Continental Resources, Inc.

News Release

Continental Resources Reports Third Quarter 2018 Results
$314.2 Million in Net Income, or $0.84 per Diluted Share
- $337.0 Million Adjusted Net Income, or $0.90 per Diluted Share (Non-GAAP)
$215 Million in Proceeds Received in October from Minerals Venture Closing
296,900 Boepd Average Daily 3Q18 Production; Beats 3Q18 Guidance & Consensus
- 164,605 Bopd Average Daily 3Q18 Oil Production; up 5% over 2Q18 and up 17% over 3Q17
- Oil as Percent of Production Rising: Approximately 57% in September
Bakken: 167,643 Boepd Average Daily 3Q18 Production; up 23% over 3Q17
- Significant 4Q18 Ramp with up to 70 Gross Operated Wells to be Completed by YE18 (Compared to 42 Gross Operated Wells Completed in 3Q18)
STACK: 3 Meramec Units Flow at Combined Initial Rate of 74,260 Boepd (24-Hr. IP)
- 18 Wells in the Over-Pressured Window with 6 Equivalent 2-Mile Wells in Each Unit:
- Jalou Unit Avg. 24-Hour IP per Well: 2,470 Bopd and 10,587 Mcfpd (4,234 Boepd)
- Homsey Unit Avg. 24-Hr IP per Well: 2,071 Bopd and 8,701 Mcfpd (3,521 Boepd)
- Simba Unit Avg. 24-Hr IP per Well: 621 Bopd and 24,001 Mcfpd (4,622 Boepd)
SCOOP: Project SpringBoard Proceeding on Schedule with 14 Rigs Drilling
- 9 Springer Wells Begin Flow-Back

OKLAHOMA CITY, Oct. 29, 2018 /PRNewswire/ -- Continental Resources, Inc. (NYSE: CLR) (the Company) today announced third quarter operating and financial results. The Company reported net income of $314.2 million, or $0.84 per diluted share, for the quarter ended September 30, 2018. 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 third quarter 2018, these typically excluded items in aggregate represented $22.8 million, or $0.06 per diluted share, of Continental's reported net income. Adjusted net income for third quarter 2018 was $337.0 million, or $0.90 per diluted share.

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Net cash provided by operating activities for third quarter 2018 was $860.7 million. EBITDAX for third quarter 2018 was $1.0 billion. Definitions and reconciliations of adjusted net income, adjusted net income per share, free cash flow, EBITDAX, net debt, net sales prices and cash general and administrative (G&A) expenses per barrel of oil equivalent (Boe) presented herein 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.

The Company's third quarter 2018 crude oil differential was $3.72 per barrel below the NYMEX daily average for the period, an improvement of $1.26 per barrel compared to third quarter 2017 due to strong Gulf Coast pricing, strong seasonal demand and lower Cushing inventories. The realized wellhead natural gas price for third quarter 2018 was a premium of $0.22 per Mcf compared to the average NYMEX Henry Hub benchmark price.     

"With up to 70 of our forecasted 2018 Bakken wells and up to 18 SpringBoard wells scheduled to be completed by year end, Continental anticipates a strong wave of oil-weighted production growth as we approach year end," said Harold Hamm, Chairman and Chief Executive Officer. "Thanks to the quality of our oil assets, the ingenuity of our teams, and the positive tailwind provided by our unhedged oil portfolio, Continental's strategic move to optimize capital-efficient, oil-weighted growth is enhancing shareholder value."

$215 Million in Proceeds Received in October from Minerals Venture Closing

On October 23, 2018, the Company closed its strategic minerals agreement with Franco-Nevada. The Company received approximately $215 million in net proceeds at closing, which offset previously incurred Capex for acquired minerals. Moving forward, the minerals relationship will capitalize on the Company's land and exploration expertise and will focus predominantly on acquiring minerals under the Company's drill plan. To grow the minerals portfolio, Franco-Nevada has committed up to $300 million over the next three years, while the Company has committed up to $75 million (or 20% of the total investment) over the next three years, subject to achieving agreed upon development thresholds. With a carry structure in place, the Company will earn 25-50% of total revenue from the minerals venture, based on achieving certain predetermined targets.

Production Update

Third quarter 2018 production totaled 27.3 million barrels of oil equivalent (Boe), or 296,904 Boe per day, up 22% from third quarter 2017. Total production for third quarter included 164,605 barrels of oil (Bo) per day, as well as 793.8 million cubic feet (MMcf) of natural gas per day. The following table provides the Company's average daily production by region for the periods presented.



3Q


2Q


3Q


YTD


YTD

Boe per day


2018


2018


2017


2018


2017

North Region:











North Dakota Bakken


161,008


151,805


129,582


155,796


114,435

Montana Bakken


6,635


6,314


7,269


6,600


7,569

Red River Units 


8,989


8,404


9,536


8,909


9,832

Other


26


258


449


232


422

South Region:











SCOOP


63,270


64,786


57,283


63,360


60,171

STACK


56,129


51,722


35,619


53,733


32,280

Arkoma(1)


8


9


1,722


6


1,755

Other 


839


761


1,328


856


1,228

Total


296,904


284,059


242,788


289,492


227,692


(1) Producing properties comprising approximately 1,700 Boe per day of the Company's Arkoma production were sold in September 2017.

Bakken: 167,643 Boepd Average Daily 3Q18 Production; up 23% over 3Q17

The Company's Bakken production hit an all-time quarterly record, averaging 167,643 Boe per day in third quarter 2018, up 23% versus third quarter 2017. During the quarter, the Company completed 42 gross (26 net) operated wells flowing at an average initial 24-hour rate of 2,013 Boe per day. Two of the wells ranked as top ten 30-day rate Bakken wells for the Company, including the Wiley 8-25H (2,289 Boe per day) and Mountain Gap 3-10H (2,094 Boe per day). All Company top ten 30-day rate Bakken wells have been completed in the past twelve months.

The Company currently has 8 rigs drilling in the Bakken, up 2 rigs from last quarter to facilitate continued oil growth in 2019. In fourth quarter 2018, production is expected to ramp significantly with up to 70 wells forecasted to be completed by year end 2018.

"The performance and returns from the Bakken have been exceptional," said Jack Stark, President. "Our entire 2017 Bakken program, which included 133 operated wells, paid out by the end of third quarter 2018. Now that's capital efficiency."

STACK: 3 Meramec Units Flow at Combined Initial Rate of 74,260 Boepd (24-Hr. IP)     

The Company's STACK production increased 58% to 56,129 Boe per day in third quarter 2018, compared to third quarter 2017. During the quarter, the Company completed 15 gross (7 net) operated wells with first production. The Company currently has 5 operated drilling rigs in STACK.

The Company recently completed three outstanding Meramec units in the over-pressured oil and condensate windows of STACK. All three units were developed with the equivalent of six, two-mile wells. In the oil window, the Jalou unit flowed at a combined initial 24-hour rate of 25,404 Boe per day, averaging 2,470 Bo per day per well and 10,587 Mcf per day per well. At an average 24-hour rate of 4,234 Boe per day, the Jalou wells set an industry record for fully developed units in the STACK over-pressured oil window. Additionally in the oil window, the Homsey unit flowed at a combined initial 24-hour rate of 21,127 Boe per day, averaging 2,071 Bo per day per well and 8,701 Mcf per day per well. In the condensate window, the Simba unit flowed at a combined initial 24-hour rate of 27,729 Boe per day, averaging 621 Bo per day per well and 24,001 Mcf per day per well.

"The outstanding results from these units confirm both our unit development model and the exceptional quality of our Meramec reservoirs, which are some of the thickest and most over-pressured in STACK," said Tony Barrett, Vice President, Exploration. "These results demonstrate the potential of our operated STACK inventory with up to 65 units remaining to develop in the oil and condensate windows."  

The following table provides the average initial 24-hour rates per well for recent STACK units:

Unit

2-Mi Equiv. Wells
per Unit

Bopd per Well

Mcfpd per Well

Boepd per Well

Jalou

6

2,470

10,587

4,234

Homsey

6

2,071

8,701

3,521

Simba

6

621

24,001

4,622

SCOOP: Project SpringBoard Proceeding on Schedule with 14 Rigs Drilling

The Company's SCOOP production averaged 63,270 Boe per day in third quarter 2018, up 10% versus third quarter 2017. The Company's SCOOP crude oil production in third quarter 2018 increased 33% over third quarter 2017. The Company completed 9 gross (7 net) operated wells with first production in third quarter 2018. The Company currently has 16 operated drilling rigs in SCOOP, ramping up to 18 by year end.

Project SpringBoard is proceeding on schedule with 14 rigs drilling, 8 of which are targeting the Springer reservoir and 6 of which are targeting the Woodford and Sycamore reservoirs. In the Springer, the Company has finished drilling 17 of the 18 wells planned for row 1 and has begun drilling row 2. Of the 17 Springer wells drilled, 9 are flowing-back and 8 are in various stages of completions. In the Woodford and Sycamore, the Company has finished drilling 9 wells to date.

"Project SpringBoard is a massive oil project where we are concurrently developing three reservoirs," said Gary Gould, Senior Vice President of Production & Resource Development. "As expected, we are already realizing operational efficiencies that will translate to significant additional value for our shareholders."

Financial Update

"Continental's strong third quarter and early fourth quarter results reflect our strategic decision to focus operations on oil-weighted production growth," said John Hart, Chief Financial Officer. "Continental is poised to deliver a strong exit rate, increase our oil production growth and continue to use significant free cash flow to further reduce debt toward our long-term target of $5 billion or below."  

As of September 30, 2018, the Company's balance sheet included approximately $13 million in cash and cash equivalents and $5.96 billion in total debt. On September 30, 2018, net debt (non-GAAP) was $5.94 billion. Net debt is projected to be between $5.4 and $5.6 billion at year end 2018, driven by strong cash flow. The Company's third quarter annualized net-debt-to-EBITDAX ratio was 1.49x and has now reached levels seen prior to the three-year commodity down cycle.

In third quarter 2018, the Company's average net sales price excluding the effects of derivative positions was $65.78 per barrel of oil and $3.12 per Mcf of gas, or $44.85 per Boe. The Company remains unhedged on oil. Production expense per Boe was $3.77 for third quarter 2018.

Non-acquisition capital expenditures for third quarter 2018 totaled approximately $790.8 million, including $633.5 million in exploration and development drilling, $105.5 million in leasehold, and $51.8 million in workovers, recompletions and other. Non-acquisition capital expenditures for third quarter were slightly higher than projected due to timing of completions that will see first production in fourth quarter 2018 or in 2019.  

The following table provides the Company's production results, per-unit operating costs, results of operations and certain non-GAAP financial measures for the periods presented. Average net sales prices exclude any effect of derivative transactions. Per-unit expenses have been calculated using sales volumes.


Three months ended September 30,


Nine months ended September 30,


2018


2017


2018


2017

Average daily production:








Crude oil (Bbl per day)

164,605


140,611


161,856


128,476

Natural gas (Mcf per day)

793,793


613,060


765,821


595,294

Crude oil equivalents (Boe per day)

296,904


242,788


289,492


227,692

Average net sales prices (non-GAAP), excluding effect from derivatives: (1)








Crude oil ($/Bbl)

$65.78


$43.27


$62.73


$43.26

Natural gas ($/Mcf)

$3.12


$2.74


$2.92


$2.78

Crude oil equivalents ($/Boe)

$44.85


$31.86


$42.80


$31.67

Production expenses ($/Boe) 

$3.77


$3.82


$3.62


$3.86

Production taxes (% of net crude oil and gas sales)

8.0%


7.3%


7.8%


6.8%

DD&A ($/Boe)

$17.15


$19.00


$17.35


$19.31

Total general and administrative expenses ($/Boe) (2)

$1.61


$1.99


$1.70


$2.10

Net income (loss) (in thousands)

$314,169


$10,621


$790,580


($52,467)

Diluted net income (loss) per share

$0.84


$0.03


$2.11


($0.14)

Adjusted net income (non-GAAP) (in thousands) (1) 

$337,017


$32,162


$865,033


$37,142

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

$0.90


$0.09


$2.31


$0.10

Net cash provided by operating activities (in thousands)

$860,748


$431,409


$2,500,741


$1,347,981

EBITDAX (non-GAAP) (in thousands) (1)

$999,882


$563,767


$2,772,733


$1,525,730


(1) Net sales prices, adjusted net income, adjusted diluted net income per share, and EBITDAX represent non-GAAP financial measures. Further information about these non-GAAP financial measures as well as reconciliations to the most directly comparable U.S. GAAP financial measures are provided subsequently under the header Non-GAAP Financial Measures.


(2) 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 $1.18, $1.45, $1.28, and $1.58 for 3Q 2018, 3Q 2017, YTD 2018 and YTD 2017, respectively. Non-cash equity compensation expense per Boe was $0.43, $0.54, $0.42, and $0.52 for 3Q 2018, 3Q 2017, YTD 2018 and YTD 2017, respectively. 

Third Quarter Earnings Conference Call

Continental plans to host a conference call to discuss third quarter results on Tuesday, October 30, 2018, 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, Tuesday, October 30, 2018

Dial in:

844-309-6572

Intl. dial in:

484-747-6921

Pass code:

3745129

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:

3745129

Continental plans to publish a third quarter 2018 summary presentation to its website at www.CLR.com prior to the start of its earnings conference call on October 30, 2018. 

Upcoming Conferences

Members of Continental's management team expect to participate in the following investment conference:

November 14-15, 2018     Bank of America Global Energy Conference – Miami, Florida

Presentation materials for the conference mentioned above will be available on the Company's web site at www.CLR.com prior to the start of the Company's presentation at such conference.

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 the largest producer in the nation's premier oil field, the Bakken play of North Dakota and Montana. The Company also has significant positions in Oklahoma, including its 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 2018, the Company will celebrate 51 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, 2017, 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:

Rory Sabino

Kristin Thomas

Vice President, Investor Relations

Senior Vice President, Public Relations

405-234-9620

405-234-9480

Rory.Sabino@CLR.com

Kristin.Thomas@CLR.com



Lucy Guttenberger


Senior Investor Relations Associate


405-774-5878


Lucy.Guttenberger@CLR.com


 

Continental Resources, Inc. and Subsidiaries

Unaudited Condensed Consolidated Statements of Income (Loss)



Three months ended September 30, 


Nine months ended September 30,


2018


2017


2018


2017

Revenues:

In thousands, except per share data

Crude oil and natural gas sales

$ 1,273,238


$ 704,818


$ 3,524,618


$ 1,965,216

Gain (loss) on natural gas derivatives, net

(2,025)


8,602


(4,536)


83,482

Crude oil and natural gas service operations

10,938


13,323


40,210


24,959

Total revenues

1,282,151


726,743


3,560,292


2,073,657









Operating costs and expenses:








Production expenses

103,032


84,514


286,165


239,842

Production taxes

98,572


51,264


262,747


134,462

Transportation expenses

46,008


-


142,559


-

Exploration expenses

2,324


1,389


4,347


9,591

Crude oil and natural gas service operations

5,163


3,349


17,434


10,664

Depreciation, depletion, amortization and accretion

469,333


420,243


1,370,912


1,198,169

Property impairments

23,770


35,130


86,715


209,819

General and administrative expenses 

44,151


44,006


134,368


130,413

Net (gain) loss on sale of assets and other

(1,510)


(4,905)


(8,261)


764

Total operating costs and expenses

790,843


634,990


2,296,986


1,933,724

Income from operations

491,308


91,753


1,263,306


139,933

Other income (expense):








Interest expense

(73,409)


(74,756)


(223,590)


(218,672)

Loss on extinguishment of debt

(7,133)


-


(7,133)


-

Other 

869


394


2,231


1,209


(79,673)


(74,362)


(228,492)


(217,463)

Income (loss) before income taxes

411,635


17,391


1,034,814


(77,530)

(Provision) benefit for income taxes

(97,466)


(6,770)


(244,234)


25,063

Net income (loss)

$   314,169


$  10,621


$   790,580


$    (52,467)

Basic net income (loss) per share

$         0.84


$      0.03


$         2.13


$        (0.14)

Diluted net income (loss) per share

$         0.84


$      0.03


$         2.11


$        (0.14)


 

Continental Resources, Inc. and Subsidiaries

Unaudited Condensed Consolidated Balance Sheets



September 30, 2018


December 31, 2017

Assets

In thousands

Cash and cash equivalents

$

12,896


$

43,902

Other current assets


1,356,241



1,207,823

Net property and equipment (1)


13,644,538



12,933,789

Other noncurrent assets


17,385



14,137

Total assets

$

15,031,060


$

14,199,651







Liabilities and shareholders' equity






Current liabilities 

$

1,490,449


$

1,330,242

Long-term debt, net of current portion


5,955,326



6,351,405

Other noncurrent liabilities


1,646,475



1,386,801

Total shareholders' equity


5,938,810



5,131,203

Total liabilities and shareholders' equity

$

15,031,060


$

14,199,651



(1) Balance is net of accumulated depreciation, depletion and amortization of $10.33 billion and $9.08 billion as of September 30, 2018 and December 31, 2017, respectively.

 

Continental Resources, Inc. and Subsidiaries

Unaudited Condensed Consolidated Statements of Cash Flows




Three months ended September 30,


Nine months ended September 30,

In thousands


2018


2017


2018


2017

Net income (loss)


$

314,169


$

10,621


$

790,580


$

(52,467)

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













Non-cash expenses



619,284



480,718



1,764,566



1,358,639

Changes in assets and liabilities



(72,705)



(59,930)



(54,405)



41,809

Net cash provided by operating activities



860,748



431,409



2,500,741



1,347,981

Net cash used in investing activities



(759,880)



(494,934)



(2,103,483)



(1,374,254)

Net cash (used in) provided by financing activities



(217,976)



57,080



(428,253)



20,361

Effect of exchange rate changes on cash



15



20



(11)



34

Net change in cash and cash equivalents



(117,093)



(6,425)



(31,006)



(5,878)

Cash and cash equivalents at beginning of period



129,989



17,190



43,902



16,643

Cash and cash equivalents at end of period


$

12,896


$

10,765


$

12,896


$

10,765


Non-GAAP Financial Measures

Adjusted earnings (net income/loss) and adjusted earnings (net income/loss) 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 as applicable. 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 an alternative to, or more meaningful than, earnings or diluted earnings per share as determined in accordance with U.S. GAAP and may not be comparable to other similarly titled measures of other companies. The following table reconciles earnings and diluted earnings per share as determined under U.S. GAAP to adjusted earnings and adjusted diluted earnings per share for the periods presented.



Three months ended September 30,



2018


2017

In thousands, except per share data


$


Diluted EPS


$


Diluted EPS

Net income (GAAP)


$314,169


$        0.84


$ 10,621


$        0.03

Adjustments:









Non-cash loss on derivatives


548




2,939



Property impairments


23,770




35,130



Gain on sale of assets


(1,510)




(3,562)



Loss on extinguishment of debt


7,133




-



Total tax effect of adjustments (1)


(7,093)




(12,966)



Total adjustments, net of tax


22,848


0.06


21,541


0.06

Adjusted net income (non-GAAP)


$337,017


$        0.90


$ 32,162


$0.09

Weighted average diluted shares outstanding


374,623




373,015



Adjusted diluted net income per share (non-GAAP)


$     0.90




$0.09














Nine months ended September 30,



2018


2017

In thousands, except per share data


$


Diluted EPS


$


Diluted EPS

Net income (loss) (GAAP)


$790,580


$        2.11


$(52,467)


$       (0.14)

Adjustments:









Non-cash (gain) loss on derivatives


12,013




(65,481)



Property impairments


86,715




209,819



Gain on sale of assets


(8,261)




(703)



Loss on extinguishment of debt


7,133




-



Total tax effect of adjustments (1)


(23,147)




(54,026)



Total adjustments, net of tax


74,453


0.20


89,609


0.24

Adjusted net income (non-GAAP)


$865,033


$        2.31


$ 37,142


$        0.10

Weighted average diluted shares outstanding


374,762




373,588



Adjusted diluted net income per share (non-GAAP)


$     2.31




$     0.10




(1) Computed by applying a combined federal and state statutory tax rate of 24% in effect for 2018 and 38% in effect for 2017 to the pre-tax amount of adjustments associated with our operations in the United States.  

Net debt

Net debt is a non-GAAP measure. We define net debt as total debt less cash and cash equivalents as determined under U.S. GAAP. Net debt should not be considered an alternative to, or more meaningful than, the comparable GAAP measure. Management uses net debt to determine the Company's outstanding debt obligations that would not be readily satisfied by its cash and cash equivalents on hand. We believe this metric is useful to analysts and investors in determining the Company's leverage position since the Company has the ability to, and may decide to, use a portion of its cash and cash equivalents to reduce debt. This metric is sometimes presented as a ratio with EBITDAX in order to provide investors with another means of evaluating the Company's ability to service its existing debt obligations as well as any future increase in the amount of such obligations. At September 30, 2018, the Company's net debt amounted to $5.94 billion, representing total debt of $5.96 billion less cash and cash equivalents of $13 million. From time to time the Company provides forward-looking net debt forecasts; however, the Company is unable to provide a quantitative reconciliation of the forward-looking non-GAAP measure to its most directly comparable forward-looking GAAP measure because management cannot reliably quantify certain of the necessary components of such forward-looking GAAP measure. The reconciling items in future periods could be significant.

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 as applicable. 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 to EBITDAX for the periods presented.



Three months ended September 30,


Nine months ended September 30, 

In thousands



2018



2017



2018



2017

Net income (loss)


$

314,169


$

10,621


$

790,580


$

(52,467)

Interest expense



73,409



74,756



223,590



218,672

Provision (benefit) for income taxes



97,466



6,770



244,234



(25,063)

Depreciation, depletion, amortization and accretion



469,333



420,243



1,370,912



1,198,169

Property impairments



23,770



35,130



86,715



209,819

Exploration expenses



2,324



1,389



4,347



9,591

Impact from derivative instruments:













Total (gain) loss on derivatives, net



2,025



(9,945)



4,536



(82,015)

Total cash (paid) received on derivatives, net



(1,477)



12,884



7,477



16,534

Non-cash (gain) loss on derivatives, net



548



2,939



12,013



(65,481)

Non-cash equity compensation



11,730



11,919



33,209



32,490

Loss on extinguishment of debt



7,133



-



7,133



-

EBITDAX (non-GAAP)


$

999,882


$

563,767


$

2,772,733


$

1,525,730



























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












Three months ended September 30,


Nine months ended September 30, 

In thousands



2018



2017



2018



2017

Net cash provided by operating activities


$

860,748


$

431,409


$

2,500,741


$

1,347,981

Current income tax provision (benefit)



(7,778)



(1)



(7,778)



-

Interest expense



73,409



74,756



223,590



218,672

Exploration expenses, excluding dry hole costs



2,324



1,389



4,346



9,434

Gain on sale of assets, net



1,510



3,562



8,261



703

Other, net



(3,036)



(7,278)



(10,832)



(9,251)

Changes in assets and liabilities



72,705



59,930



54,405



(41,809)

EBITDAX (non-GAAP)


$

999,882


$

563,767


$

2,772,733


$

1,525,730

Free cash flow

Our presentation of free cash flow is a non-GAAP measure. We define free cash flow as cash flows from operations before changes in working capital items less capital expenditures, excluding acquisitions, plus non-controlling interest capital contributions, less distributions to non-controlling interests. The inclusion of non-controlling interest capital contributions and distributions, expected to begin in the fourth quarter of 2018, is related to our newly formed relationship with Franco-Nevada to fund a portion of certain mineral acquisitions which are included in our capital expenditures and operating results. Free cash flow is not a measure of net income or cash flows as determined by U.S. GAAP and should not be considered an alternative to, or more meaningful than, the comparable GAAP measure. Management believes that these measures are useful to management and investors as a measure of a company's ability to internally fund its capital expenditures and to service or incur additional debt. These measures eliminate the impact of certain items that management does not consider to be indicative of the Company's performance from period to period. From time to time the Company provides forward-looking free cash flow estimates; however, the Company is unable to provide a quantitative reconciliation of the forward-looking non-GAAP measure to its most directly comparable forward-looking GAAP measure because management cannot reliably quantify certain of the necessary components of such forward-looking GAAP measure. The reconciling items in future periods could be significant.

Net sales prices

On January 1, 2018, we adopted Accounting Standards Update 2016-08, Revenue from Contracts with Customers (Topic 606): Principal versus Agent Considerations (Reporting Revenue Gross versus Net), which impacted the presentation of our crude oil and natural gas revenues. We adopted the new rules using a modified retrospective transition approach whereby changes have been applied only to the most current period presented and prior period results have not been adjusted to conform to current presentation.

Under the new rules, revenues and transportation expenses associated with production from our operated properties are now reported on a gross basis compared to net presentation in the prior year. For non-operated properties, we receive a net payment from the operator for our share of sales proceeds which is net of costs incurred by the operator, if any. Such non-operated revenues are recognized at the net amount of proceeds received, consistent with our historical practice. As a result, beginning January 1, 2018 the gross presentation of revenues from our operated properties differs from the net presentation of revenues from non-operated properties. This impacts the comparability of certain operating metrics, such as per-unit sales prices, when such metrics are prepared in accordance with U.S. GAAP using gross presentation for some revenues and net presentation for others.

In order to provide metrics prepared in a manner consistent with how management assesses the Company's operating results, and to achieve comparability with prior period metrics for analysis purposes, we may present crude oil and natural gas sales net of transportation expenses, which we refer to as "net crude oil and natural gas sales," a non-GAAP measure. Average sales prices calculated using net crude oil and natural gas sales are referred to as "net sales prices," a non-GAAP measure, and are calculated by taking revenues less transportation expenses divided by sales volumes, whether for crude oil or natural gas, as applicable. Management believes presenting our revenues and sales prices net of transportation expenses is useful because it normalizes the presentation differences between operated and non-operated revenues and allows for a useful comparison of net realized prices to NYMEX benchmark prices on a Company-wide basis.

The following table presents a reconciliation of crude oil and natural gas sales (GAAP) to net crude oil and natural gas sales and related net sales prices (non-GAAP) for the three and nine months ended September 30, 2018. Information is also presented for the three and nine months ended September 30, 2017 for comparative purposes.



Three months ended September 30, 2018


Three months ended September 30, 2017

In thousands


Crude oil


Natural gas


Total


Crude oil


Natural gas


Total

Crude oil and natural gas sales (GAAP)


$1,038,558


$234,680


$1,273,238


$550,451


$154,367


$704,818

Less: Transportation expenses


(39,336)


(6,672)


(46,008)




Net crude oil and natural gas sales (non-GAAP for 2018)


$999,222


$228,008


$1,227,230


$550,451


$154,367


$704,818

Sales volumes (MBbl/MMcf/MBoe)


15,190


73,029


27,361


12,722


56,401


22,123

Net sales price (non-GAAP for 2018)


$65.78


$3.12


$44.85


$43.27


$2.74


$31.86
















Nine months ended September 30, 2018


Nine months ended September 30, 2017

In thousands


Crude oil


Natural gas


Total


Crude oil


Natural gas


Total

Crude oil and natural gas sales (GAAP)


$2,891,722


$632,896


$3,524,618


$1,512,990


$452,226


$1,965,216

Less: Transportation expenses


(119,939)


(22,620)


(142,559)




Net crude oil and natural gas sales (non-GAAP for 2018)


$2,771,783


$610,276


$3,382,059


$1,512,990


$452,226


$1,965,216

Sales volumes (MBbl/MMcf/MBoe)


44,183


209,069


79,028


34,975


162,515


62,061

Net sales price (non-GAAP for 2018)


$62.73


$2.92


$42.80


$43.26


$2.78


$31.67

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.

2018 Guidance

As of October 29, 2018




2018



Full-year average production 

290,000 to 300,000 Boe per day

Exit-rate average production 

315,000 to 325,000 Boe per day 

Capital expenditures budget (non-acquisition)

$2.7 billion 



Operating Expenses:


     Production expense per Boe

$3.50 to $3.75 (updated(1))

     Production tax (% of net oil & gas revenue)

7.6% to 8.0%

     Cash G&A expense per Boe(2)

$1.20 to $1.65

     Non-cash equity compensation per Boe

$0.40 to $0.50

     DD&A per Boe

$17.00 to $18.00



Average Price Differentials:


     NYMEX WTI crude oil (per barrel of oil)

($3.50) to ($4.50)

     Henry Hub natural gas (per Mcf)

$0.00 to +$0.50



(1) Updated from a prior guidance range of $3.00 to $3.50.  

(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. Guidance for total G&A (cash and non-cash) is an expected range of $1.60 to $2.15 per Boe. 

 

Cision View original content:http://www.prnewswire.com/news-releases/continental-resources-reports-third-quarter-2018-results-300739738.html

SOURCE Continental Resources