Continental Resources, Inc.

News Release

Continental Resources Reports Full-Year 2018 And 4Q18 Results
Full-Year 2018 Results
$988 Million in Net Income in 2018, or $2.64 per Diluted Share
- $1.07 Billion Adjusted Net Income in 2018, or $2.84 per Diluted Share (Non-GAAP)
~ 14% Average Full-Year 2018 Return on Capital Employed (ROCE)
298,190 Boepd Average Daily FY 2018 Total Production, up 23% over FY 2017
- 168,177 Bopd Average Daily FY 2018 Oil Production; up 21% over FY 2017
$585 Million Total Debt Reduction and $239 Million Cash Build since Dec. 2017 Resulting in Net Debt (Non-GAAP) Reduction of $824 Million since Dec. 2017
- $5.77 Billion in Total Debt and $5.49 Billion in Net Debt as of Dec. 2018
$3.59 per Boe Production Expense; 36% Reduction in the Last Four Years
1.52 Billion Boe Year-End 2018 Proved Reserves, up 14% over Year-End 2017
- Year-End 2018 Oil Reserves up 18% over Year-End 2017
4Q18 Results
$198 Million in Net Income in 4Q18, or $0.53 per Diluted Share
- $202 Million Adjusted Net Income in 4Q18, or $0.54 per Diluted Share (Non-GAAP)
324,001 Boepd Average Daily 4Q18 Production; up 9% over 3Q18
- 186,934 Bopd Average Daily 4Q18 Oil Production; up 14% over 3Q18
Bakken: 183,836 Boepd Average Daily 4Q18 Production; up 10% over 3Q18
- 2,800 Boepd Average 24-Hour IP per Well for 52 Gross Operated Wells in 4Q18
STACK: Another Over-Pressured Condensate Unit Outperforms Parent Type Curve
- 3,645 Boepd Average 24-Hour IP per Well for 19 Gross Operated Wells in 4Q18
SCOOP: SpringBoard on Pace to Add 10% to CLR Net Oil Production (3Q18-3Q19)
CLR's Five Year Vision Targets
~ 12.5% Annual Production CAGR
Average Annual Free Cash Flow (Non-GAAP) of $500 Million per Year at $60 per Barrel WTI
~ 14.5% Average Annual ROCE per Year at $60 per Barrel WTI

OKLAHOMA CITY, Feb. 18, 2019 /PRNewswire/ -- Continental Resources, Inc. (NYSE: CLR) (the Company) today announced full-year 2018 and fourth quarter 2018 operating and financial results.

Logo - http://photos.prnewswire.com/prnh/20120327/DA76602LOGO

The Company reported full-year 2018 net income of $988.3 million, or $2.64 per diluted share. 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." Typically excluded items in aggregate represented $77.9 million, or $0.20 per diluted share. Adjusted net income for full-year 2018 was $1.07 billion, or $2.84 per diluted share (non-GAAP). Net cash provided by operating activities for full-year 2018 was $3.46 billion and EBITDAX was $3.62 billion (non-GAAP).

The Company reported net income of $197.7 million, or $0.53 per diluted share, for the quarter ended December 31, 2018. In fourth quarter 2018, typically excluded items in aggregate represented $3.9 million, or $0.01 per diluted share, of Continental's reported net income. Adjusted net income for fourth quarter 2018 was $201.7 million, or $0.54 per diluted share (non-GAAP). Net cash provided by operating activities for fourth quarter 2018 was $955.3 million and EBITDAX was $850.6 million (non-GAAP).

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 are non-GAAP financial measures. Definitions and explanations for how these measures relate to the most directly comparable U.S. generally accepted accounting principles (GAAP) financial measures are provided at the conclusion of this press release. Also presented at the end of this press release is the Company's calculation of return on capital employed for 2018.

"2018 was a breakout year of performance for Continental with significant cash flow generation and debt reduction, as well as corporate returns that compare favorably against our peers and are competitive with other industries," said Harold Hamm, Chairman and Chief Executive Officer. "In 2019, we will continue to deliver strong corporate returns coupled with growth that can adjust to various market conditions."

Production Update: 4Q18 Oil Production up 14% over 3Q18   

Full-year 2018 production increased 23% over full-year 2017, averaging 298,190 Boe per day. 2018 oil production increased 21% over 2017, averaging 168,177 barrels of oil (Bo) per day. 2018 natural gas production averaged 780.1 million cubic feet (MMcf) per day.

Fourth quarter 2018 production increased 9% over third quarter 2018 and 13% over fourth quarter 2017, averaging 324,001 Boe per day. Fourth quarter 2018 oil production increased 14% over third quarter 2018 and 11% over fourth quarter 2017, averaging 186,934 Bo per day. Fourth quarter 2018 natural gas production averaged 822.4 MMcf per day.

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



4Q


3Q


4Q


FY


FY

Boe per day


2018


2018


2017


2018


2017

North Region:











North Dakota Bakken


177,358


161,008


158,640


161,231


125,577

Montana Bakken


6,478


6,635


6,958


6,569


7,415

Other


9,077


9,015


9,965


9,125


10,182

South Region:











SCOOP


67,244


63,270


62,242


64,339


60,693

STACK


62,947


56,129


47,914


56,055


36,220

Other(1)


897


847


1,266


871


2,550












Total


324,001


296,904


286,985


298,190


242,637


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

Bakken: 183,836 Boepd Average Daily 4Q18 Production; up 10% over 3Q18

The Company's full-year 2018 Bakken production increased 26% over 2017, averaging 167,800 Boe per day. The Company's fourth quarter 2018 Bakken production increased 10% over third quarter 2018 and 11% over fourth quarter 2017, averaging 183,836 Boe per day. During the quarter, the Company completed 52 gross (34 net) operated wells with first production flowing at an average initial 24-hour rate per well of 2,800 Boe per day.

"Continental has entered a new era of optimized full field development in the Bakken where technology and operational efficiencies have uplifted performance across the play," said Jack Stark, President. "As we look to 2019 and beyond, the Bakken will continue to underpin Continental's sustainable, value-driven and oil-weighted growth."

STACK: Another Over-Pressured Condensate Unit Outperforms Parent Type Curve

The Company's fourth quarter 2018 STACK production increased 12% over third quarter 2018 and 31% over fourth quarter 2017, averaging 62,947 Boe per day. During the quarter, the Company completed 19 gross (9 net) operated wells with first production flowing at an average initial 24-hour rate per well of 3,645 Boe per day.

The Company recently completed another outstanding Meramec unit in the over-pressured condensate window of STACK. The Boden unit flowed at an impressive combined initial 24-hour rate of 14,071 Boe per day, averaging 1,197 Bo per day per well and 20,961 Mcf per day per well.

"Recent results from the Boden unit further validate Continental's optimized density development and the high quality of the over-pressured Meramec that underlies our acreage position in STACK," said Gary Gould, Senior Vice President of Production & Resource Development.

SCOOP: SpringBoard on Pace to Add 10% to CLR Net Oil Production (3Q18-3Q19)

The Company's fourth quarter 2018 SCOOP production increased 6% over third quarter 2018 and 8% over fourth quarter 2017, averaging 67,244 Boe per day. The Company completed 17 gross (14 net) operated wells with first production in fourth quarter 2018. The Company's fourth quarter 2018 SCOOP oil production increased 47% over fourth quarter 2017, reflecting the decision made in early 2018 to shift to the Company's oil-weighted assets. 

As previously announced in the Company's Project SpringBoard conference call, Project SpringBoard is expected to add 10%, or 16,500 barrels of oil per day, to the Company's total net oil production from third quarter 2018 to third quarter 2019. In fourth quarter 2018, Project SpringBoard production growth was on pace, producing an average 5,260 barrels of oil per day. The Company currently has 45 gross operated wells waiting on completion in Project SpringBoard with 18 gross operated wells in the Springer reservoir and 27 gross operated wells in the Woodford and Sycamore reservoirs. Approximately 12 rigs will be focused on Project SpringBoard in 2019, with approximately 7 rigs targeting the Springer and approximately 5 rigs targeting the Woodford and Sycamore.

Financial Update

"Continental's 2018 performance signals a structural transition to free cash flow generation through low cost operations and development," said John Hart, Chief Financial Officer. "Over the next five years, we are targeting free cash flow generation, continued debt reduction and an average 12.5% compound annual production growth rate to drive strong corporate returns and continued shareholder value."

As of December 31, 2018, the Company's balance sheet included approximately $282.7 million in cash and cash equivalents, $5.77 billion in total debt and $5.49 billion in net debt (non-GAAP). The Company anticipates further reducing net debt to $5 billion late in 2019.

For full-year 2018, the Company's average net sales prices excluding the effects of derivative positions were $59.19 per barrel of oil and $3.01 per Mcf of gas, or $41.25 per Boe. The Company remains unhedged on oil. Production expense per Boe was $3.59 for full-year 2018, a record annual low for the Company and well within annual guidance of $3.50 to $3.75.

Non-acquisition capital expenditures for full-year 2018 totaled approximately $2.8 billion, including $2.4 billion in exploration and development drilling and completion, $276.4 million in leasehold and minerals, and $198.8 million in workovers, recompletions and other.

In fourth quarter 2018, the Company's average net sales prices excluding the effects of derivative positions were $50.06 per barrel of oil and $3.26 per Mcf of gas, or $37.13 per Boe. Production expense per Boe was $3.50 for fourth quarter 2018.

Non-acquisition capital expenditures for fourth quarter 2018 totaled approximately $742.6 million, including $611.0 million in exploration and development drilling and completion, $59.0 million in leasehold and minerals, and $72.6 million in workovers, recompletions and other.

The Company's 2019 guidance remains as announced on February 13, 2019 and can be found at the conclusion of this press release.

CLR's Five Year Vision Targets

Over the next five years, the Company is targeting an average 12.5% compound annual production growth rate from existing inventory. The Company is also targeting an average annual free cash flow of $500 million per year at $60 per barrel WTI. Individual years may vary above or below these targets depending on the timing of future projects.

In addition to cash flow generation, the Company expects ROCE to remain strong over the next five years, competing against other energy companies as well as other industries. The Company is targeting average annual ROCE of approximately 14.5% per year over the five years at $60 per barrel WTI.

The Company expects capital allocation between its North and South assets to be reasonably consistent with the historical norm of approximately 50% to 60% in the North and approximately 40% to 50% in the South.

The Company's operating expenses on a per Boe basis are expected to remain relatively consistent or improve. Additionally, the Company expects oil and gas differentials to improve with continued infrastructure directed toward coastal markets, which will allow the Company to benefit from access to both premium domestic and global markets.

The Company's five year vision is underpinned by the depth and quality of current inventory. The Company estimates less than 30% of current inventory is to be developed under this five year vision. The five year inventory is projected to deliver a 60% blended average rate of return (ROR) at $60 per barrel WTI.  

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 December 31,


Year ended December 31,


2018


2017


2018


2017

Average daily production:








Crude oil (Bbl per day)

186,934


168,066


168,177


138,455

Natural gas (Mcf per day)

822,402


713,518


780,083


625,093

Crude oil equivalents (Boe per day)

324,001


286,985


298,190


242,637

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








Crude oil ($/Bbl)

$50.06


$51.16


$59.19


$45.70

Natural gas ($/Mcf)

$3.26


$3.30


$3.01


$2.93

Crude oil equivalents ($/Boe)

$37.13


$38.27


$41.25


$33.65

Production expenses ($/Boe) 

$3.50


$3.17


$3.59


$3.66

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

8.2%


7.3%


7.9%


7.0%

DD&A ($/Boe)

$16.41


$17.93


$17.09


$18.89

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

$1.65


$2.30


$1.69


$2.16

Net income attributable to Continental Resources (in thousands) (3)

$197,738


$841,914


$988,317


$789,447

Diluted net income per share attributable to Continental Resources

$0.53


$2.25


$2.64


$2.11

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

$201,686


$153,660


$1,066,237


$190,803

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

$0.54


$0.41


$2.84


$0.51

Net cash provided by operating activities (in thousands)

$955,267


$731,125


$3,456,008


$2,079,106

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

$850,640


$837,887


$3,623,373


$2,363,617


(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 at the end of this press release.


(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, $1.80, $1.25, and $1.64 for 4Q 2018, 4Q 2017, FY 2018 and FY 2017, respectively. Non-cash equity compensation expense per Boe was $0.47, $0.50, $0.44, and $0.52 for 4Q 2018, 4Q 2017, FY 2018 and FY 2017, respectively.


(3) In December 2017, the Tax Cuts and Jobs Act was signed into law, which among other things reduced the U.S. federal corporate income tax rate from 35% to 21% effective January 1, 2018. In accordance with U.S. GAAP, the Company remeasured its deferred income tax assets and liabilities as of December 31, 2017 to reflect the reduced tax rate, which resulted in a one-time increase in net income of approximately $713.7 million ($1.91 per diluted share) for the three and twelve months ended December 31, 2017.

Fourth Quarter Earnings Conference Call

Continental plans to host a conference call to discuss fourth quarter and full-year 2018 results on Tuesday, February 19, 2019 at 12:00 p.m. ET (11:00 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, February 19, 2019

Dial-in:

844-309-6572

Intl. dial-in:

484-747-6921

Conference ID:

5856777

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

Conference ID:

5856777

Continental plans to publish a fourth quarter and full-year 2018 summary presentation to its website at www.CLR.com prior to the start of its conference call on February 19, 2019. 

Upcoming Conferences

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

March 25-26, 2019      Scotia Howard Weil 47th Annual Energy ConferenceNew Orleans, LA

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 2019, the Company will celebrate 52 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," "target," "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, and once filed, for the year ended December 31, 2018, 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

Consolidated Statements of Income



Three months ended December 31, 


Year ended December 31,


2018


2017


2018


2017

Revenues:

In thousands, except per share data

Crude oil and natural gas sales

$ 1,154,104


$ 1,017,750


$ 4,678,722


$ 2,982,966

Gain (loss) on natural gas derivatives, net

(19,394)


8,165


(23,930)


91,647

Crude oil and natural gas service operations

14,584


21,257


54,794


46,215

Total revenues

1,149,294


1,047,172


4,709,586


3,120,828









Operating costs and expenses:








Production expenses

104,258


84,371


390,423


324,214

Production taxes

90,393


73,816


353,140


208,278

Transportation expenses

49,028


-


191,587


-

Exploration expenses

3,295


2,802


7,642


12,393

Crude oil and natural gas service operations

4,205


6,216


21,639


16,880

Depreciation, depletion, amortization and accretion

488,416


476,732


1,859,327


1,674,901

Property impairments

38,494


27,552


125,210


237,370

General and administrative expenses 

49,201


61,294


183,569


191,706

Litigation settlement

-


59,600


-


59,600

Net gain on sale of assets and other

(8,410)


(54,679)


(16,671)


(53,915)

Total operating costs and expenses

818,880


737,704


3,115,866


2,671,427

Income from operations

330,414


309,468


1,593,720


449,401

Other income (expense):








Interest expense

(69,441)


(75,823)


(293,032)


(294,495)

Loss on extinguishment of debt

-


(554)


(7,133)


(554)

Other 

1,016


506


3,247


1,715


(68,425)


(75,871)


(296,918)


(293,334)

Income before income taxes

261,989


233,597


1,296,802


156,067

(Provision) benefit for income taxes

(62,868)


608,317


(307,102)


633,380

Net income

199,121


841,914


989,700


789,447

Net income attributable to noncontrolling interests

1,383


-


1,383


-

Net income attributable to Continental Resources

$   197,738


$   841,914


$   988,317


$   789,447

Net income per share attributable to Continental Resources:








Basic

$         0.53


$         2.27


$         2.66


$         2.13

Diluted

$         0.53


$         2.25


$         2.64


$         2.11

 

Continental Resources, Inc. and Subsidiaries

Consolidated Balance Sheets



December 31, 2018


December 31, 2017

Assets

In thousands

Cash and cash equivalents

$

282,749


$

43,902

Other current assets


1,129,612



1,207,823

Net property and equipment (1)


13,869,800



12,933,789

Other noncurrent assets


15,786



14,137

Total assets

$

15,297,947


$

14,199,651







Liabilities and equity






Current liabilities 

$

1,387,509


$

1,330,242

Long-term debt, net of current portion


5,765,989



6,351,405

Other noncurrent liabilities


1,722,588



1,386,801

Equity attributable to Continental Resources


6,145,133



5,131,203

Equity attributable to noncontrolling interests


276,728



-

Total liabilities and equity

$

15,297,947


$

14,199,651


(1) Balance is net of accumulated depreciation, depletion and amortization of $10.81 billion and $9.08 billion as of December 31, 2018 and December 31, 2017, respectively.

 

Continental Resources, Inc. and Subsidiaries

Consolidated Statements of Cash Flows




Three months ended December 31,


Year ended December 31,

In thousands


2018


2017


2018


2017

Net income


$

199,121


$

841,914


$

989,700


$

789,447

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













Non-cash expenses



576,033



(70,395)



2,340,600



1,288,244

Changes in assets and liabilities



180,113



(40,394)



125,708



1,415

Net cash provided by operating activities



955,267



731,125



3,456,008



2,079,106

Net cash used in investing activities



(756,689)



(434,591)



(2,860,172)



(1,808,845)

Net cash provided by (used in) financing activities



71,319



(263,395)



(356,934)



(243,034)

Effect of exchange rate changes on cash



(44)



(2)



(55)



32

Net change in cash and cash equivalents



269,853



33,137



238,847



27,259

Cash and cash equivalents at beginning of period



12,896



10,765



43,902



16,643

Cash and cash equivalents at end of period


$

282,749


$

43,902


$

282,749


$

43,902

Non-GAAP adjusted net income and adjusted net income per share attributable to Continental

Our presentation of adjusted net income and adjusted net income per share that exclude the effect of certain items are non-GAAP financial measures. Adjusted net income and adjusted net income per share represent net income and diluted net income per share determined under U.S. GAAP without regard to non-cash gains and losses on derivative instruments, property impairments, losses on certain litigation settlements, gains and losses on asset sales, losses on extinguishment of debt, and the impact of U.S. tax reform legislation 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 net income and adjusted net income per share should not be considered in isolation or as an alternative to, or more meaningful than, net income or diluted net income 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 net income and diluted net income per share as determined under U.S. GAAP to adjusted net income and adjusted diluted net income per share for the periods presented.



Three months ended December 31,



2018


2017

In thousands, except per share data


$


Diluted EPS


$


Diluted EPS

Net income attributable to Continental Resources (GAAP)


$   197,738


$        0.53


$841,914


$        2.25

Adjustments:









Non-cash (gain) loss on derivatives


(25,022)




7,450



Property impairments


38,494




27,552



Litigation settlement


-




59,600



Gain on sale of assets


(8,410)




(54,420)



Loss on extinguishment of debt


-




554



Total tax effect of adjustments (1)


(1,114)




(15,335)



Tax benefit from US tax reform legislation


-




(713,655)



Total adjustments, net of tax


3,948


0.01


(688,254)


(1.84)

Adjusted net income (non-GAAP)


$   201,686


$        0.54


$153,660


$        0.41

Weighted average diluted shares outstanding


374,525




373,764



Adjusted diluted net income per share (non-GAAP)


$        0.54




$0.41














Year ended December 31,



2018


2017

In thousands, except per share data


$


Diluted EPS


$


Diluted EPS

Net income attributable to Continental Resources (GAAP)


$   988,317


$        2.64


$789,447


$        2.11

Adjustments:









Non-cash gain on derivatives


(13,009)




(58,031)



Property impairments


125,210




237,370



Litigation settlement


-




59,600



Gain on sale of assets


(16,671)




(55,124)



Loss on extinguishment of debt


7,133




554



Total tax effect of adjustments (1)


(24,743)




(69,358)



Tax benefit from US tax reform legislation


-




(713,655)



Total adjustments, net of tax


77,920


0.20


(598,644)


(1.60)

Adjusted net income (non-GAAP)


$1,066,237


$        2.84


$190,803


$        0.51

Weighted average diluted shares outstanding


374,838




373,768



Adjusted diluted net income per share (non-GAAP)


$        2.84




$     0.51




(1) Computed by applying a combined federal and state statutory tax rate of 24.5% 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 other than the 2017 tax benefit adjustment related to US tax reform legislation.  

Non-GAAP 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, total debt, the most directly 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 December 31, 2018, the Company's total debt was $5.77 billion and its net debt amounted to $5.49 billion, representing total debt of $5.77 billion less cash and cash equivalents of $282.7 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 the most directly comparable forward-looking GAAP measure of total debt 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.

Non-GAAP EBITDAX

We use a variety of financial and operational measures to assess our performance. Among these measures is EBITDAX, a non-GAAP measure. 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 December 31,


Year ended December 31, 

In thousands



2018



2017



2018



2017

Net income


$

199,121


$

841,914


$

989,700


$

789,447

Interest expense



69,441



75,823



293,032



294,495

Provision (benefit) for income taxes



62,868



(608,317)



307,102



(633,380)

Depreciation, depletion, amortization and accretion



488,416



476,732



1,859,327



1,674,901

Property impairments



38,494



27,552



125,210



237,370

Exploration expenses



3,295



2,802



7,642



12,393

Impact from derivative instruments:













Total (gain) loss on derivatives, net



19,394



(8,417)



23,930



(90,432)

Total cash (paid) received on derivatives, net



(44,416)



15,867



(36,939)



32,401

Non-cash (gain) loss on derivatives, net



(25,022)



7,450



(13,009)



(58,031)

Non-cash equity compensation



14,027



13,377



47,236



45,868

Loss on extinguishment of debt



-



554



7,133



554

EBITDAX (non-GAAP)


$

850,640


$

837,887


$

3,623,373


$

2,363,617

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



Three months ended December 31,


Year ended December 31, 

In thousands



2018



2017



2018



2017

Net cash provided by operating activities


$

955,267


$

731,125


$

3,456,008


$

2,079,106

Current income tax provision (benefit)



2



(7,781)



(7,776)



(7,781)

Interest expense



69,441



75,823



293,032



294,495

Exploration expenses, excluding dry hole costs



3,149



2,783



7,495



12,217

Litigation settlement



-



(59,600)



-



(59,600)

Gain on sale of assets, net



8,410



54,420



16,671



55,124

Other, net



(5,516)



723



(16,349)



(8,529)

Changes in assets and liabilities



(180,113)



40,394



(125,708)



(1,415)

EBITDAX (non-GAAP)


$

850,640


$

837,887


$

3,623,373


$

2,363,617

Non-GAAP Free Cash Flow

Our presentation of projected free cash flow is a non-GAAP measure. We define projected free cash flow as cash flows from operations before changes in working capital items, less capital expenditures, plus noncontrolling interest capital contributions, less distributions to noncontrolling interests. Noncontrolling interest capital contributions and distributions primarily relate to our new relationship formed with Franco-Nevada in 2018 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 operating cash flows as determined by U.S. GAAP and should not be considered an alternative to, or more meaningful than, the comparable GAAP measure, and free cash flow does not represent residual cash flows available for discretionary expenditures. Management believes that this measure is 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. From time to time the Company provides forward-looking free cash flow estimates or targets; 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.

Non-GAAP 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 on January 1, 2018 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, to achieve comparability between operated and non-operated revenues, 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 twelve months ended December 31, 2018. Information is also presented for the three and twelve months ended December 31, 2017 for comparative purposes.



Three months ended December 31, 2018


Three months ended December 31, 2017

In thousands


Crude oil


Natural gas


Total


Crude oil


Natural gas


Total

Crude oil and natural gas sales (GAAP)


$900,872


$253,232


$1,154,104


$800,871


$216,879


$1,017,750

Less: Transportation expenses


(42,373)


(6,655)


(49,028)




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


$858,499


$246,577


$1,105,076


$800,871


$216,879


$1,017,750

Sales volumes (MBbl/MMcf/MBoe)


17,149


75,661


29,759


15,653


65,644


26,594

Net sales price (non-GAAP for 2018)


$50.06


$3.26


$37.13


$51.16


$3.30


$38.27
















Year ended December 31, 2018


Year ended December 31, 2017

In thousands


Crude oil


Natural gas


Total


Crude oil


Natural gas


Total

Crude oil and natural gas sales (GAAP)


$3,792,594


$886,128


$4,678,722


$2,313,862


$669,104


$2,982,966

Less: Transportation expenses


(162,312)


(29,275)


(191,587)




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


$3,630,282


$856,853


$4,487,135


$2,313,862


$669,104


$2,982,966

Sales volumes (MBbl/MMcf/MBoe)


61,332


284,730


108,787


50,628


228,159


88,655

Net sales price (non-GAAP for 2018)


$59.19


$3.01


$41.25


$45.70


$2.93


$33.65

Non-GAAP 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.

The following table reconciles total G&A per Boe as determined under U.S. GAAP to cash G&A per Boe for the periods presented.



Three months ended December 31, 


Year ended December 31,



2018


2017


2018


2017

Total G&A per Boe (GAAP)


$1.65


$2.30


$1.69


$2.16

Less: Non-cash equity compensation per Boe


(0.47)


(0.50)


(0.44)


(0.52)

Cash G&A per Boe (non-GAAP)


$1.18


$1.80


$1.25


$1.64

Calculation of Return on Capital Employed (ROCE)

The following table shows the calculation of ROCE for 2018.

In thousands


2018




Net income attributable to Continental Resources


$     988,317

Impact from derivative instruments:



Total (gain) loss on derivatives, net


23,930

Total cash received (paid), net


(36,939)

Non-cash (gain) loss on derivatives, net


(13,009)




Provision for income taxes


307,102

Non-cash equity compensation


47,236

Interest expense


293,032

Loss on extinguishment of debt


7,133

Adjusted EBIT


$  1,629,811







Equity attributable to Continental Resources - beginning of 2018


$  5,131,203

Total debt - beginning of 2018


6,353,691

Capital employed - beginning of 2018


11,484,894




Equity attributable to Continental Resources - end of 2018


6,145,133

Total debt - end of 2018


5,768,349

Capital employed - end of 2018


11,913,482




Average capital employed


$11,699,188




ROCE


13.9%

 

Continental Resources, Inc.

2019 Guidance

As of February 18, 2019












2019




Full-year average oil production 


190,000 to 200,000 Bo per day

Full-year average natural gas production 


790,000 to 810,000 Mcf per day 

Capital expenditures budget


$2.6 billion 




Operating Expenses:



     Production expense per Boe


$3.75 to $4.25

     Production tax (% of net oil & gas revenue)


8.0% to 8.3%

     Cash G&A expense per Boe(1)


$1.25 to $1.45

     Non-cash equity compensation per Boe


$0.45 to $0.55

     DD&A per Boe


$15.00 to $17.00




Average Price Differentials:



     NYMEX WTI crude oil (per barrel of oil)


($4.50) to ($5.50)

     Henry Hub natural gas (per Mcf)


$0.00 to ($0.50)


(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 $1.70 to $2.00 per Boe.

 

Cision View original content:http://www.prnewswire.com/news-releases/continental-resources-reports-full-year-2018-and-4q18-results-300797501.html

SOURCE Continental Resources