Continental Resources Reports First Quarter 2017 Results
PR Newswire
OKLAHOMA CITY

OKLAHOMA CITY, May 3, 2017 /PRNewswire/ -- Continental Resources, Inc. (NYSE: CLR) (the Company) today announced first quarter operating and financial results. Continental reported net income of $0.47 million, or $0.00 per diluted share, for the quarter ended March 31, 2017.

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The Company's net income includes certain items typically excluded by the investment community in published estimates, the result of which is referred to as "adjusted net income." In first quarter 2017, these typically excluded items in aggregate represented $6.3 million, or $0.02 per diluted share, of Continental's reported net income. Adjusted net income for the first quarter was $6.8 million, or $0.02 per diluted share.

Net cash provided by operating activities for first quarter 2017 was $470.2 million. EBITDAX for first quarter 2017 was $482.5 million. Definitions and reconciliations of adjusted net income, adjusted net income per share and EBITDAX to the most directly comparable U.S. generally accepted accounting principles (GAAP) financial measures are provided in the supporting tables at the conclusion of this press release.

"I am very pleased with the performance of our assets and operations so far this year. Relative to 2017 guidance, we are ahead on production, under on CAPEX and expect to be at the top-end or better than our production guidance for the year," said Harold Hamm, Chairman and Chief Executive Officer. "In the Bakken, we have seen industry-wide basin wellhead netbacks strengthen by approximately $2.00 per barrel with new pipeline capacity and additional markets becoming available. This will begin to positively impact our economics over the next several months."

Mr. Hamm noted that Continental continues to expand the strategic scope of its premier assets with the Sycamore reservoir in Oklahoma's SCOOP play. "On top of all of the other great news, we are pleased to announce the addition of approximately 300,000 net reservoir acres in Sycamore, a new reservoir layer within SCOOP. Our world-class asset portfolio continues to expand."

Production Accelerates in March

First quarter 2017 net production totaled 19.2 million barrels of oil equivalent (Boe), or 213,755 Boe per day, up approximately 4,000 Boe per day from fourth quarter 2016. March production averaged approximately 222,500 Boe per day. The Company now expects second quarter 2017 production will be in a range of 220,000 to 225,000 Boe per day. The Company is currently tracking at the top end or better than its annual production guidance, and if warranted, it will update guidance in August.

Total net production for first quarter 2017 included 119,201 barrels of oil (Bo) per day (56% of production) and 567 million cubic feet (MMcf) of natural gas per day (44% of production). Oil as a percentage of total production is expected to continue increasing to approximately 60% at year-end 2017.

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

   

1Q

 

4Q

 

1Q

Boe per day

 

2017

 

2016

 

2016

North Region:

           

North Dakota Bakken

 

101,012

 

96,035

 

129,168

Montana Bakken

 

7,980

 

8,489

 

10,434

Red River Units 

 

10,089

 

10,140

 

11,300

Other

 

333

 

4,109

 

649

South Region:

           

SCOOP

 

62,178

 

63,490

 

64,616

STACK

 

29,216

 

24,426

 

11,127

Arkoma

 

1,754

 

1,929

 

2,037

Other 

 

1,193

 

1,243

 

1,471

Total

 

213,755

 

209,861

 

230,802

Bakken: Outperformance Continues as a Result of Optimized Completions

Continental's Bakken net production averaged 108,992 Boe per day in first quarter 2017. The Company had 50 gross (17 net) operated and non-operated Bakken wells with first production during first quarter 2017.

In the first quarter there were 16 gross operated wells with first production, all of which were completed using the Company's optimized completion techniques, which includes tighter stage spacing, increased proppant per foot, diverter technology, more aggressive flowback, and high-capacity lift technology.

Of these, 14 gross operated wells had 30 days or more of production, and all are outperforming the 980 MBoe (thousand Boe) estimated ultimate recovery (EUR) type curve by an average of 65% at 30 days. Based on an average well cost of $7.0 million and $55 WTI, the 14 wells are expected to average approximately a 75% rate of return, almost double the 40% rate of return originally targeted by the 2017 Bakken drilling program.

Included in this group are four wells with record 30-day production rates:

  • 1,853 Boe per day (79% oil) from a 9,400-foot lateral (Akron Federal 7-27H);
  • 1,833 Boe per day (79% oil) from a 9,700-foot lateral (Radermecher 2-22H1);
  • 1,618 Boe per day (78% oil) from a 9,500-foot lateral (Radermecher 4-22H2); and
  • 1,543 Boe per day (79% oil) from a 10,100-foot lateral (Charlotte 7X-22H).

Continental previously announced seven optimized Bakken completions in February 2017, and they continue to outperform the Bakken 980 MBoe EUR type curve by an average of 55% at 150 days, compared with 35% outperformance of the type curve model at 90 days.

"Our optimized completions are another game changer for the Bakken," said Jack Stark, President. "This technology is delivering record 30-day production rates and almost doubling the rates of return expected from our previous economic models."

Drilling performance continues to advance year-over-year with first quarter 2017 spud-to-total depth cycle times averaging 12 days, a 16% reduction over full-year 2016. 

Continental has four operated drilling rigs working in the Bakken and plans to maintain that level through year end. The Company also has seven stimulation crews working in the play and plans to be at nine by mid-year.

SCOOP: Springer Delivers Impressive Results

In first quarter 2017, SCOOP net production averaged 62,178 Boe per day (27% oil), or 29% of the Company's total production in first quarter. Continental had 14 gross (5 net) operated and non-operated wells with first production in first quarter 2017. Continental currently has five operated drilling rigs working in SCOOP.

During the quarter, Continental announced three SCOOP Springer wells. All three wells are outperforming the Company's historical 940 MBoe Springer type curve for a 4,500-foot lateral in their first 30-to-60 days on production. The Cash 1-26H well is outperforming the type curve by 75% at 30 days, the Strassle 1-28-33XH is outperforming the type curve by 35% at 60 days, and the Trammel 1-11-14-23XH is outperforming the type curve by 100% at 60 days.

The wells are located in Grady County, Oklahoma and are the first Springer wells completed by the Company since third quarter 2015. The wells were completed using the Company's latest stimulation designs, including increased proppant per foot and tighter stage spacing. 

Initial 24-hour production test rates for these wells are as follows:   

  • 1,691 Boe per day (84% oil) from a 4,775-foot lateral (Cash 1-26H);
  • 2,300 Boe per day (79% oil) from an 8,300-foot lateral (Trammell 1-11-14-23XH); and
  • 1,257 Boe per day (89% oil) from a 5,800-foot lateral (Strassle 1-28-33XH).

Springer drilling times were also reduced through improved drilling and directional control technology. The Cash 1-26H, which was a 4,775-foot lateral, was drilled in 34 days from spud to total depth, down 45% from comparable wells drilled in third quarter 2015. Including costs for the larger stimulation, total completed well cost for the Cash 1-26H was $7.6 million, down $2.7 million, or approximately 25%, compared to the third quarter 2015 Springer wells.  

The Company has elected to increase activity in the Springer during 2017 and now plans to complete up to 10 Springer wells during the year.

The Company has approximately 197,000 net acres in the SCOOP Springer, which is located approximately 1,000 feet above the Woodford formation.

Sycamore Further Expands SCOOP Asset Value

Continental announced its first two well completions targeting the Sycamore formation in Grady County, adding yet another highly productive layer in SCOOP to its portfolio. The Company has approximately 300,000 net reservoir acres in the Sycamore, which lies directly above the Woodford formation.  

Initial 24-hour production test rates for the Company's new wells included:

  • 7.8 MMcf and 225 Bo per day with a flowing casing pressure of 3,200 psi from a 5,800-foot lateral (Ryan Express 1-18-19XH); and
  • 12.2 MMcf and 109 Bo per day with a flowing casing pressure of 3,900 psi from a 7,900-foot lateral (Pudge 1-7-6XH).

The wells have been on production approximately 170 and 180 days, respectively.

Continental is projecting that its SCOOP Sycamore wells will have an average EUR between 1.6 and 2.0 MMBoe, based on a 7,500-foot lateral.

"We are excited about Continental's Sycamore position and the added value it will bring to the Company," said Mr. Stark. "We plan to drill five to seven additional wells during the year focused on delineating the high-liquids windows of the play."

STACK: Continued Successful Well Results

STACK production increased 20% to 29,216 Boe per day in first quarter 2017, compared to fourth quarter 2016. Continental had 27 gross (8 net) operated and non-operated wells with first production in STACK in first quarter 2017.

The Company reported three operated standalone wells in the STACK Meramec over-pressured oil window and one operated well in the over-pressured condensate window.

Initial 24-hour production test rates and flowing casing pressures in pounds per square inch (psi) for these wells included:

  • 2,865 Boe per day (74% oil) flowing at 2,850 psi from a 4,575-foot lateral (Swaim 1-14H);
  • 2,104 Boe per day (51% oil) flowing at 2,910 psi from a 4,800-foot lateral (Mowery 1-36H);
  • 1,907 Boe per day (59% oil) flowing at 3,925 psi from a 10,500-foot lateral (Herod FIU 1-8-5XH); and
  • 3,011 Boe per day (10% oil) flowing at 4,400 psi from a 10,100-foot lateral (Nuzum 1-12-1XH).

The Company has 11 operated rigs in the play, with six rigs targeting the Meramec formation in the over-pressured oil and condensate windows and five targeting the Woodford formation in the Northwest Cana joint development agreement area in Blaine and Custer counties.

Financial Update

"Improving production results, strong cash management and additional operating efficiencies combined to deliver an excellent first quarter," said John Hart, Chief Financial Officer. "This enabled us to come in $33 million below budget on non-acquisition capital expenditures and to reduce debt by $70 million for the quarter."

Continental continues to see accelerating production growth throughout the year and thereafter, he said. "We expect to achieve annual production growth of 20% from 2018 through 2020 while reducing debt below $6 billion. These plans are cash neutral each year at oil prices between $50 and $55 per barrel, reflecting strong well productivity and cost efficiency."

In first quarter 2017, Continental's average realized sales price excluding the effects of derivative positions was $44.69 per barrel of oil and $3.00 per Mcf of gas, or $32.90 per Boe. Based on realizations without the effect of derivatives, the Company's first quarter 2017 oil differential was $7.09 per barrel below the NYMEX daily average for the period. The realized wellhead natural gas price for the quarter was on average $0.29 per Mcf below the average NYMEX Henry Hub benchmark price.      

Production expense per Boe was $3.78 for first quarter 2017. Other select operating costs and expenses for first quarter 2017 included production taxes of 6.5% of oil and natural gas sales; DD&A of $19.84 per Boe; and total G&A of $2.45 per Boe.

Non-acquisition capital expenditures for first quarter 2017 totaled approximately $427.0 million, which was 7% lower than budgeted. Non-acquisition capital expenditures for the quarter included $329.8 million in exploration and development drilling, $69.8 million in leasehold and seismic, and $27.4 million in workovers, recompletions and other. 

As of March 31, 2017, Continental's balance sheet included approximately $17.2 million in cash and cash equivalents and $6.5 billion in long-term debt.

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.

 

1Q

 

4Q

 

1Q

 

2017

 

2016

 

2016

Average daily production:

         

Crude oil (Bbl per day)

119,201

 

116,486

 

146,469

Natural gas (Mcf per day)

567,328

 

560,251

 

505,998

Crude oil equivalents (Boe per day)

213,755

 

209,861

 

230,802

Average sales prices, excluding effect from derivatives:

         

Crude oil ($/Bbl)

$44.69

 

$42.23

 

$25.72

Natural gas ($/Mcf)

$3.00

 

$2.70

 

$1.36

Crude oil equivalents ($/Boe)

$32.90

 

$30.64

 

$19.27

Production expenses ($/Boe)

$3.78

 

$3.60

 

$3.76

Production taxes (% of oil and gas revenues)

6.5%

 

6.4%

 

7.6%

DD&A ($/Boe)

$19.84

 

$20.11

 

$22.16

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

$2.45

 

$2.93

 

$1.55

Net income (loss) (in thousands) 

$469

 

$27,670

 

($198,326)

Diluted net income (loss) per share

$0.00

 

$0.07

 

($0.54)

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

$6,782

 

($27,416)

 

($150,467)

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

$0.02

 

($0.07)

 

($0.41)

Net cash provided by operating activities

$470,201

 

$262,031

 

$278,902

EBITDAX (non-GAAP) (in thousands) (2)

$482,472

 

$652,382

 

$314,609

 

(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 $1.86, $2.21, and $1.11 for 1Q 2017, 4Q 2016, and 1Q 2016, respectively. Non-cash equity compensation expense per Boe was $0.59, $0.72, and $0.44 for 1Q 2017, 4Q 2016, and 1Q 2016, 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.

First Quarter Earnings Conference Call

Continental plans to host a conference call to discuss first quarter results on Thursday, May 4, 2017, 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 http://www.clr.com/ or by phone:

Time and date:

12 p.m. ET, Thursday, May 4, 2017

Dial in:

844-309-6572

Intl. dial in:

484-747-6921

Pass code:

85738716

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:

85738716

Continental plans to publish a first quarter 2017 summary presentation to its website at http://www.clr.com/ prior to the start of its earnings conference call on May 4, 2017. 

Upcoming Conferences

Members of Continental's management team plan to participate in the following investment conferences:

May 8-9, 2017

Morgan Stanley E&P and Oil Services Conference, Houston

May 23, 2017

UBS Global Oil and Gas Conference, Austin

June 6, 2017

RBC Global Energy & Power Executive Conference, New York

June 6, 2017

Bank of America Merrill Lynch High Yield Conference, New York

June 19-20, 2017

Wells Fargo West Coast Energy Conference, San Francisco  

About Continental Resources

Continental Resources (NYSE: CLR) is a top 15 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 significant positions in Oklahoma, including its SCOOP Woodford and SCOOP Springer discoveries and the STACK 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 2017, the Company will celebrate 50 years of operations. For more information, please visit http://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 December 31, 2016, 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 March 31,

 

2017

 

2016

Revenues:

In thousands, except per share data

Crude oil and natural gas sales

$633,850

 

$ 403,592

Gain on crude oil and natural gas derivatives, net

46,858

 

42,112

Crude oil and natural gas service operations

4,719

 

7,470

Total revenues

685,427

 

453,174

       

Operating costs and expenses:

     

Production expenses

72,854

 

78,640

Production taxes

41,234

 

30,493

Exploration expenses

4,998

 

3,066

Crude oil and natural gas service operations

2,837

 

3,043

Depreciation, depletion, amortization and accretion

382,156

 

463,992

Property impairments

51,372

 

78,927

General and administrative expenses 

47,220

 

32,407

Net loss on sale of assets and other

5,535

 

1,709

Total operating costs and expenses

608,206

 

692,277

Income (loss) from operations

77,221

 

(239,103)

Other income (expense):

     

Interest expense

(71,172)

 

(80,953)

Other 

442

 

384

 

(70,730)

 

(80,569)

Income (loss) before income taxes

6,491

 

(319,672)

(Provision) benefit for income taxes (1)

(6,022)

 

121,346

Net income (loss)

$      469

 

$(198,326)

Basic net income (loss) per share

$          -

 

$      (0.54)

Diluted net income (loss) per share

$          -

 

$      (0.54)

 

(1) In 1Q 2017 we adopted ASU 2016-09, Compensation—Stock Compensation (Topic 718): Improvements to Employee Share-Based Payment Accounting, which requires, among other things, that companies recognize excess tax benefits and deficiencies from stock-based compensation as income tax benefit or expense in the income statement rather than through additional paid-in-capital. This change resulted in a $3.3 million increase in income tax expense in 1Q 2017 with no comparable impact in the prior period. 

 

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

 
 

March 31, 2017

 

December 31, 2016

Assets

In thousands

Current assets

$

929,506

 

$

913,233

Net property and equipment (1)

 

12,880,357

   

12,881,227

Other noncurrent assets

 

16,197

   

17,316

Total assets

$

13,826,060

 

$

13,811,776

           

Liabilities and shareholders' equity

         

Current liabilities 

$

1,005,321

 

$

932,393

Long-term debt, net of current portion

 

6,508,209

   

6,577,697

Other noncurrent liabilities

 

2,003,176

   

1,999,690

Total shareholders' equity

 

4,309,354

   

4,301,996

Total liabilities and shareholders' equity

$

13,826,060

 

$

13,811,776

           

(1) Balance is net of accumulated depreciation, depletion and amortization of $8.03 billion and $7.65 billion as of March 31, 2017 and December 31, 2016, respectively.

 

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

 
   

Three months ended March 31,

In thousands

 

2017

   

2016

Net income (loss)

 

$

469

 

$

(198,326)

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

           

Non-cash expenses

   

411,955

   

432,774

Changes in assets and liabilities

   

57,777

   

44,454

Net cash provided by operating activities

   

470,201

   

278,902

Net cash used in investing activities

   

(389,271)

   

(358,811)

Net cash (used in) provided by financing activities

   

(80,385)

   

81,342

Effect of exchange rate changes on cash

   

-

   

31

Net change in cash and cash equivalents

   

545

   

1,464

Cash and cash equivalents at beginning of period

   

16,643

   

11,463

Cash and cash equivalents at end of period

 

$

17,188

 

$

12,927

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 (loss) 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.  

In thousands

   

1Q 2017

   

4Q 2016

   

1Q 2016

Net income (loss)

 

$

469

 

$

27,670

 

$

(198,326)

Interest expense

   

71,172

   

75,613

   

80,953

Provision (benefit) for income taxes

   

6,022

   

26,478

   

(121,346)

Depreciation, depletion, amortization and accretion

   

382,156

   

388,321

   

463,992

Property impairments

   

51,372

   

34,564

   

78,927

Exploration expenses

   

4,998

   

8,246

   

3,066

Impact from derivative instruments:

                 

Total (gain) loss on derivatives, net

   

(44,961)

   

45,331

   

(41,052)

Total cash (paid) received on derivatives, net

   

(194)

   

6,281

   

39,189

Non-cash (gain) loss on derivatives, net

   

(45,155)

   

51,612

   

(1,863)

Non-cash equity compensation

   

11,438

   

13,823

   

9,206

Loss on extinguishment of debt

   

-

   

26,055

   

-

EBITDAX

 

$

482,472

 

$

652,382

 

$

314,609

                   

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

                   
     
     

In thousands

   

1Q 2017

   

4Q 2016

   

1Q 2016

Net cash provided by operating activities

 

$

470,201

 

$

262,031

 

$

278,902

Current income tax provision

   

1

   

(22,941)

   

6

Interest expense

   

71,172

   

75,613

   

80,953

Exploration expenses, excluding dry hole costs

   

4,841

   

3,613

   

3,066

Gain (loss) on sale of assets, net

   

(3,638)

   

201,315

   

109

Other, net

   

(2,328)

   

(1,981)

   

(3,973)

Changes in assets and liabilities

   

(57,777)

   

134,732

   

(44,454)

EBITDAX

 

$

482,472

 

$

652,382

 

$

314,609

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 losses on extinguishment of debt. 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 table reconciles earnings and diluted earnings per share as determined under U.S. GAAP to adjusted earnings and adjusted diluted earnings per share for the periods presented.

       

1Q 2017

 

4Q 2016

 

1Q 2016

In thousands, except per share data

 

After-Tax $

 

Diluted

EPS

 

After-Tax $

 

Diluted

EPS

 

After-Tax $

 

Diluted

EPS

Net income (loss) (GAAP) (1)

 

$       469

 

$   -

 

$  27,670

 

$ 0.07

 

$(198,326)

 

$(0.54)

Adjustments:

                       

Non-cash (gain) loss on derivatives

 

(45,155)

     

51,612

     

(1,863)

   

Property impairments

 

51,372

     

34,564

     

78,927

   

(Gain) loss on sale of assets

 

3,638

     

(201,315)

     

(109)

   

Loss on extinguishment of debt

 

-

     

26,055

     

-

   

Total tax effect of adjustments

 

(3,542)

     

33,998

     

(29,096)

   

Total adjustments, net of tax

 

6,313

 

0.02

 

(55,086)

 

(0.14)

 

47,859

 

0.13

Adjusted net income (loss) (non-GAAP)

 

$    6,782

 

$0.02

 

$ (27,416)

 

$(0.07)

 

$(150,467)

 

$(0.41)

Weighted average diluted shares outstanding

 

373,353

     

370,539

     

370,062

   

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

 

$      0.02

     

$     (0.07)

     

$     (0.41)

   
                             

(1) In 1Q 2017 we adopted ASU 2016-09, Compensation-Stock Compensation (Topic 718): Improvements to Employee Share-Based Payment Accounting, which requires, among other things, that companies recognize excess tax benefits and deficiencies from stock-based compensation as income tax benefit or expense in the income statement rather than through additional paid-in capital. This change resulted in a $3.3 million ($0.01 per diluted share) decrease in net income in 1Q 2017 with no comparable impact in the prior period.

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. 

2017 Guidance

As of May 3, 2017

     
   

2017

     

Full year average production 

 

220,000 to 230,000 Boe per day

Exit rate average production 

 

250,000 to 260,000 Boe per day 

Capital expenditures (non-acquisition)

 

$1.95 billion 

     

Operating Expenses:

   

     Production expense per Boe

 

$3.50 to $4.00

     Production tax (% of oil & gas revenue)

 

6.75% to 7.25%

     Cash G&A expense per Boe(1)

 

$1.50 to $2.00

     Non-cash equity compensation per Boe

 

$0.60 to $0.70

     DD&A per Boe

 

$19.00 to $22.00

     

Average Price Differentials:

   

     NYMEX WTI crude oil (per barrel of oil)

 

($6.50) to ($7.50)

     Henry Hub natural gas (per Mcf)

 

$0.10 to ($0.40)

     

Income tax rate

 

38%

Deferred taxes

 

90% to 95%

 

(1) 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. Guidance for total G&A (cash and non-cash) is an expected range of $2.10 to $2.70 per Boe. 

 

SOURCE Continental Resources

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