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Continental Resources Reports Second Quarter 2016 Results
Outstanding STACK Well Results Increase 2016 Production Guidance to 210,000 to 220,000 Boe per Day; Capital Budget Remains Unchanged
Production Expense Outlook Reduced $0.50 per Barrel of Oil Equivalent (Boe)
New STACK Completions Extend Oil Window West: Madeline 1-9-4XH Flows at 3,538 Boe per Day (71% Oil); Frankie Jo 1-25-24XH Flows at 2,627 Boe per Day (56% Oil)
Enhanced Completions in SCOOP Woodford Oil Window Increase Estimated Ultimate Recovery (EUR) by ~30% to 1.3 Million Boe per Well (62% Oil) for 2-Mile Laterals
Company Agrees to Sell Non-Strategic SCOOP Leasehold for $281 Million, with Proceeds to Be Applied to Debt Reduction

OKLAHOMA CITY, Aug. 3, 2016 /PRNewswire/ -- Continental Resources, Inc. (NYSE: CLR) (the "Company") today reported a net loss of $119.4 million, or $0.32 per diluted share, for the quarter ended June 30, 2016.

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The Company's net loss includes certain items typically excluded by the investment community in published estimates, the result of which is often referred to as "adjusted net loss." In second quarter 2016, these typically excluded items in aggregate represented $53.5 million, or $0.14 per diluted share, of Continental's reported net loss.

EBITDAX for second quarter 2016 was $528.1 million. The Company has defined and reconciled adjusted net loss, adjusted net loss per diluted share and EBITDAX to the most directly comparable U.S. generally accepted accounting principles (GAAP) financial measures in supporting tables at the conclusion of this press release under the header Non-GAAP Financial Measures.

"Continental once again outperformed production guidance in the second quarter thanks to the exceptional quality and performance of our Bakken, SCOOP and STACK assets, as well as exceptional execution by our teams," commented Harold Hamm, Chairman and Chief Executive Officer. "We are also on track to reduce long-term debt with our agreement to sell a second non-strategic asset for $281 million."

Updated 2016 Guidance Reflects Strong Performance

Based on strong operating results in first half 2016, the Company now expects production for the year will be in a range of 210,000 and 220,000 Boe per day, an increase of 5,000 Boe per day from previous guidance. Continental expects to exit the year with production between 195,000 and 205,000 Boe per day, also reflecting a 5,000 Boe per day increase.

Continental also reduced 2016 guidance for production expense per Boe and cash general and administrative (G&A) expense per Boe. Production expense is now expected to be in a range of $3.75 to $4.25 per Boe for the year, down approximately 11% ($0.50 per Boe) from the previous range. Efficiencies contributing to the lower guidance include reducing produced water expense and increasing artificial lift efficiency in the Bakken and reducing compression, saltwater disposal and chemical costs in Oklahoma. 

Total G&A expense, including cash and non-cash G&A expense, is expected to be in a reduced range of $1.85 to $2.45 per Boe for 2016. Of this total, cash G&A expense is expected to be in a range of $1.20 to $1.60 per Boe for 2016, a reduction from the previous range of $1.25 to $1.75 per Boe.

Finally, the Company improved its outlook for oil price differential, reflecting increased crude oil production in Oklahoma, where it has lower transportation costs, and reduced transportation costs from the Bakken. Average crude oil price differential for 2016 is expected to be in a range of $7.00 to $8.00 per barrel of oil (Bo), compared with the previous range of $7.00 to $9.00.

 

2016 Updated Guidance Metrics 

Updated 2016 Guidance

Previous 2016 Guidance

Production guidance (Boe per day)

210,000 to 220,000

205,000 to 215,000

Production expense per Boe

$3.75 to $4.25

$4.25 to $4.75

Cash G&A expense per Boe

$1.20 to $1.60

$1.25 to $1.75

Average price differential for NYMEX WTI crude oil (per Bo)

($7.00) to ($8.00)

($7.00) to ($9.00)

 

The Company's full 2016 guidance is stated in a table at the conclusion of this release.

"Over the last 18 months, Continental has achieved a step-change improvement in capital efficiency," said Jack Stark, President and Chief Operating Officer.  "Barrels of oil found per dollar invested have more than doubled, while production expense per Boe and G&A expense per Boe have decreased by a combined 36% since 2014.  We believe the majority of these capital efficiencies are structural and sustainable, further strengthening CLR's performance going forward."

SCOOP Non-Strategic Asset Sale for $281 Million

Continental announced today it has signed a definitive purchase and sale agreement with an undisclosed buyer to sell approximately 29,500 net acres of non-strategic leasehold in the SCOOP play in Oklahoma for $281 million. The agreement provides for customary closing conditions and adjustments. Located primarily on the eastern side of SCOOP, the leasehold represents approximately 550 Boe per day of net production. After this transaction, the Company will retain approximately 384,000 net acres of leasehold in SCOOP.

"Proceeds from this sale and the previous sale of Wyoming assets will total nearly $400 million," said Mr. Stark. In May 2016, the Company announced the sale of approximately 132,000 net acres of leasehold in the Washakie Basin in Wyoming for $110 million.

"We have additional opportunities to sell non-strategic assets for continued debt reduction," he said.

Production Results  

Second quarter 2016 net production totaled approximately 20.0 million Boe (MMBoe), or 219,300 Boe per day, down 5% from first quarter 2016 and 3% lower than second quarter 2015. The second quarter 2016 production decline, as expected, was concentrated in the Bakken play, where the Company continues to increase its drilled but uncompleted (DUC) well inventory.

Total net production for second quarter 2016 included approximately 133,000 Bo per day (61% of total production) and approximately 518 million cubic feet (MMcf) of natural gas per day (39% of total production). 

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

 




2Q


1Q


2Q


YTD


YTD

Boe per day


2016


2016


2015


2016


2015

North Region:











North Dakota Bakken


114,554


129,168


127,872


121,861


124,434

Montana Bakken


10,474


10,434


13,116


10,454


13,844

Red River Units 


11,075


11,300


12,669


11,188


12,810

Other


695


649


1,835


672


1,261

South Region:











SCOOP


64,669


64,616


62,546


64,642


56,249

STACK/NW Cana


14,610


11,127


4,410


12,868


3,924

Arkoma


1,862


2,037


2,112


1,950


2,118

Other 


1,384


1,471


1,987


1,428


2,102

Total


219,323


230,802


226,547


225,063


216,742

 

STACK / Northwest Cana Joint Development Agreement (JDA) Area, Oklahoma

STACK/Northwest Cana production increased 31% to 14,610 Boe per day in second quarter 2016, compared to first quarter 2016.

The Company reported five new Meramec completions in Blaine County. Initial 24-hour production test rates and flowing casing pressures (in pounds per square inch, or psi) for these wells were as follows:

  • Madeline 1-9-4XH flowed 2,513 Bo and 6.1 MMcf of natural gas (3,538 Boe) per day at 4,500 psi flowing casing pressure;
  • Frankie Jo 1-25-24XH flowed 1,484 Bo and 6.9 MMcf of natural gas (2,627 Boe) per day at 4,320 psi;
  • Gillilan 1-35-26XH flowed 1,703 Bo and 4.4 MMcf of natural gas (2,439 Boe) per day at 2,030 psi;
  • Oppel 1-25-26XH flowed 998 Bo and 1.9 MMcf of natural gas (1,308 Boe) per day at 1,670 psi; and
  • Yocum 1-35-26XH flowed 14.0 MMcf of natural gas and 17 Bo (2,355 Boe) per day at 4,810 psi.

All five new wells were drilled with extended laterals, ranging from approximately 7,100 to 9,900 feet.

"Results of the Madeline and Frankie Jo wells are outstanding," said Mr. Stark. "These two wells extend the known productive footprint of the over-pressured Meramec oil window 17 miles west of the Verona well we reported in May. The Madeline actually set a new record for Continental operated wells in STACK, flowing at an initial 24-hour rate of 3,538 Boe per day, with 71% of production being crude oil."

The Yocum is a strong gas producer and Continental's first completion in the over-pressured gas window of STACK. The Yocum was designed to test the productivity of the Meramec on the down-thrown side of a significant north-south trending fault that separates the Yocum from the Company's previously announced Boden 1-15-10XH well, which is located just over a mile to the northwest.

"The separating fault has up to 525 feet of vertical displacement, and the Yocum is clearly in the gas window on the down-thrown side of the fault," said Glen Brown, Senior Vice President of Exploration. "In contrast, the Boden is located in the condensate window on the fault's up-thrown side, and it has steadily produced 27% crude oil since December 2015. The Yocum's results place an additional 2% of Continental's STACK acreage in the gas window."

Continental finished drilling and is now completing its first STACK density pilot in the Ludwig unit, which is located in the over-pressured oil window of STACK. The Ludwig is testing four wells per zone in the Upper and Middle Meramec zones, with one well in the Woodford.  Average lateral length for the Ludwig wells is approximately 9,500 feet. Multi-well pad development reduced drilling times for the Ludwig density wells to an average 25 days, down 44%, compared to the Company's average for STACK wells drilled in 2015. Average drilling cost for the Ludwig density wells is estimated at $3.2 million per well, 28% below the Ludwig legacy well drilled in June of 2015.  

The Company has commenced drilling its second and third STACK density pilots in the over-pressured oil window at the Bernhardt and Blurton units in Blaine County. The Bernhardt density pilot is testing a five-well per zone pattern in the Lower Meramec, with targeted lateral lengths of 4,500 feet. The Blurton density pilot is testing three to five wells per zone in the Upper and Lower Meramec, with average lateral lengths of 9,800 feet.

Continental is now targeting an average completed well cost of $9.0 million per operated well for extended-lateral wells in the over-pressured oil window of STACK. This is $500,000 per well below the previous year-end 2016 target. At this targeted cost, Continental estimates a well in the over-pressured oil window should deliver more than an 85% rate of return at $45 per barrel WTI and $2.50 per Mcf of gas, based on an EUR of 1.7 MMBoe per well.

Continental increased its STACK leasehold by approximately 12,000 net acres in second quarter 2016 to approximately 183,000 net acres, located primarily in Blaine, Dewey and Custer counties. Since year-end 2015, the Company has added approximately 27,000 net acres of leasehold in STACK. The Company estimates 95% of its STACK leasehold is in the over-pressured window, of which 40% is in the oil window, 40% is in the condensate window and 20% is in the gas window. The Company has 11 operated rigs in STACK, with six targeting the Meramec formation in Blaine County and five targeting the Woodford formation in the Northwest Cana JDA area.

A notable second quarter 2016 well completion in the Northwest Cana JDA area was the Lacretia 1-29-20XH, which had initial 24-hour production of 17.6 MMcf per day (100% natural gas) with approximately a 7,500-foot lateral at 5,500 psi flowing casing pressure. Since inception in early April, the Lacretia has flowed a cumulative 1.7 Bcf of gas, and it is currently flowing approximately 11.8 MMcf per day at 3,250 psi flowing casing pressure.

SCOOP Play, Oklahoma: Woodford Oil Window EUR Increased to 1.3 MMBoe per Well  

In second quarter 2016, total SCOOP net production averaged 64,669 Boe per day, slightly above first quarter 2016 and 3% higher than second quarter 2015. SCOOP production represented 29% of the Company's total production in second quarter 2016.

SCOOP Woodford net production averaged 56,511 Boe per day in second quarter 2016, compared with SCOOP Springer net production of 8,158 Boe per day.

The Company announced it has increased the EUR for 2-mile wells drilled in the SCOOP Woodford oil window by approximately 30% to 1.3 MMBoe per well, with 62% of production being crude oil. The increase in EUR was based on the results of 22 enhanced completions conducted over the past two years in the SCOOP Woodford oil window and assumes an average 9,800-foot lateral per well. Results show that 180-day production rates are on average 25%-to-30% higher than offsetting legacy wells. At a targeted completed well cost of $9.8 million per well, a 1.3 MMBoe EUR SCOOP Woodford oil well should yield a 32% rate of return at $45 per barrel WTI and $2.50 per Mcf of gas.

The most recent enhanced completion well in the SCOOP Woodford oil window was the RK Morris 1-29-17XH in eastern Grady County, which had an initial 24-hour production test rate of 1,003 Bo and 1.8 MMcf (1,297 Boe) from an 11,500-foot lateral, with flowing casing pressure of 690 psi. Along with solid initial production, the well is exhibiting a low decline rate, with an average 30-day production of 903 Bo and 1.6 MMcf per day at 560 psi.

Gary Gould, Senior Vice President of Production and Resource Development, said, "Enhanced completions once again are having a profound impact on production rates and EURs, this time in the oil window of SCOOP Woodford, just as we've experienced in the SCOOP condensate window. We estimate that at least 50,000 net acres in our Woodford oil window leasehold can be upgraded to the new 1.3 MMBoe EUR type curve, so the new approach obviously increases the value of this asset in a significant way." He added that enhanced completion designs will be applied in all future oil window wells in SCOOP Woodford, starting with the completion of the new wells in the May density pilot in Grady County.

Continental completed 6 net (24 gross) operated and non-operated wells in SCOOP in second quarter 2016, while operating an average of four rigs in the play. This includes 5.4 net (23 gross) wells targeting the Woodford formation and 0.3 net (1 gross) wells targeting the Springer formation.

Bakken Play, North Dakota

Continental's Bakken production averaged 125,028 Boe per day in second quarter 2016, a decrease of 10% from first quarter 2016. Continental completed 3 net (25 gross) operated and non-operated wells in Bakken in second quarter 2016, while operating an average of four drilling rigs in the play.

The Company recently elected to complete eight additional operated Bakken wells in the second half of 2016 to further test enhanced completion concepts including stage spacing, proppant volumes per stage, proppant size and diverter technology.  Two stimulation crews were recently deployed in the field to execute these plans, and the Company anticipates first production for new wells in this program during third and fourth quarters 2016.  This testing program is designed to provide additional data to help Continental optimize future development of its DUC inventory.

Continental's current Bakken DUC inventory has grown to approximately 165 gross operated DUCs, with expectations to end 2016 with approximately 190 gross operated DUCs. This represents a high-graded inventory with an average EUR of approximately 850,000 Boe per DUC well. The Company estimates a current average cost of between $3.0 million to $3.5 million per well to complete these wells.  At $45 per barrel WTI and $2.50 per Mcf of gas, the cost-forward rate of return on this incremental capital expenditure is over 100%.  "Our DUCs represent an exceptional value that we can capitalize on as markets recover," Mr. Gould said.

The Company's total completed well cost for a 2-mile lateral Bakken well is approximately $6.2 million, down from $6.8 million at year-end 2015. Continental expects to achieve an operated completed well cost of $6.0 million by year-end 2016.

Financial Update

"Continental's second quarter results clearly reflect continued discipline in terms of operating costs and capital expenditures," said John Hart, Chief Financial Officer.  "We are currently cash flow positive and expect to remain so in the second half of the year, especially under our assumption that commodity prices will strengthen. Our credit metrics are improving and are expected to further improve as we apply asset divestiture proceeds to further reduce debt."

In second quarter 2016, Continental's average realized sales price, excluding the effects of derivative positions, was $38.38 per Bo and $1.31 per Mcf of gas, or $26.36 per Boe. Based on realizations without the effect of derivatives, the Company's second quarter 2016 oil differential was $7.21 per barrel below the NYMEX daily average for the period. The second quarter 2016 realized wellhead natural gas price, without the effect of derivatives, was on average $0.65 per Mcf below the average NYMEX Henry Hub benchmark price.      

Production expense per Boe was $3.72 for second quarter 2016, a decrease of $0.67 per Boe from second quarter 2015. Other select operating costs and expenses for second quarter 2016 included production taxes of 7.4% of oil and natural gas sales; DD&A of $22.15 per Boe; and G&A (cash and non-cash) of $1.82 per Boe.

As of June 30, 2016, Continental's balance sheet included $16.6 million in cash and cash equivalents and $885 million of borrowings against the Company's revolving credit facility, compared to the balance of $940 million at March 31, 2016. As of July 31, 2016, borrowings against the revolving credit facility had declined to $820 million. Continental had approximately $1.86 billion in available borrowing capacity under its revolving credit facility as of June 30, 2016, and approximately $1.93 billion was available as of July 31, 2016.

Capital expenditures for second quarter 2016 were $219.3 million, including $9.9 million for acquisitions. Non-acquisition capital expenditures for second quarter 2016 included $179.6 million in exploration and development drilling, $18.8 million in leasehold and seismic, and $11.0 million in workovers, recompletions and other. Year-to-date non-acquisition capital expenditures were consistent with the Company's spending plan under its budget of $920 million for 2016.

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 June 30,


Six months ended June 30,


2016


2015


2016


2015

Average daily production:








Crude oil (Bbl per day)

133,044


149,897


139,756


146,722

Natural gas (Mcf per day)

517,677


459,898


511,837


420,123

Crude oil equivalents (Boe per day)

219,323


226,547


225,063


216,742

Average sales prices, excluding effect from derivatives:








Crude oil ($/Bbl)

$38.38


$49.84


$31.76


$44.46

Natural gas ($/Mcf)

$1.31


$2.31


$1.33


$2.48

Crude oil equivalents ($/Boe)

$26.36


$37.82


$22.73


$34.93

Production expenses ($/Boe) 

$3.72


$4.39


$3.74


$4.70

Production taxes (% of oil and gas revenues)

7.4%


7.8%


7.5%


8.0%

DD&A ($/Boe)

$22.15


$21.68


$22.16


$21.36

Total general and administrative expenses ($/Boe) (1)

$1.82


$2.11


$1.68


$2.28

Net income (loss) (in thousands) 

($119,402)


$403


($317,727)


($131,568)

Diluted net income (loss) per share

($0.32)


$0.00


($0.86)


($0.36)

Adjusted net income (loss) (non-GAAP) (in thousands) (2) 

($65,910)


$48,450


($216,378)


$14,631

Adjusted diluted net income (loss) per share (non-GAAP) (2)

($0.18)


$0.13


($0.58)


$0.04

Net cash provided by operating activities

$218,819


$394,622


$497,721


$916,812

EBITDAX (non-GAAP) (in thousands) (2)

$528,109


$647,009


$842,718


$1,086,435



(1)

Total general and administrative expense is comprised of cash general and administrative expense and non-cash equity compensation expense. Cash general and administrative expense per Boe was $1.22, $1.34, $1.16, and $1.58 for 2Q 2016, 2Q 2015, YTD 2016, and YTD 2015, respectively. Non-cash equity compensation expense per Boe was $0.60, $0.77, $0.52, and $0.70 for 2Q 2016, 2Q 2015, YTD 2016, and YTD 2015, respectively.

 

(2)

Adjusted net income (loss), adjusted diluted net income (loss) 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 (loss), diluted net income (loss) 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 (loss), adjusted diluted net income (loss) per share, and EBITDAX to the most directly comparable U.S. GAAP financial measures are provided subsequently under the header Non-GAAP Financial Measures.

 

Second Quarter 2016 Earnings Conference Call

Continental plans to host a conference call to discuss second quarter results on Thursday, August 4, 2016, 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, Thursday, August 4, 2016

Dial in:    

844-309-6572

Intl. dial in: 

484-747-6921

Pass code:

28733877

A replay of the call will be available for 14 days on the Company's website or by dialing:

Replay number:  

855-859-2056 or 404-537-3406

Intl. replay:  

800-585-8367

Pass code:

28733877

Continental plans to publish a second quarter 2016 summary presentation to its website at www.CLR.com prior to the start of its earnings conference call on August 4, 2016. 

Upcoming Conferences

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

August 24, 2016Heikkinen Energy Conference, Houston
September 6-7, 2016Barclays CEO Energy-Power Conference, New York

Presentation materials for all conferences listed 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 U.S. Lower 48 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 leading positions in Oklahoma, including its SCOOP Woodford and SCOOP Springer discoveries and the STACK and Northwest Cana plays. With a focus on the exploration and production of oil, Continental has unlocked the technology and resources vital to American energy independence and our nation's leadership in the new world oil market. In 2016, the Company will celebrate 49 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, rates of return, budgets, costs, business strategy, objectives, and cash flows 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, 2015, 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:

J. Warren Henry  

Kristin Thomas

Vice President, Investor Relations & Research 

Vice President, Public Relations

405-234-9127    

405-234-9480

Warren.Henry@CLR.com  

Kristin.Thomas@CLR.com



Alyson L. Gilbert


Manager, Investor Relations


405-774-5814


Alyson.Gilbert@CLR.com


 

Continental Resources, Inc. and Subsidiaries
Unaudited Condensed Consolidated Statements of Income (Loss)



Three months ended June 30,


Six months ended June 30,


2016


2015


2016


2015

Revenues:

In thousands, except per share data

Crude oil and natural gas sales

$  525,711


$ 790,102


$  929,302


$ 1,372,694

Gain (loss) on crude oil and natural gas derivatives, net

(82,257)


(4,737)


(40,145)


28,018

Crude oil and natural gas service operations

7,757


11,009


15,227


21,306

Total revenues

451,211


796,374


904,384


1,422,018









Operating costs and expenses:








Production expenses

74,083


91,735


152,724


184,675

Production taxes and other expenses

39,141


61,545


69,634


109,908

Exploration expenses

1,674


109


4,739


14,449

Crude oil and natural gas service operations

3,576


7,092


6,618


10,986

Depreciation, depletion, amortization and accretion

441,761


452,957


905,752


839,469

Property impairments

66,112


76,872


145,039


224,432

General and administrative expenses 

36,246


44,190


68,654


89,571

Net gain on sale of assets and other

(100,835)


(20,573)


(99,127)


(22,643)

Total operating costs and expenses

561,758


713,927


1,254,033


1,450,847

Income (loss) from operations

(110,547)


82,447


(349,649)


(28,829)

Other income (expense):








Interest expense

(81,922)


(78,442)


(162,875)


(153,505)

Other 

435


540


819


886


(81,487)


(77,902)


(162,056)


(152,619)

Income (loss) before income taxes

(192,034)


4,545


(511,705)


(181,448)

Provision (benefit) for income taxes

(72,632)


4,142


(193,978)


(49,880)

Net income (loss)

$ (119,402)


$       403


$ (317,727)


$  (131,568)

Basic net income (loss) per share

$       (0.32)


$            -


$       (0.86)


$        (0.36)

Diluted net income (loss) per share

$       (0.32)


$            -


$       (0.86)


$        (0.36)

 

Continental Resources, Inc. and Subsidiaries
Unaudited Condensed Consolidated Balance Sheets








June 30, 2016


December 31, 2015

Assets

In thousands

Current assets

$

797,212


$

822,339

Net property and equipment (1)


13,541,129



14,063,328

Other noncurrent assets


21,395



34,141

Total assets

$

14,359,736


$

14,919,808







Liabilities and shareholders' equity






Current liabilities 

$

818,059


$

923,028

Long-term debt, net of current portion


7,149,279



7,115,644

Other noncurrent liabilities


2,025,449



2,212,236

Total shareholders' equity


4,366,949



4,668,900

Total liabilities and shareholders' equity

$

14,359,736


$

14,919,808



(1)

Balance is net of accumulated depreciation, depletion and amortization of $7.36 billion and $6.45 billion as of June 30, 2016 and December 31, 2015, respectively.

 

Continental Resources, Inc. and Subsidiaries

Unaudited Condensed Consolidated Statements of Cash Flows
















Three months ended June 30,


Six months ended June 30,

In thousands


2016


2015


2016


2015

Net income (loss)


$

(119,402)


$

403


$

(317,727)


$

(131,568)

Adjustments to reconcile net income (loss) to net cash provided by operating activities:













Non-cash expenses



470,257



544,438



903,030



1,039,534

Changes in assets and liabilities



(132,036)



(150,219)



(87,582)



8,846

Net cash provided by operating activities



218,819



394,622



497,721



916,812

Net cash used in investing activities



(158,983)



(684,899)



(517,794)



(1,963,303)

Net cash provided by financing activities



(56,181)



267,283



25,161



1,051,666

Effect of exchange rate changes on cash



(22)



807



9



(4,098)

Net change in cash and cash equivalents



3,633



(22,187)



5,097



1,077

Cash and cash equivalents at beginning of period



12,927



47,645



11,463



24,381

Cash and cash equivalents at end of period


$

16,560


$

25,458


$

16,560


$

25,458

 

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, and non-cash equity compensation expense. EBITDAX is not a measure of net income or net cash provided by operating activities 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 (loss) and net cash provided by operating activities 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 (loss) or net cash provided by operating activities 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 (loss) to EBITDAX for the periods presented.

 




Three months ended June 30,


Six months ended June 30, 

In thousands



2016



2015



2016



2015

Net income (loss)


$

(119,402)


$

403


$

(317,727)


$

(131,568)

Interest expense



81,922



78,442



162,875



153,505

Provision (benefit) for income taxes



(72,632)



4,142



(193,978)



(49,880)

Depreciation, depletion, amortization and accretion



441,761



452,957



905,752



839,469

Property impairments



66,112



76,872



145,039



224,432

Exploration expenses



1,674



109



4,739



14,449

Impact from derivative instruments:













Total (gain) loss on derivatives, net



78,057



4,737



37,005



(28,018)

Total cash received on derivatives, net



38,778



13,182



77,967



36,617

Non-cash loss on derivatives, net



116,835



17,919



114,972



8,599

Non-cash equity compensation



11,839



16,165



21,046



27,429

EBITDAX (non-GAAP)


$

528,109


$

647,009


$

842,718


$

1,086,435














 

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

 

























Three months ended June 30,


Six months ended June 30, 

In thousands



2016



2015



2016



2015

Net cash provided by operating activities


$

218,819


$

394,622


$

497,721


$

916,812

Current income tax provision



6



5



12



10

Interest expense



81,922



78,442



162,875



153,505

Exploration expenses, excluding dry hole costs



1,468



109



4,533



6,446

Gain on sale of assets, net



96,907



20,573



97,016



22,643

Other, net



(3,049)



3,039



(7,021)



(4,135)

Changes in assets and liabilities



132,036



150,219



87,582



(8,846)

EBITDAX (non-GAAP)


$

528,109


$

647,009


$

842,718


$

1,086,435

 

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 and gains and losses on asset sales. Management believes these measures provide useful information to analysts and investors for analysis of our operating results. 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.

 











Three months ended June 30,










2016


2015


In thousands, except per share data


$


Diluted EPS


$


Diluted EPS


Net income (loss) (GAAP)


$(119,402)


$       (0.32)


$       403


$        0.00


Adjustments:










Non-cash loss on derivatives




116,835




17,919




Property impairments




66,112




76,872




Gain on sale of assets




(96,907)




(20,573)




Total tax effect of adjustments




(32,548)




(26,171)




Total adjustments, net of tax




53,492


0.14


48,047


0.13


Adjusted net income (loss) (non-GAAP)




$  (65,910)


$       (0.18)


$   48,450


$        0.13


Weighted average diluted shares outstanding


370,435




370,873




Adjusted diluted net income (loss) per share (non-GAAP)


$     (0.18)




$      0.13




























Six months ended June 30,










2016


2015


In thousands, except per share data




$


Diluted EPS


$


Diluted EPS


Net income (loss) (GAAP)






$(317,727)


$       (0.86)


$(131,568)


$       (0.36)


Adjustments:










Non-cash loss on derivatives




114,972




8,599




Property impairments




145,039




224,432




Gain on sale of assets




(97,016)




(22,643)




Total tax effect of adjustments




(61,646)




(64,189)




Total adjustments, net of tax




101,349


0.28


146,199


0.40


Adjusted net income (loss) (non-GAAP)




$(216,378)


$       (0.58)


$   14,631


$        0.04


Weighted average diluted shares outstanding


370,248




369,448




Adjusted diluted net income (loss) per share (non-GAAP)


$     (0.58)




$      0.04



 

Cash general and administrative expenses per Boe

Our presentation of cash general and administrative ("G&A") expenses per Boe is a non-GAAP measure. We define cash G&A per Boe as total G&A determined in accordance with U.S. GAAP less non-cash equity compensation expenses, expressed on a per-Boe basis. We report and provide guidance on cash G&A per Boe because we believe this measure is commonly used by management, analysts and investors as an indicator of cost management and operating efficiency on a comparable basis from period to period. In addition, management believes cash G&A per Boe is used by analysts and others in valuation, comparison and investment recommendations of companies in the oil and gas industry to allow for analysis of G&A spend without regard to stock-based compensation programs which can vary substantially from company to company. Cash G&A per Boe should not be considered as an alternative to, or more meaningful than, total G&A per Boe as determined in accordance with U.S. GAAP and may not be comparable to other similarly titled measures of other companies.

 

Continental Resources, Inc. 

2016 Guidance

As of August 3, 2016 (1)




2016



Full year average production 

210,000 - 220,000 Boe per day

Capital expenditures (non-acquisition)

$920 million 



Operating Expenses:


     Production expense per Boe

$3.75 - $4.25

     Production tax (% of oil & gas revenue)

6.75% - 7.25%

     Cash G&A expense per Boe(2)

$1.20 - $1.60

     Non-cash equity compensation per Boe

$0.65 - $0.85

     DD&A per Boe

 $20.00 - $22.00



Average Price Differentials:


     NYMEX WTI crude oil (per barrel of oil)

($7.00) - ($8.00)

     Henry Hub natural gas (per Mcf)

$0.00 - ($0.65)



Income tax rate

38%

Deferred taxes

90% - 95%






(1)

Bolded items denote a positive guidance revision from the previous disclosure provided on May 4, 2016. 


(2)

Cash G&A is a non-GAAP measure and excludes the range of values shown for non-cash equity compensation per Boe in the item appearing immediately below. 

 

To view the original version on PR Newswire, visit:http://www.prnewswire.com/news-releases/continental-resources-reports-second-quarter-2016-results-300308764.html

SOURCE Continental Resources

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