CONTINENTAL RESOURCES, INC false 0000732834 0000732834 2021-02-16 2021-02-16

 

 

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

 

 

FORM 8-K

 

 

CURRENT REPORT

Pursuant to Section 13 or 15(d)

of the Securities Exchange Act of 1934

Date of Report (Date of earliest event reported): February 16, 2021

 

 

CONTINENTAL RESOURCES, INC.

(Exact name of registrant as specified in its charter)

 

 

 

Oklahoma   001-32886   73-0767549

(State or other jurisdiction of

incorporation or organization)

 

(Commission

File Number)

 

(I.R.S. Employer

Identification No.)

 

20 N. Broadway

Oklahoma City, Oklahoma

  73102
(Address of principal executive offices)   (Zip Code)

Registrant’s telephone number, including area code: (405) 234-9000

Not Applicable.

(Former name or former address, if changed since last report.)

 

 

Check the appropriate box below if the Form 8-K filing is intended to simultaneously satisfy the filing obligation of the registrant under any of the following provisions (see General Instruction A.2. below):

 

Written communications pursuant to Rule 425 under the Securities Act (17 CFR 230.425)

 

Soliciting material pursuant to Rule 14a-12 under the Exchange Act (17 CFR 240.14a-12)

 

Pre-commencement communications pursuant to Rule 14d-2(b) under the Exchange Act (17 CFR 240.14d-2(b))

 

Pre-commencement communications pursuant to Rule 13e-4(c) under the Exchange Act (17 CFR 240.13e-4(c))

Securities registered pursuant to Section 12(b) of the Act:

 

Title of each class

 

Trading

symbol(s)

 

Name of each exchange

on which registered

Common Stock, $0.01 par value   CLR   New York Stock Exchange

Indicate by check mark whether the registrant is an emerging growth company as defined in Rule 405 of the Securities Act of 1933 (17 CFR 230.405) or Rule 12b-2 of the Securities Exchange Act of 1934 (17 CFR 240.12b-2). Emerging growth company  

If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act.  ☐

 

 

 


Item 2.02

Results of Operations and Financial Condition

On February 16, 2021, Continental Resources, Inc. (the “Company”) issued a press release announcing, among other things, its fourth quarter and full-year 2020 financial and operating results, 2021 capital expenditure budget and 2021 operational guidance. A copy of the press release is being furnished as an exhibit to this report on Form 8-K.

 

Item 7.01

Regulation FD Disclosure

Reference materials in connection with the fourth quarter and full-year 2020 earnings call scheduled for February 17, 2021 at 12:00 p.m. Eastern time (11:00 a.m. Central time), will be available on the Company’s web site at www.CLR.com, prior to the start of the call.

 

Item 9.01

Financial Statements and Exhibits

(d) Exhibits

 

Exhibit

Number

  

Description

99.1    Press release dated February 16, 2021
104    Cover page interactive data file (embedded within the Inline XBRL document)


SIGNATURE

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned hereunto duly authorized.

 

    CONTINENTAL RESOURCES, INC.
    (Registrant)
Dated: February 16, 2021      
    By:  

/s/ John D. Hart

      John D. Hart
      Senior Vice President, Chief Financial Officer and
Treasurer

Exhibit 99.1

NEWS RELEASE

 

CONTINENTAL RESOURCES ANNOUNCES FULL-YEAR 2020 AND 4Q20 RESULTS;

2021 CAPITAL BUDGET AND GUIDANCE

FY20: $1.4 B Cash Flow from Operations & $275 MM Free Cash Flow (Non-GAAP)

 

   

4Q20: $488 MM Cash Flow from Operations & $332 MM Free Cash Flow (FCF)

 

   

$168 MM in Non-Acquisition Capex

 

   

176.6 MBopd & 976 MMcfpd Average Daily Production

 

   

$2.80 Production Expense per Boe

 

   

FY20: Fifth Consecutive Year of Generating Positive FCF

 

   

$1.16 B in Non-Acquisition Capex ($1.2 B Guidance)

 

   

160.5 MBopd & 837.5 MMcfpd Avg. Daily Production (155-165 MBopd & 800-820 MMcfpd Guidance)

 

   

$3.27 Production Expense per Boe ($3.50-$3.75 Guidance)

FY21: Projecting Sixth Consecutive Year of Generating Positive FCF

 

   

In Excess of 40% of Cash Flow from Operations Projected toward Shareholder Capital Returns through Debt Reduction and Future Dividends1

 

   

Targeting Approx. $4.5 B Total Debt by YE21; <$4.0 B by YE22

 

   

Approx. $2.4 B of Cash Flow from Operations; $1.0 B of FCF; 12% FCF Yield2 (non-GAAP)

 

   

58% Reinvestment Rate; 3-4% Total Production Growth; Budgeted at $52 WTI & $2.75 HH

 

   

$5 Increase in WTI = Approx. $250 MM Increase in Cash Flow

 

   

Expanding Operations into the Oil-Weighted Wyoming Powder River Basin in March 2021

 

   

Adds 130,000 Net Acres & 400 MMBoe Net Unrisked Resource Potential to CLR Portfolio

Oklahoma City, February 16, 2021 – Continental Resources, Inc. (NYSE: CLR) (the “Company”) today announced its full-year 2020 and fourth quarter 2020 operating and financial results, as well as its 2021 capital expenditures budget and operating plan.

“In 2020, Continental demonstrated our commitment to delivering sustainable free cash flow by generating $275 million of free cash flow in arguably one of the most challenging years of our over 50 years of operations. Delivering our fifth consecutive year of free cash flow in spite of unprecedented market volatility validates our durable approach to managing our business. We are well-positioned to sustainably deliver significant shareholder returns from strong free cash flow in 2021 and beyond,” said Bill Berry, Chief Executive Officer.

 

1 

All future dividends require Board approval.

2 

Free cash flow yield is estimated by dividing the 2021 annual FCF estimate by the Company’s current market capitalization, as of February 16, 2021.


The Company reported a full-year 2020 net loss of $596.9 million, or $1.65 per diluted share. For full-year 2020, typically excluded items in aggregate represented $172.9 million, or $0.48 per diluted share, of Continental’s reported net loss. Adjusted net loss for full-year 2020 was $424.0 million, or $1.17 per diluted share (non-GAAP). Net cash provided by operating activities for full-year 2020 was $1.42 billion and EBITDAX was $1.68 billion (non-GAAP).

The Company reported a net loss of $92.5 million, or $0.26 per diluted share, for the quarter ended December 31, 2020. In fourth quarter 2020, typically excluded items in aggregate represented $10.6 million, or $0.03 per diluted share, of Continental’s reported net loss. Adjusted net loss for fourth quarter 2020 was $81.9 million, or $0.23 per diluted share (non-GAAP). Net cash provided by operating activities for fourth quarter 2020 was $487.5 million and EBITDAX was $572.0 million (non-GAAP).

Adjusted net income (loss), adjusted net income (loss) per share, free cash flow, free cash flow yield, 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.

Production & Operations Update

Full-year 2020 total production averaged 300,090 Boepd. Full-year 2020 oil production averaged 160,505 Bopd. Full-year 2020 natural gas production averaged 837.5 MMcfpd. Fourth quarter 2020 total production averaged 339,307 Boepd. Fourth quarter 2020 oil production averaged 176,639 Bopd. Fourth quarter 2020 natural gas production averaged 976.0 MMcfpd.

The Company achieved its 2020 completed well cost targets in both the Bakken and Oklahoma, with go forward well costs in the Bakken of approximately $690 per lateral foot, at a 10,000’ lateral length, and in Oklahoma of approximately $1,070 per lateral foot, at an 8,200’ lateral length. These all-in well costs include drilling and completion (D&C), full facilities and artificial lift. Cost savings are 70% to 80% structural and are being driven by a reduction in drilling cycle times, stage counts, proppant volumes and stimulation days, as well as the optimization of artificial lift.

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

 

     4Q      4Q      FY      FY  

Boe per day

   2020      2019      2020      2019  

Bakken

     183,141      194,156      158,604      194,691

South

     149,377      163,552      134,540      137,579

All other

     6,789      7,633      6,946      8,125
  

 

 

    

 

 

    

 

 

    

 

 

 

Total

     339,307      365,341      300,090      340,395

 

2


Financial Update

“As part of our commitment to operational excellence and capital discipline, Continental spent approximately 3% less non-acquisition Capex than budgeted while delivering oil production in line with the midpoint of our guidance. Our strong cost performance continues to underpin and drive our ability to generate significant free cash flow historically and prospectively,” said John Hart, Chief Financial Officer.

 

2020 Financial Update

   Three Months Ended
December 31, 2020
    Year Ended
December 31, 2020
 

Cash and Cash Equivalents

     $ 47.5 million  

Total Debt

     $ 5.53 billion  

Net Debt (non-GAAP)(1)

     $ 5.48 billion  

Average Net Sales Price (non-GAAP)(1)

    

Per Barrel of Oil

   $ 37.34     $ 34.71  

Per Mcf of Gas

   $ 1.81     $ 1.04  

Per Boe

   $ 24.63     $ 21.47  

Production Expense per Boe

   $ 2.80     $ 3.27  

Total G&A Expenses per Boe

   $ 2.14     $ 1.79  

Crude Oil Differential per Barrel

   ($ 5.20   ($ 5.80

Natural Gas Differential per Mcf

   ($ 0.87   ($ 1.10

Non-Acquisition Capital Expenditures

   $ 168.1 million     $ 1,159.0 million  

Exploration & Development Drilling & Completion

   $ 151.0 million     $ 971.7 million  

Leasehold

   $ 3.5 million     $ 34.5 million  

Minerals, of which 80% was Recouped from FNV

   $ 0.1 million     $ 23.9 million  

Workovers, Recompletions and Other

   $ 13.5 million     $ 128.9 million  

 

(1)

Net debt and net sales prices 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.

Strategic Acquisition and Entrance into the Wyoming Powder River Basin

The Company announced it has executed definitive documents to acquire approximately 130,000 net acres and approximately 9,000 Boepd of production in the Powder River Basin for $215 million, subject to customary closing conditions. This acquisition included 96 approved federal drilling permits and is expected to close in March 2021. The Company intends to begin delineating and developing the Shannon, Frontier and Niobrara reservoirs with 2 rigs in second quarter 2021.

“These Powder River Basin assets provide Continental another oil-weighted platform, adding over 400 MMBoe of net unrisked resource potential to our portfolio,” said Jack Stark, President and Chief Operating Officer. “We especially like the fact that the basin is in the very early stages of development with solid economics even before applying our low cost efficient operations.”

2021 Capital Budget & Guidance

The Company is projecting a $1.4 billion capital expenditures budget, net of Franco Nevada’s share of mineral costs, which approximates to a 58% cash flow from operations (CFFO) reinvestment rate for 2021. The 2021 capital budget is projected to generate approximately $2.4 billion of cash flow from operations and $1.0 billion of free cash flow (non-GAAP) for full-year 2021 at $52 per barrel WTI and $2.75 per Mcf Henry Hub. A $5 increase per barrel WTI is estimated to increase cash flow by approximately $250 million.

 

3


The Company is projecting approximately 12% free cash flow yield (non-GAAP) at $52 WTI. Free cash flow yield is estimated by dividing the 2021 annual FCF estimate by the Company’s current market capitalization, as of February 16, 2021. The Company is targeting shareholder capital returns in excess of 40% of cash flow from operations through debt reduction and future dividends. All future dividends require Board approval. Additionally, the Company is projecting total debt of approximately $4.5 billion at year-end 2021 and $4.0 billion or below by year-end 2022.

Annual crude oil production is projected to range between 160,000 to 165,000 Bopd. Annual natural gas production is projected to range between 880,000 to 920,000 Mcfpd.

The Company is allocating approximately $1.1 billion to D&C activities, of which approximately 60% is allocated to the Bakken and approximately 35% to Oklahoma, with the remaining capital being allocated to the Powder River Basin asset. An additional $300 million is being allocated to non-D&C capital and is planned to be primarily for leasehold, mineral acquisitions, workovers and facilities.

At year-end 2021, the Company expects to have a working backlog of approximately 135 gross operated wells in progress in various stages of completion.

As an update on the previously disclosed water monetization process, the Company has made the decision not to further pursue this transaction. Ultimately, the Company has elected to maintain full operational flexibility to maximize the long-term value of these assets and enhance cash flow.

The Company’s full 2021 guidance, capital expenditures budget and operating details can be found at the conclusion of this press release.

“Our 58% reinvestment rate at $52 WTI in 2021 highlights our commitment to generating significant and sustainable free cash flow. With expectations to deliver a strong free cash flow yield and shareholder capital returns in excess of 40% of cash flow from operations through debt reduction and future dividends, Continental will continue to drive shareholder value,” said Bill Berry, Chief Executive Officer.

 

4


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,  
     2020     2019     2020     2019  

Average daily production:

        

Crude oil (Bbl per day)

     176,639     206,249     160,505     197,991

Natural gas (Mcf per day)

     976,011     954,556     837,509     854,424

Crude oil equivalents (Boe per day)

     339,307     365,341     300,090     340,395

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

 

Crude oil ($/Bbl)

   $ 37.34   $ 51.33   $ 34.71   $ 51.82

Natural gas ($/Mcf)

   $ 1.81   $ 1.73   $ 1.04   $ 1.77

Crude oil equivalents ($/Boe)

   $ 24.63   $ 33.49   $ 21.47   $ 34.56

Production expenses ($/Boe)

   $ 2.80   $ 3.31   $ 3.27   $ 3.58

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

     7.8     8.1     8.2     8.3

DD&A ($/Boe)

   $ 19.01   $ 16.45   $ 17.12   $ 16.25

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

   $ 2.14   $ 1.59   $ 1.79   $ 1.57

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

   $ (92,497   $ 193,946   $ (596,869   $ 775,641

Diluted net income (loss) per share attributable to Continental Resources

   $ (0.26   $ 0.53   $ (1.65   $ 2.08

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

   $ (81,896   $ 203,589   $ (424,035   $ 838,723

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

   $ (0.23   $ 0.55   $ (1.17   $ 2.25

Net cash provided by operating activities (in thousands)

   $ 487,537   $ 803,812   $ 1,422,304   $ 3,115,688

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

   $ 571,952   $ 905,525   $ 1,675,523   $ 3,447,033

 

(1)

Net sales prices, adjusted net income (loss), adjusted diluted net income (loss) 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 $1.61, $1.15, $1.20 and $1.15 for 4Q 2020, 4Q 2019, FY 2020 and FY 2019, respectively. Non-cash equity compensation expense per Boe was $0.53, $0.44, $0.59, and $0.42 for 4Q 2020, 4Q 2019, FY 2020 and FY 2019, respectively.

Fourth Quarter Earnings Conference Call

The Company plans to host a conference call to discuss full-year 2020 and fourth quarter 2020 results on Wednesday, February 17, 2021 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:    12:00 p.m. ET, Wednesday, February 17, 2021
Dial-in:    1-888-317-6003
Intl. dial-in:    1-412-317-6061
Conference ID:    6942729

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

 

Replay number:    1-877-344-7529
Intl. replay:    1-412-317-0088
Conference ID:    10151479

The Company plans to publish a full-year 2020 and fourth quarter 2020 summary presentation to its website at www.CLR.com prior to the start of its conference call on Wednesday, February 17, 2021.

 

5


About Continental Resources

Continental Resources (NYSE: CLR) is a top 10 independent oil producer in the U.S. 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 2021, the Company will celebrate 54 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 effects of any national or international health crisis; 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; our ability to pay future dividends or complete share repurchases; 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;

 

6


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, 2019, Quarterly Reports on Form 10-Q for the quarters ended March 31, 2020, June 30, 2020 and September 30, 2020, and once filed, the Company’s Annual Report on Form 10-K for the year ended December 31, 2020, 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, if any, 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
[email protected]    [email protected]

Lucy Spaay

  

Investor Relations Analyst

  

405-774-5878

  

[email protected]

  

 

7


Continental Resources, Inc. and Subsidiaries

Consolidated Statements of Income (Loss)

 

     Three months ended December 31,     Year ended December 31,  
     2020     2019     2020     2019  
     In thousands, except per share data              

Revenues:

        

Crude oil and natural gas sales

   $ 816,571   $ 1,185,980   $ 2,555,434   $ 4,514,389

Gain (loss) on derivative insturments, net

     10,977     (4,436     (14,658     49,083

Crude oil and natural gas service operations

     10,092     13,590     45,694     68,475
  

 

 

   

 

 

   

 

 

   

 

 

 

Total revenues

     837,640     1,195,134     2,586,470     4,631,947

Operating costs and expenses:

        

Production expenses

     87,415     111,203     359,267     444,649

Production taxes

     60,274     90,751     192,718     357,988

Transportation expenses

     48,613     61,080     196,692     225,649

Exploration expenses

     3,094     7,268     17,732     14,667

Crude oil and natural gas service operations

     3,006     6,614     18,294     33,230

Depreciation, depletion, amortization and accretion

     592,774     552,711     1,880,959     2,017,383

Property impairments

     12,965     19,348     277,941     86,202

General and administrative expenses

     66,859     53,465     196,572     195,302

Net (gain) loss on sale of assets and other

     (5,727     (1,182     187     (535
  

 

 

   

 

 

   

 

 

   

 

 

 

Total operating costs and expenses

     869,273     901,258     3,140,362     3,374,535
  

 

 

   

 

 

   

 

 

   

 

 

 

Income (loss) from operations

     (31,633     293,876     (553,892     1,257,412

Other income (expense):

        

Interest expense

     (65,693     (64,981     (258,240     (269,379

Gain (loss) on extinguishment of debt

     (28,854     —         35,719     (4,584

Other

     277     516     1,662     3,713
  

 

 

   

 

 

   

 

 

   

 

 

 
     (94,270     (64,465     (220,859     (270,250
  

 

 

   

 

 

   

 

 

   

 

 

 

Income (loss) before income taxes

     (125,903     229,411     (774,751     987,162

(Provision) benefit for income taxes

     30,840     (35,303     169,190     (212,689
  

 

 

   

 

 

   

 

 

   

 

 

 

Net income (loss)

     (95,063     194,108     (605,561     774,473

Net income (loss) attributable to noncontrolling interests

     (2,566     162     (8,692     (1,168
  

 

 

   

 

 

   

 

 

   

 

 

 

Net income (loss) attributable to Continental Resources

   $ (92,497   $ 193,946   $ (596,869   $ 775,641
  

 

 

   

 

 

   

 

 

   

 

 

 

Net income (loss) per share attributable to Continental Resources:

        

Basic

   $ (0.26   $ 0.53   $ (1.65   $ 2.09  

Diluted

   $ (0.26   $ 0.53   $ (1.65   $ 2.08  

 

8


Continental Resources, Inc. and Subsidiaries

Consolidated Balance Sheets

 

In thousands

   December 31, 2020      December 31, 2019  

Assets

     

Cash and cash equivalents

   $ 47,470    $ 39,400

Other current assets

     805,075      1,167,615

Net property and equipment (1)

     13,737,292      14,497,726

Other noncurrent assets

     43,261      23,166
  

 

 

    

 

 

 

Total assets

   $ 14,633,098    $ 15,727,907
  

 

 

    

 

 

 

Liabilities and equity

     

Current liabilities

   $ 860,806    $ 1,336,026

Long-term debt, net of current portion

     5,530,173      5,324,079

Other noncurrent liabilities

     1,819,394      1,959,451

Equity attributable to Continental Resources

     6,056,446      6,741,667

Equity attributable to noncontrolling interests

     366,279      366,684
  

 

 

    

 

 

 

Total liabilities and equity

   $ 14,633,098    $ 15,727,907
  

 

 

    

 

 

 

 

(1)

Balance is net of accumulated depreciation, depletion and amortization of $14.77 billion and $12.77 billion as of December 31, 2020 and December 31, 2019, respectively.

Continental Resources, Inc. and Subsidiaries

Consolidated Statements of Cash Flows

 

     Three months ended December 31,     Year ended December 31,  

In thousands

   2020     2019     2020     2019  

Net income (loss)

   $ (95,063   $ 194,108   $ (605,561   $ 774,473

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

        

Non-cash expenses

     597,995     641,495     2,025,987     2,400,708

Changes in assets and liabilities

     (15,395     (31,791     1,878     (59,493
  

 

 

   

 

 

   

 

 

   

 

 

 

Net cash provided by operating activities

     487,537     803,812     1,422,304     3,115,688

Net cash used in investing activities

     (329,492     (518,029     (1,511,358     (2,771,956

Net cash provided by (used in) financing activities

     (131,812     (281,650     97,124     (587,108

Effect of exchange rate changes on cash

     —         7     —         27
  

 

 

   

 

 

   

 

 

   

 

 

 

Net change in cash and cash equivalents

     26,233     4,140     8,070     (243,349

Cash and cash equivalents at beginning of period

     21,237     35,260     39,400     282,749
  

 

 

   

 

 

   

 

 

   

 

 

 

Cash and cash equivalents at end of period

   $ 47,470   $ 39,400   $ 47,470   $ 39,400

 

9


Non-GAAP Financial Measures

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

Our presentation of adjusted net income (loss) and adjusted net income (loss) per share that exclude the effect of certain items are non-GAAP financial measures. Adjusted net income (loss) and adjusted net income (loss) per share represent net income (loss) and diluted net income (loss) 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 gains 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 net income (loss) and adjusted net income (loss) per share should not be considered in isolation or as an alternative to, or more meaningful than, net income (loss) or diluted net income (loss) per share as determined in accordance with U.S. GAAP and may not be comparable to other similarly titled measures of other companies. The following tables reconcile net income (loss) and diluted net income (loss) per share as determined under U.S. GAAP to adjusted net income (loss) and adjusted diluted net income (loss) per share for the periods presented.

 

10


     Three months ended December 31,  
     2020      2019  

In thousands, except per share data

  

            $             

    

Diluted EPS

    

            $             

    

Diluted EPS

 

Net income (loss) attributable to Continental Resources (GAAP)

   $ (92,497    $ (0.26    $ 193,946    $ 0.53

Adjustments:

           

Non-cash (gain) loss on derivatives

     (22,052         16,915   

Property impairments

     12,965         19,348   

Net gain on sale of assets and other

     (5,727         (1,182   

Loss on extinguishment of debt

     28,854         —       

Total tax effect of adjustments (1)

     (3,439         (8,578   

Tax benefit from sale of Canadian subsidiary

     —             (16,860   
  

 

 

       

 

 

    

Total adjustments, net of tax

     10,601      0.03      9,643      0.02
  

 

 

    

 

 

    

 

 

    

 

 

 

Adjusted net income (loss) (non-GAAP)

   $ (81,896    $ (0.23    $ 203,589    $ 0.55

Weighted average diluted shares outstanding

     360,316         368,825   
  

 

 

       

 

 

    

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

   $ (0.23       $ 0.55   

 

     Year ended December 31,  
     2020      2019  

In thousands, except per share data

  

            $             

    

Diluted EPS

    

            $             

    

Diluted EPS

 

Net income (loss) attributable to Continental Resources (GAAP)

   $ (596,869    $ (1.65    $ 775,641    $ 2.08

Adjustments:

           

Non-cash (gain) loss on derivatives

     (13,492         15,612   

Property impairments

     277,941         86,202   

Net (gain) loss on sale of assets and other

     187         (535   

(Gain) loss on extinguishment of debt

     (35,719         4,584   

Total tax effect of adjustments (1)

     (56,083         (25,921   

Tax benefit from sale of Canadian subsidiary

     —             (16,860   
  

 

 

       

 

 

    

Total adjustments, net of tax

     172,834      0.48      63,082      0.17
  

 

 

    

 

 

    

 

 

    

 

 

 

Adjusted net income (loss) (non-GAAP)

   $ (424,035    $ (1.17    $ 838,723    $ 2.25

Weighted average diluted shares outstanding

     361,538         372,538   
  

 

 

       

 

 

    

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

   $ (1.17       $ 2.25   

 

(1)

Computed by applying a combined federal and state statutory tax rate of 24.5% in effect for 2020 and 2019 to the pre-tax amount of adjustments associated with our operations in the United States.

 

11


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, 2020, the Company’s total debt was $5.53 billion and its net debt amounted to $5.48 billion, representing total debt of $5.53 billion less cash and cash equivalents of $47.5 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 gains 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.

 

12


EBITDAX should not be considered as an alternative to, or more meaningful than, net income/loss or net cash provided by operating activities as determined in accordance with U.S. GAAP or as an indicator of a company’s operating performance or liquidity. Certain items excluded from EBITDAX are significant components in understanding and assessing a company’s financial performance, such as a company’s cost of capital and tax structure, as well as the historic costs of depreciable assets, none of which are components of EBITDAX. Our computations of EBITDAX may not be comparable to other similarly titled measures of other companies.

The following table provides a reconciliation of our net income (loss) to EBITDAX for the periods presented.

 

     Three months ended December 31,      Year ended December 31,  

In thousands

   2020      2019      2020      2019  

Net income (loss)

   $ (95,063    $ 194,108    $ (605,561    $ 774,473

Interest expense

     65,693      64,981      258,240      269,379

Provision (benefit) for income taxes

     (30,840      35,303      (169,190      212,689

Depreciation, depletion, amortization and accretion

     592,774      552,711      1,880,959      2,017,383

Property impairments

     12,965      19,348      277,941      86,202

Exploration expenses

     3,094      7,268      17,732      14,667

Impact from derivative instruments:

           

Total (gain) loss on derivatives, net

     (10,977      4,436      14,658      (49,083

Total cash (paid) received on derivatives, net

     (11,075      12,479      (28,150      64,695
  

 

 

    

 

 

    

 

 

    

 

 

 

Non-cash (gain) loss on derivatives, net

     (22,052      16,915      (13,492      15,612

Non-cash equity compensation

     16,527      14,891      64,613      52,044

(Gain) loss on extinguishment of debt

     28,854      —          (35,719      4,584
  

 

 

    

 

 

    

 

 

    

 

 

 

EBITDAX (non-GAAP)

   $ 571,952    $ 905,525    $ 1,675,523    $ 3,447,033

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

   2020      2019      2020      2019  

Net cash provided by operating activities

   $ 487,537    $ 803,812    $ 1,422,304    $ 3,115,688

Current income tax provision (benefit)

     4      —          (2,219      —    

Interest expense

     65,693      64,981      258,240      269,379

Exploration expenses, excluding dry hole costs

     3,092      7,268      11,274      14,667

Gain (loss) on sale of assets and other, net

     5,727      1,182      (187      535

Other, net

     (5,496      (3,509      (12,011      (12,729

Changes in assets and liabilities

     15,395      31,791      (1,878      59,493
  

 

 

    

 

 

    

 

 

    

 

 

 

EBITDAX (non-GAAP)

   $ 571,952    $ 905,525    $ 1,675,523    $ 3,447,033

 

13


Non-GAAP Free Cash Flow and Free Cash Flow Yield

Our presentation of free cash flow and free cash flow yield are non-GAAP measures. We define free cash flow as cash flows from operations before changes in working capital items, less capital expenditures, excluding acquisitions, plus noncontrolling interest capital contributions, less distributions to noncontrolling interests. Noncontrolling interest capital contributions and distributions primarily relate to our 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. Free cash flow yield is calculated by taking free cash flow divided by the market capitalization of the Company at a given date. Management believes these measures are useful to management and investors as measures of a company’s ability to internally fund its capital expenditures, to service or incur additional debt, and to measure management’s success in creating shareholder value. From time to time the Company provides forward-looking free cash flow and free cash flow yield estimates or targets; however, the Company is unable to provide a quantitative reconciliation of these forward-looking non-GAAP measures to the 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.

The following table reconciles net cash provided by operating activities as determined under U.S. GAAP to free cash flow for the full-year 2020 and three months ended December 31, 2020.

 

In thousands

   4Q 2020      FY 2020  

Net cash provided by operating activities (GAAP)

   $ 487,537    $ 1,422,304

Exclude: Changes in working capital items

     15,395      (1,878

Less: Capital expenditures (1)

     (168,049      (1,158,981

Plus: Contributions from noncontrolling interests

     529      27,116

Less: Distributions to noncontrolling interests

     (2,995      (13,809
  

 

 

    

 

 

 

Free cash flow (non-GAAP)

   $ 332,417    $ 274,752

 

(1)

Capital expenditures are calculated as follows:

 

In thousands

   4Q 2020      FY 2020  

Cash paid for capital expenditures

   $ 330,066    $ 1,514,137

Less: Total acquisitions

     (191,508      (225,553

Plus: Change in accrued capital expenditures & other

     28,756      (133,863

Plus: Exploratory seismic costs

     735      4,260
  

 

 

    

 

 

 

Capital expenditures

   $ 168,049    $ 1,158,981

 

14


Non-GAAP Net Sales Prices

Revenues and transportation expenses associated with production from our operated properties are reported separately. 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. As a result, the separate presentation of revenues and transportation expenses from our operated properties differs from the net presentation 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 between operated and non-operated revenues, 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 tables present 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 periods presented.

 

     Three months ended December 31, 2020     Three months ended December 31, 2019  

In thousands

   Crude oil     Natural gas     Total     Crude oil     Natural gas     Total  

Crude oil and natural gas sales (GAAP)

   $ 643,532   $ 173,039   $ 816,571   $ 1,024,432   $ 161,548   $ 1,185,980

Less: Transportation expenses

     (38,208     (10,405     (48,613     (51,332     (9,748     (61,080
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

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

   $ 605,324   $ 162,634   $ 767,958   $ 973,100   $ 151,800   $ 1,124,900

Sales volumes (MBbl/MMcf/MBoe)

     16,210     89,793     31,175     18,956     87,819     33,593
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Net sales price (non-GAAP)

   $ 37.34   $ 1.81   $ 24.63   $ 51.33   $ 1.73   $ 33.49
     Year ended December 31, 2020     Year ended December 31, 2019  

In thousands

   Crude oil     Natural gas         Total         Crude oil     Natural gas     Total  

Crude oil and natural gas sales (GAAP)

   $ 2,199,976   $ 355,458   $ 2,555,434   $ 3,929,994   $ 584,395   $ 4,514,389

Less: Transportation expenses

     (158,989     (37,703     (196,692     (191,998     (33,651     (225,649
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

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

   $ 2,040,987   $ 317,755   $ 2,358,742   $ 3,737,996   $ 550,744   $ 4,288,740

Sales volumes (MBbl/MMcf/MBoe)

     58,793     306,528     109,881     72,136     311,865     124,113
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Net sales price (non-GAAP)

   $ 34.71   $ 1.04   $ 21.47   $ 51.82   $ 1.77   $ 34.56

 

15


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,  
     2020      2019      2020      2019  

Total G&A per Boe (GAAP)

   $ 2.14    $ 1.59    $ 1.79    $ 1.57

Less: Non-cash equity compensation per Boe

     (0.53      (0.44      (0.59      (0.42
  

 

 

    

 

 

    

 

 

    

 

 

 

Cash G&A per Boe (non-GAAP)

   $ 1.61    $ 1.15    $ 1.20    $ 1.15

 

16


Continental Resources, Inc.

2021 Guidance

As of February 16, 2021

 

     2021

Full-year average oil production (Bopd)

   160,000 to 165,000

Full-year average natural gas production (Mcfpd)

   880,000 to 920,000

Capital expenditures budget

   $1.4 billion

Operating Expenses:

  

Production expense per Boe

   $3.25 to $3.75

Production tax (% of net oil & gas revenue)

   7.9% to 8.1%

Cash G&A expense per Boe(1)

   $1.20 to $1.40

Non-cash equity compensation per Boe

   $0.45 to $0.55

DD&A per Boe

   $16.50 to $18.50

Average Price Differentials:

  

NYMEX WTI crude oil (per barrel of oil)

   ($4.50) to ($5.50)

Henry Hub natural gas(2) (per Mcf)

   ($0.25) to ($0.75)

 

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 a projected range of $1.65 to $1.95 per Boe.

2.

Includes natural gas liquids production in differential range.

2021 Capital Expenditures

The following table provides the breakout of budgeted capital expenditures:

 

($ in Millions)

   North D&C      South D&C      Leasehold, Facilities, Other(1)  

Capex

   $ 732      $ 380      $ 288  

 

1.

Includes $13 million of minerals royalty acquisitions attributable to Continental. Excludes $52 million of minerals acquisitions attributable to Franco-Nevada.

2021 Operational Detail

The following table provides additional operational detail for wells expected to have first production in 2021:

 

Asset

   Average Rigs      Gross Operated Wells      Net Operated Wells      Total Net Wells(1)  

North

     7        143        85        94  

South

     4        67        54        57  

Total

     11        210        139        151  

 

1.

Represents projected net operated and non-operated wells with first production.

 

17

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