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Continental Resources Reports Fourth Quarter 2014 and Full-Year 2014 Results
Fourth Quarter Adjusted Net Income Totals $420.8 Million, or $1.14 per Diluted Share
Fourth Quarter EBITDAX of $1.19 Billion Brings Full-Year 2014 EBITDAX to $3.78 Billion

OKLAHOMA CITY, Feb. 24, 2015 /PRNewswire/ -- Continental Resources, Inc. (NYSE: CLR) ("Continental" or the "Company") today announced fourth quarter and full-year 2014 operating and financial results.  Net income for the quarter ended December 31, 2014 was $114.0 million, or $0.31 per diluted share, compared with net income of $132.8 million, or $0.36 per diluted share, for the fourth quarter of 2013.  Excluding items typically excluded from published analyst estimates, adjusted net income for the fourth quarter of 2014 was $420.8 million, or $1.14 per diluted share, an 84% increase over adjusted net income of $228.1 million, or $0.62 per diluted share, for the fourth quarter of 2013.

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Net income for full-year 2014 was $977.3 million, or $2.64 per diluted share, compared with net income of $764.2 million, or $2.07 per diluted share, for full-year 2013.  Excluding items typically excluded from published analyst estimates, adjusted net income for full-year 2014 was $1.27 billion, or $3.43 per diluted share, a 29% increase over adjusted net income of $986.1 million, or $2.67 per diluted share, for full-year 2013.

EBITDAX for the fourth quarter of 2014 was $1.19 billion, a 66% increase over EBITDAX of $712 million for the fourth quarter of 2013.  Full-year 2014 EBITDAX was a record $3.78 billion, a 33% increase over EBITDAX of $2.84 billion for full-year 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.

"We concluded 2014 with a strong fourth quarter performance, capping off another year of exceptional production and proved reserves growth," commented Harold G. Hamm, Continental's Chairman and Chief Executive Officer.  "Looking ahead, our 2015 budget targets cash flow neutrality in the second half of the year.  Given the quality of our assets and our operational flexibility, we are well on our way to achieving this balance of growth and value-creation in the current environment. We believe that our momentum coming out of 2014 will allow us to grow our production 16% to 20% this year; however, we are deferring completions in the Bakken to minimize the volumes we sell into this low price environment. As oilfield service costs align with commodity prices and as the contango in the oil market is realized, we will bring additional production online."

Production

Fourth quarter 2014 net production totaled 17.8 million Boe, or 193,456 Boe per day, a sequential increase of 6% from third quarter 2014 and 34% higher than fourth quarter 2013.  Total net production for the fourth quarter included 136,972 barrels of oil per day (71% of production) and approximately 338.9 million cubic feet of natural gas per day (29% of production).  Full-year 2014 production averaged 174,189 Boe per day, an increase of 28% compared to full-year 2013.  SCOOP volumes accounted for 20% of the total full-year 2014 volumes, up from 14% of the total full-year 2013 volumes.    

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



4Q


3Q


4Q


FY


FY

Boe per day


2014


2014


2013


2014


2013

North Region:











North Dakota Bakken


115,137


106,224


80,374


100,050


76,649

Montana Bakken


15,646


15,380


12,961


14,665


11,602

Red River Units 


13,259


13,749


14,398


13,815


14,759

Other


690


725


812


800


1,164

South Region:











SCOOP


40,403


36,346


23,754


35,128


18,932

NW Cana (1)


3,780


4,957


6,696


4,906


7,436

Arkoma


2,318


2,494


2,769


2,493


3,017

Other 


2,223


2,460


2,490


2,332


2,360

Total


193,456


182,335


144,254


174,189


135,919


(1)

NW Cana volumes decreased sequentially in the 2014 fourth quarter by approximately 1,000 Boe per day due to the Company's 9/30/14 sale of 49.9% of its interest in certain wells under the Company's new joint development agreement with SK.

Bakken Development

Continental's Bakken production averaged 130,783 Boe per day in the fourth quarter of 2014, an increase of 8% compared to third quarter 2014 and an increase of 40% compared to fourth quarter 2013.  For full-year 2014, Bakken production averaged 114,715 Boe per day, an increase of 30% compared to 2013.  The Company completed 72 net (234 gross) operated and non-operated Bakken wells during fourth quarter 2014 and 312 net (921 gross) operated and non-operated Bakken wells for full-year 2014. The Company operated an average of 23 rigs in the Bakken field during fourth quarter 2014.  As of February 20, 2015 the Company was operating 12 rigs in the Bakken field and expects to be down to 10 rigs in March with plans to keep an average of 10 operated rigs in the play through year end.  The Company entered 2015 with 10 stimulation crews operating in the Bakken and expects to be down to four in early March due to deferring completions, which is a reduction from the original plan to have eight crews throughout March.  The Company expects to continue with four stimulation crews through year end.  

The 2015 Bakken drilling program will focus on the high rate of return areas in Williams, McKenzie, Dunn and Mountrail counties, targeting an average estimated ultimate recovery ("EUR") of 800,000 Boe per well. Enhanced completion techniques will be used to complete the wells using a combination of slickwater and hybrid stimulations.  Results of the enhanced completions are being monitored closely and continue to deliver 30% to 45% uplift in initial 90-day rates and an estimated 25% to 30% increase in EURs based on early results.

Utilizing new pipeline transportation optionality, Continental will have the ability to shift a substantial portion of its crude oil from rail to pipeline during 2015.  Continental will continue to utilize a balanced approach to reach the best markets utilizing rail, pipeline and local markets, including new North Dakota refinery capacity.   

SCOOP Woodford

In fourth quarter 2014, SCOOP Woodford net production averaged 34,498 Boe per day, an increase of 5% sequentially over third quarter 2014.  For full-year 2014, SCOOP Woodford production averaged 32,326 Boe per day.  In fourth quarter 2014, the Company completed 10 net (28 gross) operated and non-operated Woodford wells.  For full-year 2014, the Company completed 49 net (130 gross) operated and non-operated Woodford wells.  The Company operated an average of 15 rigs in SCOOP Woodford during fourth quarter 2014.  As of February 20, 2015 the Company was operating 15 rigs in the play and plans to keep an average of 10 to 13 operated rigs in the play through year end.  

The average initial one-day test rates from operated and non-operated wells completed during the fourth quarter of 2014 within the oil and condensate fairways of SCOOP Woodford were approximately 1,195 Boe per well. Select initial one-day test rates from fourth quarter SCOOP Woodford operated wells include:

  • The Oceana 1-17-8XH well in Stephens County initially tested at 20.7 million cubic feet of natural gas equivalent ("MMcfe") per day from 9,200 feet of completed lateral. The gas stream is estimated at 1,066 Btu/scf and had a 30-day average rate of 16.1 MMcfe per day with pipeline limitations. Continental has a 56% working interest in the well;
  • The Connell 1-13-12XH well in Stephens County initially tested at 14.0 MMcfe per day, which included 518 barrels of oil per day from 9,500 feet of completed lateral. The gas stream is estimated at 1,257 Btu/scf and had a 30-day average rate of 12.3 MMcfe per day with pipeline limitations. Continental has a 77% working interest in the well; and
  • The Wilkins 1-29H well in Stephens County initially tested at 11.5 MMcfe per day, which included 51 barrels of oil per day from 4,700 feet of completed lateral. The gas stream is estimated at 1,185 British thermal units per standard cubic foot ("Btu/scf") and had a 30-day average rate of 9.8 MMcfe per day with pipeline limitations. Continental has a 61% working interest in the well.

Sales from the Company's first increased density test in the SCOOP Woodford oil window commenced in first quarter 2015.  The eight Woodford wells in the Good Martin density test had an average initial one-day test rate of 820 Boe per well (approximately 75% oil).  On average, these wells were drilled approximately 660 feet apart and averaged 6,775 feet in lateral length.

The 2015 SCOOP Woodford drilling program will focus on a combination of infield development, density and step-out tests as the Company further defines and expands the play.  Approximately 85% of 2015 SCOOP Woodford wells are expected to be extended laterals to further enhance returns.

SCOOP Springer

In fourth quarter 2014, SCOOP Springer net production averaged 5,905 Boe per day, an increase of 72% sequentially over third quarter 2014.  For full-year 2014, SCOOP Springer production averaged 2,802 Boe per day. In the fourth quarter 2014, the Company completed 4 net (6 gross) operated and non-operated Springer wells. For full-year, the Company completed 16 net (21 gross) operated and non-operated wells. The Company operated an average of 12 rigs in the Springer during fourth quarter 2014.  As of February 20, 2015 the Company was operating 5 rigs and plans to keep a range of 3 to 6 rigs in the play through year end.

The initial one-day test rates averaged approximately 950 Boe per well for operated and non-operated Springer wells within the oil fairway of SCOOP Springer.  Select initial one-day test rates from fourth quarter operated wells within the oil fairway of SCOOP Springer include:

  • The Schoof 1-17H well in Grady County initially tested at 1,465 Boe per day (74% oil) from 4,415 feet of completed lateral. The well had a 30-day average rate of 920 Boe per day and Continental has a 99% working interest in the well;
  • The Lyle Land 1-25H well in Grady County initially tested at 1,135 Boe per day (77% oil) from 4,948 feet of completed lateral. The well had a 30-day average rate of 908 Boe per day and Continental has a 71% working interest in the well; and
  • The Martha Skid 1-35H well in Grady County initially tested at 935 Boe per day (75% oil) from 4,184 feet of completed lateral. The well had a 30-day average rate of 648 Boe per day and Continental has a 94% working interest in the well.

Sales from the Company's first increased density test in the SCOOP Springer oil window commenced in the first quarter 2015.  The four Springer wells in the Hartley unit density test had an average initial one-day test rate of 1,186 Boe per well (72% oil).  Three of the wells were spaced 1,055 feet apart and one well was spaced 2,110 feet from the others to test alternative spacing. The wells averaged 4,605 feet in lateral length.

The 2015 SCOOP Springer drilling program will focus on a combination of infield development, density and step-out tests as the Company further defines and expands the play.  Approximately 45% of 2015 wells are expected to be extended laterals to further enhance returns.

Jack H. Stark, Continental's President and Chief Operating Officer, added, "The strength of our assets and our operational flexibility have enabled us to adjust quickly to market conditions.  Our 2015 drilling program will focus on core properties to maximize returns and will continue to expand our proven assets through a strategic combination of step-out drilling, density drilling and enhanced completions.  We now believe we will see at least 15% cost savings by mid-year and even more by year end which will further enhance returns." 

Financial Update and Guidance

In fourth quarter 2014, Continental's average realized sales price excluding the effects of derivative positions was $61.53 per barrel of oil and $4.36 per thousand cubic feet of natural gas ("Mcf"), or $51.11 per Boe.  Based on realizations without the effect of derivatives, the Company's fourth quarter 2014 oil differential was $11.35 per barrel below the NYMEX daily average for the period.  The realized natural gas price differential for fourth quarter 2014 was a positive $0.35 per Mcf.  Full-year 2014 realized differentials without the effect of derivatives was a negative $10.81 per barrel of oil and a positive $1.02 per Mcf as compared to the NYMEX daily averages for the year.  Full-year 2014 oil and natural gas differentials were within the Company's guidance estimates.    

Production expense per Boe was $5.31 for fourth quarter 2014, a decrease of $0.49 per Boe from third quarter 2014.  Other select operating costs and expenses for fourth quarter 2014 included production taxes of 8.3% of oil and natural gas sales; DD&A of $22.39 per Boe; and G&A (cash and non-cash) of $2.85 per Boe.  On a full-year basis, these expense categories were better than or within the Company's full-year guidance.  

As of December 31, 2014, Continental's balance sheet included approximately $24 million in cash and cash equivalents and $165 million of borrowings against the Company's credit facility.  The Company recently increased the size of the commitments under its existing credit facility to $2.5 billion from $1.75 billion providing incremental liquidity. 

Non-acquisition capital expenditures for fourth quarter 2014 totaled approximately $1.39 billion, including $1.27 billion in exploration and development drilling, $47 million in leasehold and seismic and $76 million in workovers, recompletions and other.  Full-year 2014 capital expenditures reflected a higher than anticipated level of activity by outside operators and higher working interests in inside-operated wells during the fourth quarter.  Acquisition capital expenditures totaled approximately $24 million for fourth quarter 2014.  Full-year 2014 non-acquisition capital expenditures totaled approximately $4.81 billion.  Acquisition spending totaled approximately $204 million for the year.

The Company received approximately $433 million in proceeds and recognized $388 million in pre-tax derivative gains in the fourth quarter 2014 after taking into account cash and non-cash gains and losses for certain monetized hedge positions and remaining hedge positions.   

Property impairments for fourth quarter 2014 totaled approximately $394 million primarily resulting from lower crude oil prices and changes in drilling plans.  The impairments included $255 million for producing assets primarily from the Buffalo Red River Units and Medicine Pole Hills Units and $139 million for non-producing assets including $85 million related to exploratory prospects where the Company is not planning to proceed with development in the current commodity price environment.  There were no impairments of Bakken or SCOOP producing assets.  Full-year 2014 property impairments totaled approximately $617 million, including $324 million for producing assets and $293 million for non-producing assets.

John D. Hart, Continental's Chief Financial Officer, commented, "Looking ahead, our strategy is to maintain our financial strength and focus on operating efficiencies until commodity prices improve.  We have ample liquidity and no near-term debt maturities, providing a great deal of flexibility in how we deploy capital in 2015 and beyond."

Continental's 2015 guidance for natural gas differentials has been updated to $0.00 to negative $0.50 per Mcf due to market weakness in natural gas and natural gas liquids.  Guidance has also been updated to reflect an income tax rate of 38% due to increased operations in Oklahoma.  The Company's full-year 2015 guidance, which includes all 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,


2014


2013


2014


2013

Average daily production:











Crude oil (Bbl per day)

136,972



100,443



121,999



95,859

Natural gas (Mcf per day)

338,907



262,866



313,137



240,355

Crude oil equivalents (Boe per day)

193,456



144,254



174,189



135,919

Average sales prices, excluding effect from derivatives:











Crude oil ($/Bbl)

$61.53



$84.47



$81.26



$89.93

Natural gas ($/Mcf)

$4.36



$5.11



$5.40



$4.87

Crude oil equivalents ($/Boe)

$51.11



$68.12



$66.53



$72.04

Production expenses ($/Boe) 

$5.31



$6.03



$5.58



$5.69

Production taxes (% of oil and gas revenues)

8.3%



8.2%



8.2%



8.3%

DD&A ($/Boe)

$22.39



$20.40



$21.51



$19.47

General and administrative expenses ($/Boe)

$2.00



$2.27



$2.06



$2.11

Non-cash equity compensation ($/Boe)

$0.85



$0.79



$0.86



$0.80

Net income (in thousands) 

$114,048



$132,824



$977,341



$764,219

Diluted net income per share(1)

$0.31



$0.36



$2.64



$2.07

Adjusted net income (in thousands) (2) 

$420,770



$228,132



$1,271,171



$986,125

Adjusted diluted net income per share (1) (2)

$1.14



$0.62



$3.43



$2.67

EBITDAX (in thousands) (2)

$1,185,071



$712,300



$3,776,051



$2,839,510

(1)

Net income per share amounts for the 2013 periods have been retroactively adjusted to reflect the Company's 2-for-1 stock split in September 2014.

(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 net cash provided by operating activities 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.

Fourth Quarter and Full-Year Earnings Conference Call

Continental plans to host a conference call to discuss fourth quarter and full-year results on Wednesday, February 25, 2015, 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, February 25, 2015

Dial in:

888-895-5271

Intl. dial in:

847-619-6547

Pass code:

38844848

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:

38844848

Continental plans to publish a fourth quarter and full-year 2014 summary presentation to its website at www.CLR.com prior to the start of its earnings conference call on February 25, 2015. 

Upcoming Conferences

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

March 3, 2015

Raymond James Institutional Investors Conference: Orlando

March 4, 2015

Barclays Investment Grade Energy & Pipeline Conference: New York

March 24, 2015

Scotia Howard Weil 43rd 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 and a leader in America's energy renaissance. Based in Oklahoma City, Continental is the largest leaseholder and one of the largest producers 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 SCOOP Woodford and SCOOP Springer discoveries and the Northwest Cana play. With a focus on the exploration and production of oil, Continental has unlocked the technology and resources vital to American energy independence and is a strong free market advocate in favor of lifting of the domestic crude oil export ban. In 2015, the Company will celebrate 48 years of operations. 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, forecasts or expectations regarding the Company's business and 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 these assumptions and expectations are reasonable, they are inherently subject to numerous business, economic, competitive, regulatory and other risks and uncertainties, most of which are difficult to predict and many of which are beyond the Company's control. No assurance can be given that such expectations will be correct or achieved or that the assumptions are accurate. The risks and uncertainties include, but are not limited to, commodity price volatility; the geographic concentration of our operations; financial market and economic volatility; the inability to access needed capital; the risks and potential liabilities inherent in crude oil and natural gas drilling and production and the availability of insurance to cover any losses resulting therefrom; difficulties in estimating proved reserves and other reserves-based measures; declines in the values of our crude oil and natural gas properties resulting in impairment charges; our ability to replace proved reserves and sustain production; the availability or cost of equipment and oilfield services; leasehold terms expiring on undeveloped acreage before production can be established; our ability to project future production, achieve targeted results in drilling and well operations and predict the amount and timing of development expenditures; the availability and cost of transportation, processing and refining facilities; legislative and regulatory changes adversely affecting our industry and our business, including initiatives related to hydraulic fracturing; increased market and industry competition, including from alternative fuels and other energy sources; and the other risks described under Part I, Item 1A. Risk Factors and elsewhere in the Company's Annual Report on Form 10-K for the year ended December 31, 2013 and, once filed, for the year ended December 31, 2014, 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 on which such statement is made. 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. Except as otherwise required by applicable law, the Company undertakes no obligation to publicly correct or update any forward-looking statement whether as a result of new information, future events or circumstances after the date of this report, or otherwise.

Readers are cautioned that initial production rates are subject to decline over time and should not be regarded as reflective of sustained production levels.  In particular, production from horizontal drilling in shale oil and natural gas resource plays and tight natural gas plays that are stimulated with extensive pressure fracturing are typically characterized by significant early declines in production rates.

We use the term "EUR" or "estimated ultimate recovery" to describe potentially recoverable oil and natural gas hydrocarbon quantities.  We include these estimates to demonstrate what we believe to be the potential for future drilling and production on our properties.  These estimates are by their nature much more speculative than estimates of proved reserves and require substantial capital spending to implement recovery.  Actual locations drilled and quantities that may be ultimately recovered from our properties will differ substantially.  EUR data included herein remain subject to change as more well data is analyzed.

Investor Contact:

Media Contact:

John J. Kilgallon

Kristin Thomas

Vice President, Investor Relations

Vice President, Public Relations

405-234-9330

405-234-9480

John.Kilgallon@CLR.com

Kristin.Thomas@CLR.com

 

Continental Resources, Inc.

Consolidated Statements of Income







(Unaudited)






Three months ended December 31,


Year ended December 31,


2014


2013


2014


2013

Revenues:

In thousands, except per share data

Crude oil and natural gas sales

$ 902,323


$903,172


$4,203,022


$3,573,431

Gain (loss) on derivative instruments, net

387,958


(102,202)


559,759


(191,751)

Crude oil and natural gas service operations

7,419


10,250


38,837


40,127

Total revenues

1,297,700


811,220


4,801,618


3,421,807









Operating costs and expenses:








Production expenses

93,691


79,892


352,472


282,197

Production taxes and other expenses

77,034


75,069


349,760


298,787

Exploration expenses

20,535


5,809


50,067


34,947

Crude oil and natural gas service operations

3,481


7,097


21,871


29,665

Depreciation, depletion, amortization and accretion

395,260


270,456


1,358,669


965,645

Property impairments

393,803


58,548


616,888


220,508

General and administrative expenses 

50,220


40,619


184,655


144,379

(Gain) loss on sale of assets, net

(1,552)


24


(600)


(88)

Total operating costs and expenses

1,032,472


537,514


2,933,782


1,976,040

Income from operations

265,228


273,706


1,867,836


1,445,767

Other income (expense):








Interest expense

(74,200)


(63,666)


(283,928)


(235,275)

Loss on extinguishment of debt

-


-


(24,517)


-

Other 

702


792


2,647


2,557


(73,498)


(62,874)


(305,798)


(232,718)

Income before income taxes

191,730


210,832


1,562,038


1,213,049

Provision for income taxes

77,682


78,008


584,697


448,830

Net income

$ 114,048


$132,824


$   977,341


$   764,219

Basic net income per share(1)

$      0.31


$     0.36


$        2.65


$        2.08

Diluted net income per share(1)

$      0.31


$     0.36


$        2.64


$        2.07

(1)

Net income per share amounts for the 2013 periods have been retroactively adjusted to reflect the Company's 2-for-1 stock split in September 2014.  

    

Continental Resources, Inc.

Consolidated Balance Sheets






December 31, 2014


December 31, 2013

Assets

In thousands

Current assets

$

1,389,601


$

1,147,266

Net property and equipment (1)


13,635,852



10,721,272

Other noncurrent assets


119,617



72,644

Total assets

$

15,145,070


$

11,941,182







Liabilities and shareholders' equity






Current liabilities 

$

1,952,013


$

1,473,156

Long-term debt


5,995,837



4,713,821

Other noncurrent liabilities


2,229,376



1,801,087

Total shareholders' equity


4,967,844



3,953,118

Total liabilities and shareholders' equity

$

15,145,070


$

11,941,182

 

(1)

Balance is net of accumulated depreciation, depletion and amortization of $4.65 billion and $3.12 billion as of December 31, 2014 and December 31, 2013, respectively.

 

   

Continental Resources, Inc.

Consolidated Statements of Cash Flows
















(Unaudited)









Three months ended December 31,


Year ended December 31,

In thousands


2014


2013


2014


2013

Net income 


$

114,048


$

132,824


$

977,341


$

764,219

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













Non-cash expenses



995,960



512,189



2,505,053



1,809,951

Changes in assets and liabilities



(32,144)



(60,171)



(126,679)



(10,875)

Net cash provided by operating activities



1,077,864



584,842



3,355,715



2,563,295

Net cash used in investing activities



(1,361,139)



(911,623)



(4,587,399)



(3,711,011)

Net cash provided by financing activities



155,498



263,756



1,227,715



1,140,469

Effect of exchange rate changes on cash



(132)



-



(132)



-

Net change in cash and cash equivalents



(127,909)



(63,025)



(4,101)



(7,247)

Cash and cash equivalents at beginning of period



152,290



91,507



28,482



35,729

Cash and cash equivalents at end of period


$

24,381


$

28,482


$

24,381


$

28,482

 

Non-GAAP Financial Measures

EBITDAX

We use a variety of financial and operational measures to assess our performance. Among these measures is EBITDAX. We define EBITDAX as 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, non-cash equity compensation expense, and losses on extinguishment of debt. 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.
















Three months ended December 31,


Year ended December 31, 

In thousands



2014



2013



2014



2013

Net income


$

114,048


$

132,824


$

977,341


$

764,219

Interest expense



74,200



63,666



283,928



235,275

Provision for income taxes



77,682



78,008



584,697



448,830

Depreciation, depletion, amortization and accretion



395,260



270,456



1,358,669



965,645

Property impairments



393,803



58,548



616,888



220,508

Exploration expenses



20,535



5,809



50,067



34,947

Impact from derivative instruments:













Total (gain) loss on derivatives, net



(387,958)



102,202



(559,759)



191,751

Total cash (paid) received on derivatives, net



482,567



(9,644)



385,350



(61,555)

Non-cash (gain) loss on derivatives, net



94,609



92,558



(174,409)



130,196

Non-cash equity compensation



14,934



10,431



54,353



39,890

Loss on extinguishment of debt



-



-



24,517



-

EBITDAX


$

1,185,071


$

712,300


$

3,776,051


$

2,839,510

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



2014



2013



2014



2013

Net cash provided by operating activities


$

1,077,864


$

584,842


$

3,355,715


$

2,563,295

Current income tax provision (benefit)



(2,258)



(4,014)



20



6,209

Interest expense



74,200



63,666



283,928



235,275

Exploration expenses, excluding dry hole costs



5,998



5,639



26,388



25,597

Gain (loss) on sale of assets, net



1,552



(24)



600



88

Other, net



(4,429)



2,020



(17,279)



(1,829)

Changes in assets and liabilities



32,144



60,171



126,679



10,875

EBITDAX


$

1,185,071


$

712,300


$

3,776,051


$

2,839,510

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. We define adjusted earnings and adjusted earnings per share as 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, corporate relocation expenses, and losses on extinguishment of debt. 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 property dispositions. 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 tables reconcile 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. Net income per share amounts for the 2013 periods have been retroactively adjusted to reflect the Company's 2-for-1 stock split in September 2014.









Three Months Ended December 31,









2014


2013

In thousands, except per share data


After-Tax $


Diluted EPS


After-Tax $


Diluted EPS

Net income (GAAP)


$    114,048


$         0.31


$  132,824


$         0.36

Adjustments, net of tax:










Non-cash loss on derivatives, net


59,603


0.16


58,312


0.16


Property impairments


248,096


0.67


36,885


0.10


(Gain) loss on sale of assets, net


(977)


-


15


-


Corporate relocation expenses


-


-


96


-



Adjusted net income (Non-GAAP)(1)


$    420,770


$         1.14


$  228,132


$         0.62



Weighted average diluted shares outstanding


370,545




370,014





Adjusted diluted net income per share (Non-GAAP)(1)


$          1.14




$       0.62
























































Year Ended December 31,









2014


2013

In thousands, except per share data


After-Tax $


Diluted EPS


After-Tax $


Diluted EPS

Net income (GAAP)


$    977,341


$         2.64


$  764,219


$         2.07

Adjustments, net of tax:










Non-cash (gain) loss on derivatives, net


(109,878)


(0.30)


82,023


0.22


Property impairments


388,640


1.05


138,920


0.38


Gain on sale of assets, net


(378)


-


(55)


-


Loss on extinguishment of debt




15,446


0.04


-


-


Corporate relocation expenses


-


-


1,018


-



Adjusted net income (Non-GAAP)(1)


$  1,271,171


$         3.43


$  986,125


$         2.67



Weighted average diluted shares outstanding


370,758




369,698





Adjusted diluted net income per share (Non-GAAP)(1)


$          3.43




$       2.67



(1)

Balances for the 2014 periods include $348 million of pre-tax gains ($219 million after tax, or $0.59 per diluted share) recognized from crude oil derivative contracts that were monetized in the 2014 fourth quarter prior to their contractual maturities scheduled for 2015 and 2016.

    

Continental Resources, Inc.

2015 Guidance

As of February 24, 2015(1)







2015







Production growth (YOY)





16% to 20%

Capital expenditures (non-acquisition, in $ billions)





$2.7







Operating Expenses:






     Production expense per Boe





$5.50 to $6.00

     Production tax (% of oil & gas revenue)





7.5% to 8.5%

     G&A expense per Boe





$2.00 to $2.50

     Non-cash equity compensation per Boe





$0.75 to $0.95

     DD&A per Boe





   $20.00 to $22.50







Average Price Differentials:






     NYMEX WTI crude oil (per barrel of oil)





($7.00) to ($10.00)

     Henry Hub natural gas (per Mcf)





$0.00 to ($0.50)







Income tax rate





38%

Deferred taxes





90% to 95%



(1)

Bold items above in guidance denote a change from the previous disclosure provided on December 22, 2014.

   

Continental Resources, Inc.

2015 Non-Acquisition Capital Expenditures and

Associated Operated Rig and Well Activity



Bakken

SCOOP

 ($ in millions)

Drilling

Capex

Rigs

Net Wells

Gross

Wells

Drilling

Capex

Rigs

Net Wells

Gross

Wells

2015 Budget

$1,550

11

191

631

$720

16

81

157


Other Drilling

Total

($ in millions)

Drilling

Capex

Rigs

Net Wells

Gross

Wells

Total

Capex(1)

Rigs

Net Wells

Gross

Wells

2015 Budget

$100

4

11

25

$2,700

31

283

813



(1)

Total non-acquisition capex includes $180 million for land and $150 million for other capital expenditures.

To view the original version on PR Newswire, visit:http://www.prnewswire.com/news-releases/continental-resources-reports-fourth-quarter-2014-and-full-year-2014-results-300040692.html

SOURCE Continental Resources

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