in the Southern region in 2014, which includes SCOOP and other areas.   

In fourth quarter 2013, average initial one-day test rates from operated and non-operated wells within the oil and condensate fairways of SCOOP were approximately 1,300 boe per day. 

Financial Update and Guidance

Continental's average realized sales price excluding the effects of derivative positions was $84.47 per barrel of oil and $5.49 per thousand cubic feet of natural gas ("Mcf"), or $68.80 per Boe for fourth quarter 2013.  Settlements of matured commodity derivative positions generated a $1.05 loss per barrel of oil resulting in a net loss on matured derivatives of $9.6 million, or $0.73 per Boe for the fourth quarter 2013.  Based on realizations without the effect of derivatives, the Company's fourth quarter 2013 oil differential was $13.05 per barrel below the NYMEX daily average for the period.  The realized natural gas price differential for fourth quarter 2013 was a positive $1.88 per Mcf.  Full-year 2013 realized differential without the effect of derivatives was a negative $8.23 per barrel of oil and a positive $1.59 per Mcf as compared to the NYMEX daily averages for the year.  Full-year 2013 oil differential was above the Company's guidance estimate due to fourth quarter price volatility, while natural gas differential was better than guidance.     

Production expense per Boe was $6.03 for fourth quarter 2013, an increase from third quarter 2013 due to increased costs and lower volumes due to weather conditions.  Other select operating costs and expenses for fourth quarter 2013 included production taxes of 8.1% of oil and natural gas sales; DD&A of $20.40 per Boe; and G&A (cash and non-cash, excluding relocation expenses) of $3.06 per Boe.  On a full-year basis, these expense categories were within the Company's full-year guidance.  

As of December 31, 2013, Continental's balance sheet included approximately $28 million in cash and cash equivalents and $275 million of borrowings against the Company's $1.5 billion credit facility.  During fourth quarter 2013, Moody's Investor Services upgraded the Company's senior unsecured rating to investment grade status of Baa3, up from Ba2.

Non-acquisition capital expenditures for fourth quarter 2013 totaled approximately $868 million, including $766 million in exploration and development drilling, $62 million in leasehold and seismic and $40 million in workovers, recompletions and other.  Acquisition capital expenditures totaled approximately $71 million for fourth quarter 2013.  Full-year 2013 non-acquisition capital expenditures totaled approximately $3.574 billion, just below guidance.  Acquisition spending totaled approximately $268 million for the year.

Continental's 2014 guidance remains unchanged as originally disclosed on September 10, 2013, which includes organic production growth of 26% to 32% with a capital budget of $4.05 billion.  A table with the Company's full 2014 guidance, which includes differentials and select cost elements, can be found at the conclusion of this release. 

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.  

 


Three months ended December 31,


Year ended December 31,


2013


2012


2013


2012

Average daily production:








Crude oil (Bbl per day)

100,443


76,449


95,859


68,497

Natural gas (Mcf per day)

262,866


182,289


240,355


174,521

Crude oil equivalents (Boe per day)

144,254


106,831


135,919


97,583

Average sales prices, excluding effect from derivatives:







Crude oil ($/Bbl)

$84.47


$84.99


$89.93


$84.59

Natural gas ($/Mcf)

$5.49


$4.82


$5.25


$4.20

Crude oil equivalents ($/Boe)

$68.80


$68.89


$72.71


$66.83

Production expenses ($/Boe) 

$6.03


$5.90


$5.69


$5.49

Production taxes (% of oil and gas revenues)

8.1%


8.3%


8.2%


8.2%

DD&A ($/Boe)

$20.40


$19.76


$19.47


$19.44

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

$2.27


$2.70


$2.07


$2.38

Non-cash equity compensation ($/Boe)

$0.79


$0.85


$0.80


$0.82

Net income (in thousands) 

$132,824


$220,511


$764,219


$739,385

Diluted net income per share

$0.72


$1.19


$4.13


$4.07

Adjusted net income (in thousands) (2) 

$228,132


$191,801


$986,125


$611,870

Adjusted diluted net income per share (2) 

$1.23


$1.04


$5.33


$3.36

EBITDAX (in thousands) (2)

$712,300


$594,452


$2,839,510


$1,963,123



(1)

General and administrative expenses ($/Boe) exclude non-recurring corporate relocation expenses of $0.2 million ($0.01 per Boe) for the three months ended December 31, 2013 and $0.5 million ($0.05 per Boe) for the three months ended December 31, 2012. For the year ended December 31, 2013, general and administrative expenses exclude non-recurring corporate relocation expenses of $1.6 million ($0.04 per Boe) and $7.8 million ($0.22 per Boe) for the same period in 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 fourth quarter and full-year 2013 results on Thursday, February 27, 2014 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, February 27, 2014

Dial in:

800 708 4539

Intl. dial in:

847 619 6396

Pass code:

36590660

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:

36590660

Continental plans to publish a fourth quarter and full-year 2013 summary presentation to its website at www.CLR.com prior to the start of its earnings conference call on February 27, 2014. 

Upcoming Conferences

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

March 3, 2014

Raymond James Institutional Investors Conference: Orlando

March 5, 2014

Barclays Investment Grade Energy & Pipeline Conference: New York

March 26, 2014

Howard Weil 42nd Annual Energy Conference: New Orleans

The Company's presentation at the Raymond James conference will be available via webcast and a replay 30 days thereafter.  Instructions regarding how to access the live and replay webcast for the Raymond James presentation and presentation materials for all conferences mentioned above 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 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 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, 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.

CONTACTS: Continental Resources, Inc.           


Investors:

Media:

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



Warren Henry


Vice President, Research and Policy


405-234-9127

Waren.Henry@CLR.com


 

Continental Resources, Inc.  

Consolidated Statements of Income  












(Unaudited)









Three months ended December 31,


 Year ended December 31,



2013


2012


2013


2012

Revenues:


In thousands, except per share data

Crude oil and natural gas sales

$

912,286


$

670,438


$

3,606,774


$

2,379,433

Gain (loss) on derivative instruments, net


(102,202)



9,639



(191,751)



154,016

Crude oil and natural gas service operations


10,250



8,895



40,127



39,071

Total revenues


820,334



688,972



3,455,150



2,572,520













Operating costs and expenses:












Production expenses


79,892



57,399



282,197



195,440

Production taxes and other expenses


84,183



65,558



332,130



228,438

Exploration expenses


5,809



5,755



34,947



23,507

Crude oil and natural gas service operations


7,097



7,525



29,665



32,248

Depreciation, depletion, amortization and accretion


270,456



192,271



965,645



692,118

Property impairments


58,548



29,121



220,508



122,274

General and administrative expenses 


40,619



35,031



144,379



121,735

Gain (loss) on sale of assets, net


24



(68,908)



(88)



(136,047)

Total operating costs and expenses


546,628



323,752



2,009,383



1,279,713

Income from operations


273,706



365,220



1,445,767



1,292,807

Other income (expense):












Interest expense


(63,666)



(45,534)



(235,275)



(140,708)

Other 


792



817



2,557



3,097



(62,874)



(44,717)



(232,718)



(137,611)

Income before income taxes


210,832



320,503



1,213,049



1,155,196

Provision for income taxes


78,008



99,992



448,830



415,811

Net income

$

132,824


$

220,511


$

764,219


$

739,385

Basic net income per share

$

0.72


$

1.20


$

4.15


$

4.08

Diluted net income per share

$

0.72


$

1.19


$

4.13


$

4.07

 

 

Continental Resources, Inc.  

Consolidated Balance Sheets  






December 31,


December 31,


2013


2012

Assets

In thousands

Current assets

$

1,147,266


$

946,783

Net property and equipment (1)


10,721,272



8,105,269

Other noncurrent assets


72,644



87,957

Total assets

$

11,941,182


$

9,140,009







Liabilities and shareholders' equity






Current liabilities

$

1,473,156


$

1,125,865

Long-term debt


4,713,821



3,537,771

Other noncurrent liabilities


1,801,087



1,312,674

Total shareholders' equity


3,953,118



3,163,699

Total liabilities and shareholders' equity

$

11,941,182


$

9,140,009

(1)

Balance is net of accumulated depreciation, depletion and amortization of $3.12 billion and $2.12 billion as of December 31, 2013 and 2012, respectively.


Continental Resources, Inc.  

Consolidated Statements of Cash Flows  












(Unaudited)









Three months ended December 31, 



Year ended December 31, 

In thousands


2013


2012


2013


2012

Net income 


$

132,824


$

220,511


$

764,219


$

739,385

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













Non-cash expenses



512,189



223,804



1,809,951



905,695

Changes in assets and liabilities



(60,171)



39,853



(10,875)



(13,015)

Net cash provided by operating activities



584,842



484,168



2,563,295



1,632,065

Net cash used in investing activities



(911,623)



(1,312,243)



(3,711,011)



(3,903,370)

Net cash provided by financing activities



263,756



604,359



1,140,469



2,253,490

Net change in cash and cash equivalents



(63,025)



(223,716)



(7,247)



(17,815)

Cash and cash equivalents at beginning of period



91,507



259,445



35,729



53,544

Cash and cash equivalents at end of period


$

28,482


$

35,729


$

28,482


$

35,729















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.



Three months ended December 31,


Year ended December 31, 

In thousands


2013


2012


2013


2012

Net income


$

132,824


$

220,511


$

764,219


$

739,385

Interest expense



63,666



45,534



235,275



140,708

Provision for income taxes



78,008



99,992



448,830



415,811

Depreciation, depletion, amortization and accretion



270,456



192,271



965,645



692,118

Property impairments



58,548



29,121



220,508



122,274

Exploration expenses



5,809



5,755



34,947



23,507

Impact from derivative instruments:













Total (gain) loss on derivatives, net



102,202



(9,639)



191,751



(154,016)

Total cash (paid) received on derivatives, net



(9,644)



2,655



(61,555)



(45,721)

Non-cash (gain) loss on derivatives, net



92,558



(6,984)



130,196



(199,737)

Non-cash equity compensation



10,431



8,252



39,890



29,057

EBITDAX


$

712,300


$

594,452


$

2,839,510


$

1,963,123



























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













Three months ended December 31,


Year ended December 31, 

In thousands


2013


2012


2013


2012

Net cash provided by operating activities


$

584,842


$

484,168


$

2,563,295


$

1,632,065

Current income tax provision (benefit)



(4,014)



18,241



6,209



10,517

Interest expense



63,666



45,534



235,275



140,708

Exploration expenses, excluding dry hole costs



5,639



5,307



25,597



22,740

Gain (loss) on sale of assets, net



(24)



68,908



88



136,047

Excess tax benefit from stock-based compensation



-



15,618



-



15,618

Other, net



2,020



(3,471)



(1,829)



(7,587)

Changes in assets and liabilities



60,171



(39,853)



10,875



13,015

EBITDAX


$

712,300


$

594,452


$

2,839,510


$

1,963,123

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. 









Three Months Ended December 31,









2013


2012

In thousands, except per share data


After-Tax $


Diluted EPS


After-Tax $


Diluted EPS

Net income (GAAP)


$ 132,824


$         0.72


$ 220,511


$         1.19

Adjustments, net of tax:










Non-cash (gain) loss on derivatives, net


58,312


0.31


(4,331)


(0.02)


Property impairments


36,885


0.20


18,054


0.10


(Gain) loss on sale of assets, net


15


-


(42,723)


(0.23)


Corporate relocation expenses


96


-


290


-



Adjusted net income (Non-GAAP)


$ 228,132


$         1.23


$ 191,801


$         1.04



Weighted average diluted shares outstanding


185,007




184,603





Adjusted diluted net income per share (Non-GAAP)


$       1.23




$       1.04









































Year Ended December 31,









2013


2012

In thousands, except per share data


After-Tax $


Diluted EPS


After-Tax $


Diluted EPS

Net income (GAAP)


$ 764,219


$         4.13


$ 739,385


$         4.07

Adjustments, net of tax:










Non-cash (gain) loss on derivatives, net


82,023


0.44


(123,838)


(0.68)


Property impairments


138,920


0.75


75,810


0.41


(Gain) loss on sale of assets, net


(55)


-


(84,349)


(0.46)


Corporate relocation expenses


1,018


0.01


4,862


0.02



Adjusted net income (Non-GAAP)


$ 986,125


$         5.33


$ 611,870


$         3.36



Weighted average diluted shares outstanding


184,849




181,846





Adjusted diluted net income per share (Non-GAAP)


$       5.33




$       3.36



 

Continental Resources, Inc.

2014 Guidance Outlook

As of February 26, 2014*








2014





Production growth (YOY)



26% to 32%

Capital expenditures (non-acquisition)



$4.05B





Operating Expenses:




     Production expense per Boe



$5.60 to $6.10

     Production tax (% of oil & gas revenue)



8% to 9%

     DD&A per Boe



$17.50 to $19.50

     G&A expense per Boe



$2.00 to $2.50

     Non-cash equity compensation per Boe



$0.70 to $0.90





Average Price Differentials:




     NYMEX WTI crude oil (per barrel of oil)



($8.00) to ($11.00)

     Henry Hub natural gas (per Mcf)



+$1.00 to $1.50





Income tax rate



37%

Deferred taxes



 90% to 95%





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

SOURCE Continental Resources



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