EX-99.1 2 d272362dex991.htm EX-99.1 EX-99.1

Exhibit 99.1

NEWS RELEASE

CONTINENTAL RESOURCES ANNOUNCES RECORD 2021 RESULTS;

2022 PROJECTIONS HIGHLIGHT INCREASING CASH FLOW & CORPORATE RETURNS

2021: Delivered Record Cash Flow Generation

 

•  

$1.66 B Net Income; $4.56 per Diluted Share ($1.70 B Adj. Net Income; $4.66 per Adj Share (Non-GAAP))

 

  •  

Company Record $3.97 B Cash Flow from Operations (CFO) & $2.64 B Free Cash Flow (FCF) (Non-GAAP)

 

  •  

14.6% Return on Capital Employed1 (ROCE)

Significant Increase in Return of Capital to Shareholders

 

•  

Increasing Quarterly Dividend to $0.23 per Share (~1.7% Dividend Yield2); Targeting 2.0% or Greater Yield Long Term

 

•  

Increasing Share Buyback Program from $1.0 B to $1.5 B (Inclusive of $441 MM Repurchased to Date)

2022: Increasing Cash Flow & Corporate Returns

 

•  

$5.2 B Projected CFO3; $2.9 B Projected FCF; ~15% FCF Yield4 (Non-GAAP)

 

  •  

$2.3 B Capex Budget; ~$30 WTI FCF Breakeven Price

 

  •  

195-205 MBopd & 1,040 -1,140 MMcfpd Avg. Daily Production

 

•  

21% Projected ROCE

 

•  

<1.0x Net Debt (Non-GAAP) to EBITDAX (Non-GAAP) Target by YE22 or Earlier

2022-2025 Projection: Enhancing Shareholder Value Through Expanding Corporate Returns

 

•  

Targeting At Least $20.7 B Cumulative Projected CFO & $11.6 B Cumulative FCF (>55% Current Market Cap)

 

  •  

Based Upon a Flat YoY Capex, Relative to 2022, Delivering a Low Single Digit Production CAGR3

 

•  

22% Average Projected ROCE

Oklahoma City, February 14, 2022 – Continental Resources, Inc. (NYSE: CLR) (the “Company”) today announced its full-year 2021 and fourth quarter 2021 operating and financial results, its 2022 capital expenditures budget and operating plan, and its 2022 to 2025 financial projections.

“In 2021, Continental achieved a record level of annual adjusted earnings per share alongside a nearly 15% return on capital employed and a Company record $2.6 billion of free cash flow. Given operational excellence across our premier asset portfolio, we will continue to strongly compete by expanding return of capital to shareholders while providing above average S&P 500 and industry return on capital employed through 2022 and beyond,” said Bill Berry, Chief Executive Officer.

 

 

1 

Return on capital employed represents net income attributable to the Company before non-cash gains and losses on derivatives, non-cash equity compensation expense, interest expense, and gains and losses on extinguishment of debt, the result of which is divided by average capital employed for the year, with capital employed representing the sum of total debt and total shareholders’ equity attributable to the Company, less cash and cash equivalents.

2 

Annualized dividend yield is calculated as the annual dividend per share, based on the February 2022 dividend, divided by the stock price per share as of February 8, 2022. All future dividends require Board approval.

3 

Based on $80 WTI & $3.50 HH.

4 

Free cash flow yield is estimated by dividing the 2022 annual FCF estimate by the Company’s current market capitalization, as of February 8, 2022.

 

1

The Company reported full-year 2021 net income of $1.66 billion, or $4.56 per diluted share. For full-year 2021, typically excluded items in aggregate represented $39.0 million, or $0.10 per diluted share, of Continental’s reported net income. Adjusted net income for full-year 2021 was $1.70 billion, or $4.66 per diluted share (non-GAAP). Net cash provided by operating activities for full-year 2021 was $3.97 billion and EBITDAX was $4.46 billion (non-GAAP).

The Company reported net income of $742.7 million, or $2.04 per diluted share, for the quarter ended December 31, 2021. In fourth quarter 2021, typically excluded items in aggregate represented ($91.6) million, or ($0.25) per diluted share, of Continental’s reported net income. Adjusted net income for fourth quarter 2021 was $651.0 million, or $1.79 per diluted share (non-GAAP). Net cash provided by operating activities for fourth quarter 2021 was $1.25 billion and EBITDAX was $1.39 billion (non-GAAP).

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

2021 Production & Operations Update

Full-year 2021 total production averaged 329.6 MBoepd. Full-year 2021 oil production averaged 160.6 MBopd. Full-year 2021 natural gas production averaged 1,014 MMcfpd. Fourth quarter 2021 total production averaged 340.2 MBoepd. Fourth quarter 2021 oil production averaged 166.7 MBopd. Fourth quarter 2021 natural gas production averaged 1,041 MMcfpd. The following table provides the Company’s average daily production by region for the periods presented.

 

Boe per day

    4Q
2021		      4Q
2020		      YTD
2021		      YTD
2020		  

Bakken

      175,585        183,141        169,636        158,604  

Powder River

      7,189        —          5,161        —    

Oklahoma

      146,131        149,341        147,249        134,506  

Permian(1)

      4,997        —          1,260        —    

All other

      6,266        6,825        6,341        6,980  
  

 

 

     

 

 

     

 

 

     

 

 

  

Total

      340,168        339,307        329,647        300,090  

 

(1)

The presentation of average daily production represents production during the period from the closing of our acquisition of Permian properties on December 21, 2021 through December 31, 2021 averaged over the respective fourth quarter and full year periods. At the time of closing, our Permian properties produced on average approximately 42,000 Boe per day based on two-stream reporting.

2021 Financial Update

“The Company delivered a record year of performance in 2021. We believe the 360% increase to our quarterly dividend since inception, our recently increased corporate buyback program from $1.0 billion to $1.5 billion, inclusive of $441 million repurchased to date, and our double digit return on capital employed demonstrates the strength of our commitment to enhancing shareholder capital and corporate returns,” said John Hart, Chief Financial Officer & Executive Vice President of Strategic Planning.

 

2

4Q 2021 Financial Update

    Three Months Ended
December 31, 2021		      Year Ended
December 31, 2021		  

Cash and Cash Equivalents

         $20.9 million  

Total Debt

         $6.83 billion  

Net Debt (non-GAAP)(1)

         $6.81 billion  

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

      

Per Barrel of Oil

      $73.19        $64.06  

Per Mcf of Gas

      $6.31        $4.88  

Per Boe

      $55.27        $46.24  

Production Expense per Boe

      $3.63        $3.38  

Total G&A Expenses per Boe

      $2.12        $1.94  

Crude Oil Net Sales Price Discount to NYMEX ($/Bbl)

      ($3.61 )       ($4.00 ) 

Natural Gas Net Sales Price Premium to NYMEX ($/Mcf)

      $0.49        $1.00  

Non-Acquisition Capital Expenditures attributable to CLR

      $574.2 million        $1,540.8 million  

Exploration & Development Drilling & Completion

      $382.6 million        $1,166.7 million  

Leasehold and minerals

      $114.0 million        $157.5 million  

Workovers, Recompletions and Other

      $77.6 million        $216.6 million  

Minerals attributable to FNV

      $11.6 million        $21.3 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.

Significant Increase in Return of Capital to Shareholders

The Company’s Board of Directors recently approved increasing the Company’s quarterly dividend to $0.23 per share, payable on March 4, 2022 to stockholders of record on February 22, 2022. This dividend represents a $0.03, or 15%, increase to the Company’s $0.20 per share quarterly dividend paid in fourth quarter 2021 and equates to an approximately 1.7% annualized dividend yield, as of February 8, 2022. The Company is targeting a 2% or greater annualized dividend yield long term. The Company is also increasing its existing share repurchase program from $1.0 billion to $1.5 billion, which is inclusive of $441 million repurchased to date. The Company has repurchased 17 million shares to date at an average price of $26.00, which includes 3.2 million shares repurchased in 2021 at an average price of $38.74.

2022: Increasing Cash Flow & Corporate Returns

The Company is projecting a $2.3 billion capital expenditures budget, excluding Franco Nevada’s share of mineral costs. The Company is allocating approximately $1.8 billion to D&C activities and an additional $500 million is being allocated to non-D&C capital, planned to be primarily for leasehold, mineral acquisitions, workovers and facilities. The capital expenditures budget includes a 15% increase to legacy spending in the Bakken and Anadarko Basins combined with an approximately $500 million increase attributed to the Company’s recently acquired positions in the Permian and Powder River basins.

The 2022 capital expenditures budget is projected to generate approximately $5.2 billion of cash flow from operations and $2.9 billion of free cash flow (non-GAAP) for full-year 2022 at $80 per barrel WTI and $3.50 per Mcf Henry Hub. The Company is projecting approximately 15% free cash flow yield (non-GAAP). The Company is projecting an approximately $30 WTI free cash flow breakeven price. A $5 increase per barrel WTI is estimated to increase annual cash flow by approximately $300 million.

 

3

The Company is projecting approximately 21% return on capital employed for 2022.

The Company is targeting less than 1.0x net debt (non-GAAP) to EBITDAX (non-GAAP) by year-end 2022 or earlier.

Annual crude oil production is projected to range between 195 to 205 MBopd. Annual natural gas production is projected to range between 1,040 to 1,140 MMcfpd. At year-end 2022, the Company projects a working backlog of approximately 175 gross operated wells in progress in various stages of completion.

The Company’s full 2022 guidance, capital expenditures budget and operating details can be found at the conclusion of this press release.

2022-2025 Projection: Enhancing Shareholder Value Through Expanding Corporate Returns

From 2022 to 2025, the Company is projected to deliver at least $20.7 billion of cumulative cash flow from operations and $11.6 billion of cumulative free cash flow (non-GAAP), based upon a flat year-over-year Capex, relative to 2022, delivering a low single digit production compound annual growth rate at $80 WTI & $3.50 HH. The production profile under this scenario is approximately 55% oil, increasing throughout the multiyear projection. This level of free cash flow represents over 55% of the Company’s current market capitalization.

Given the significant level of free cash flow generation over the multi-year period, the Company is projected to achieve its targets of less than 1.0x net debt (non-GAAP) to EBITDAX (non-GAAP), a competitive 2.0% dividend yield and the $1.5 billion share repurchase program, inclusive of $441 million repurchased to date, with approximately $6.6 billion of free cash flow (non-GAAP) remaining at $80 WTI. Additionally, the Company is projecting a 22% average return on capital employed over this time period.

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.

 

4

     Three months ended December 31,     Year ended December 31  
     2021     2020     2021     2020  

Average daily production:

         

Crude oil (Bbl per day)

      166,694       176,639       160,647       160,505  

Natural gas (Mcf per day)

      1,040,842       976,011       1,014,000       837,509  

Crude oil equivalents (Boe per day)

      340,168       339,307       329,647       300,090  

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

         

Crude oil ($/Bbl)

    $ 73.19     $ 37.34     $ 64.06     $ 34.71  

Natural gas ($/Mcf)

    $ 6.31     $ 1.81     $ 4.88     $ 1.04  

Crude oil equivalents ($/Boe)

    $ 55.27     $ 24.63     $ 46.24     $ 21.47  

Production expenses ($/Boe)

    $ 3.63     $ 2.80     $ 3.38     $ 3.27  

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

      7.1 %      7.8 %      7.3 %      8.2 % 

DD&A ($/Boe)

    $ 14.34     $ 19.01     $ 15.76     $ 17.12  

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

    $ 2.12     $ 2.14     $ 1.94     $ 1.79  

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

    $ 742,673     $ (92,497 )    $ 1,660,968     $ (596,869 ) 

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

    $ 2.04     $ (0.26 )    $ 4.56     $ (1.65 ) 

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

    $ 651,048     $ (81,896 )    $ 1,699,941     $ (424,035 ) 

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

    $ 1.79     $ (0.23 )    $ 4.66     $ (1.17 ) 

Net cash provided by operating activities (in thousands)

    $ 1,245,198     $ 487,537     $ 3,973,851     $ 1,422,304  

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

    $ 1,388,016     $ 571,952     $ 4,462,884     $ 1,675,523  

 

(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 $1.54, $1.61, $1.42, and $1.20 for 4Q 2021, 4Q 2020, YTD 2021, and YTD 2020, respectively. Non-cash equity compensation expense per Boe was $0.58, $0.53, $0.52, and $0.59 for 4Q 2021, 4Q 2020, YTD 2021, and YTD 2020, respectively.

Fourth Quarter Earnings Conference Call

The Company plans to host a conference call to discuss fourth quarter 2021 results on Tuesday, February 15, 2022 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, Tuesday, February 15, 2022
Dial-in:    1-888-317-6003
Intl. dial-in:    1-412-317-6061
Conference ID:    7211512

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:    4916837

 

5

The Company plans to publish a fourth quarter 2021 summary presentation to its website at www.CLR.com prior to the start of its conference call on Tuesday, February 15, 2022.

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 is also the largest producer in the Anadarko Basin of Oklahoma and has newly acquired positions in the Powder River Basin of Wyoming and Permian Basin of Texas. 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 2022, the Company will celebrate 55 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

 

6

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 and greenhouse gas emissions; 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, 2020, and once filed, the Company’s Annual Report on Form 10-K for the year ended December 31, 2021, 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 our best estimate of recoverable oil and natural gas hydrocarbon quantities. Actual reserves recovered may differ from estimated quantities. 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
Rory.Sabino@CLR.com    Kristin.Thomas@CLR.com
Lucy Spaay   
Investor Relations Analyst   
405-774-5878   
Lucy.Spaay@CLR.com   

 

7

Continental Resources, Inc. and Subsidiaries

Consolidated Statements of Comprehensive Income (Loss)

 

     Three months ended December 31,     Year ended December 31,  
     2021     2020     2021     2020  
     In thousands, except per
share data		              

Revenues:

       

Crude oil and natural gas sales

    $ 1,807,113     $ 816,571     $ 5,793,741     $ 2,555,434  

Gain (loss) on derivative instruments, net

      103,931       10,977       (128,864 )      (14,658 ) 

Crude oil and natural gas service operations

      15,922       10,092       54,441       45,694  
  

 

 

    

 

 

    

 

 

    

 

 

  

Total revenues

      1,926,966       837,640       5,719,318       2,586,470  

Operating costs and expenses:

         

Production expenses

      114,115       87,415       406,906       359,267  

Production taxes

      123,695       60,274       404,362       192,718  

Transportation expenses

      68,319       48,613       224,989       196,692  

Exploration expenses

      11,577       3,094       21,047       17,732  

Crude oil and natural gas service operations

      6,443       3,006       21,480       18,294  

Depreciation, depletion, amortization and accretion

      451,259       592,774       1,898,082       1,880,959  

Property impairments

      7,379       12,965       38,370       277,941  

Acquisition costs

      13,920       —         13,920       —    

General and administrative expenses

      66,806       66,859       233,628       196,572  

Net (gain) loss on sale of assets and other

      (1,650 )      (5,727 )      (5,146 )      187  
  

 

 

    

 

 

    

 

 

    

 

 

  

Total operating costs and expenses

      861,863       869,273       3,257,638       3,140,362  
  

 

 

    

 

 

    

 

 

    

 

 

  

Income (loss) from operations

      1,065,103       (31,633 )      2,461,680       (553,892 ) 

Other income (expense):

         

Interest expense

      (65,802 )      (65,693 )      (251,598 )      (258,240 ) 

Gain (loss) on extinguishment of debt

      —         (28,854 )      (290 )      35,719  

Other

      (24,549 )      277       (23,654 )      1,662  
  

 

 

    

 

 

    

 

 

    

 

 

  
     (90,351 )      (94,270 )      (275,542 )      (220,859 ) 
  

 

 

    

 

 

    

 

 

    

 

 

  

Income (loss) before income taxes

      974,752       (125,903 )      2,186,138       (774,751 ) 

(Provision) benefit for income taxes

      (228,614 )      30,840       (519,730 )      169,190  
  

 

 

    

 

 

    

 

 

    

 

 

  

Net income (loss)

      746,138       (95,063 )      1,666,408       (605,561 ) 

Net income (loss) attributable to noncontrolling interests

      3,465       (2,566 )      5,440       (8,692 ) 
  

 

 

    

 

 

    

 

 

    

 

 

  

Net income (loss) attributable to Continental Resources

    $ 742,673     $ (92,497 )    $ 1,660,968     $ (596,869 ) 
  

 

 

    

 

 

    

 

 

    

 

 

  

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

 

    

Basic

    $ 2.07     $ (0.26 )    $ 4.61     $ (1.65 ) 

Diluted

    $ 2.04     $ (0.26 )    $ 4.56     $ (1.65 ) 

 

8

Continental Resources, Inc. and Subsidiaries

Consolidated Balance Sheets

 

In thousands

    December 31, 2021      December 31, 2020  

Assets

      

Cash and cash equivalents

    $ 20,868      $ 47,470  

Other current assets

      1,543,522        805,075  

Net property and equipment (1)

      16,975,465        13,737,292  

Other noncurrent assets

      51,256        43,261  
  

 

 

     

 

 

  

Total assets

    $ 18,591,111      $ 14,633,098  
  

 

 

     

 

 

  

Liabilities and equity

      

Current liabilities

    $ 1,500,127      $ 860,806  

Long-term debt, net of current portion

      6,826,566        5,530,173  

Other noncurrent liabilities

      2,408,093        1,819,394  

Equity attributable to Continental Resources

      7,475,456        6,056,446  

Equity attributable to noncontrolling interests

      380,869        366,279  
  

 

 

     

 

 

  

Total liabilities and equity

    $ 18,591,111      $ 14,633,098  
  

 

 

     

 

 

  

 

(1)

Balance is net of accumulated depreciation, depletion and amortization of $16.48 billion and $14.77 billion as of December 31, 2021 and December 31, 2020, respectively.

Continental Resources, Inc. and Subsidiaries

Consolidated Statements of Cash Flows

 

     Three months ended December 31,     Year ended December 31,  

In thousands

    2021     2020     2021     2020  

Net income (loss)

    $ 746,138     $ (95,063 )    $ 1,666,408     $ (605,561 ) 

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

         

Non-cash expenses

      562,716       597,995       2,524,323       2,025,987  

Changes in assets and liabilities

      (63,656 )      (15,395 )      (216,880 )      1,878  
  

 

 

    

 

 

    

 

 

    

 

 

  

Net cash provided by operating activities

      1,245,198       487,537       3,973,851       1,422,304  

Net cash used in investing activities

      (3,865,744 )      (329,492 )      (4,989,545 )      (1,511,358 ) 

Net cash provided by (used in) financing activities

      1,947,765       (131,812 )      989,092       97,124  
  

 

 

    

 

 

    

 

 

    

 

 

  

Net change in cash and cash equivalents

      (672,781 )      26,233       (26,602 )      8,070  

Cash and cash equivalents at beginning of period

      693,649       21,237       47,470       39,400  
  

 

 

    

 

 

    

 

 

    

 

 

  

Cash and cash equivalents at end of period

    $ 20,868     $ 47,470     $ 20,868     $ 47,470  

 

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, gains and losses on extinguishment of debt, acquisition costs, and charitable donations 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 acquisitions and 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,  
     2021      2020  

In thousands, except per share data

    $      Diluted EPS      $      Diluted EPS  

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

    $ 742,673      $ 2.04      $ (92,497 )     $ (0.26 ) 

Adjustments:

            

Non-cash gain on derivatives

      (166,007 )          (22,052 )    

Property impairments

      7,379           12,965     

Net gain on sale of assets and other

      (1,650 )          (5,727 )    

Loss on extinguishment of debt

      —             28,854     

Acquisition costs

      13,920           —       

Other (OSU charitable donation)

      25,000           —       

Total tax effect of adjustments (1)

      29,733           (3,439 )    
  

 

 

        

 

 

     

Total adjustments, net of tax

      (91,625 )       (0.25 )       10,601        0.03  
  

 

 

     

 

 

     

 

 

     

 

 

  

Adjusted net income (loss) (non-GAAP)

    $ 651,048      $ 1.79      $ (81,896 )     $ (0.23 ) 

Weighted average diluted shares outstanding

      363,391           360,316     
  

 

 

        

 

 

     

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

    $ 1.79         $ (0.23 )    
     Year ended December 31,  
     2021      2020  

In thousands, except per share data

    $      Diluted EPS      $      Diluted EPS  

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

    $ 1,660,968      $ 4.56      $ (596,869 )     $ (1.65 ) 

Adjustments:

            

Non-cash gain on derivatives

      (20,814 )          (13,492 )    

Property impairments

      38,370           277,941     

Net (gain) loss on sale of assets and other

      (5,146 )          187     

(Gain) loss on extinguishment of debt

      290           (35,719 )    

Acquisition costs

      13,920           —       

Other (OSU charitable donation)

      25,000           —       

Total tax effect of adjustments (1)

      (12,647 )          (56,083 )    
  

 

 

        

 

 

     

Total adjustments, net of tax

      38,973        0.10        172,834        0.48  
  

 

 

     

 

 

     

 

 

     

 

 

  

Adjusted net income (loss) (non-GAAP)

    $ 1,699,941      $ 4.66      $ (424,035 )     $ (1.17 ) 

Weighted average diluted shares outstanding

      364,453           361,538     
  

 

 

        

 

 

     

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

    $ 4.66         $ (1.17 )    

 

(1)

Computed by applying a combined federal and state statutory tax rate of 24.5% in effect for 2021 and 2020 to the pre-tax amount of adjustments.

 

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, 2021, the Company’s total debt was $6.83 billion and its net debt amounted to $6.81 billion, representing total debt of $6.83 billion less cash and cash equivalents of $20.9 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, gains and losses on extinguishment of debt, and non-cash charitable donations 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.

 

12

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

    2021      2020      2021      2020  

Net income (loss)

    $ 746,138      $ (95,063 )     $ 1,666,408      $ (605,561 ) 

Interest expense

      65,802        65,693        251,598        258,240  

Provision (benefit) for income taxes

      228,614        (30,840 )       519,730        (169,190 ) 

Depreciation, depletion, amortization and accretion

      451,259        592,774        1,898,082        1,880,959  

Property impairments

      7,379        12,965        38,370        277,941  

Exploration expenses

      11,577        3,094        21,047        17,732  

OSU charitable donation

      25,000        —          25,000        —    

Impact from derivative instruments:

            

Total (gain) loss on derivatives, net

      (103,931 )       (10,977 )       128,864        14,658  

Total cash paid on derivatives, net

      (62,077 )       (11,075 )       (149,678 )       (28,150 ) 
  

 

 

     

 

 

     

 

 

     

 

 

  

Non-cash (gain) loss on derivatives, net

      (166,008 )       (22,052 )       (20,814 )       (13,492 ) 

Non-cash equity compensation

      18,255        16,527        63,173        64,613  

(Gain) loss on extinguishment of debt

      —          28,854        290        (35,719 ) 
  

 

 

     

 

 

     

 

 

     

 

 

  

EBITDAX (non-GAAP)

    $ 1,388,016      $ 571,952      $ 4,462,884      $ 1,675,523  

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

    2021      2020      2021      2020  

Net cash provided by operating activities

    $ 1,245,198      $ 487,537      $ 3,973,851      $ 1,422,304  

Current income tax benefit

      —          4        —          (2,219 ) 

Interest expense

      65,802        65,693        251,598        258,240  

Exploration expenses, excluding dry hole costs

      11,577        3,092        21,047        11,274  

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

      1,650        5,727        5,146        (187 ) 

Other, net

      133        (5,496 )       (5,638 )       (12,011 ) 

Changes in assets and liabilities

      63,656        15,395        216,880        (1,878 ) 
  

 

 

     

 

 

     

 

 

     

 

 

  

EBITDAX (non-GAAP)

    $ 1,388,016      $ 571,952      $ 4,462,884      $ 1,675,523  

 

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 a measure 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 three months ended December 31, 2021 and full-year 2021.

 

In thousands

    4Q 2021      FY 2021  

Net cash provided by operating activities (GAAP)

    $ 1,245,198      $ 3,973,851  

Exclude: Changes in working capital items

      63,656        216,880  

Less: Capital expenditures (1)

      (585,711 )       (1,561,953 ) 

Plus: Contributions from noncontrolling interests

      11,681        31,493  

Less: Distributions to noncontrolling interests

      (5,912 )       (22,447 ) 
  

 

 

     

 

 

  

Free cash flow (non-GAAP)

    $ 728,912      $ 2,637,824  

 

(1)

Capital expenditures are calculated as follows:

 

In thousands

    4Q 2021      FY 2021  

Cash paid for capital expenditures

    $ 3,869,223      $ 4,997,585  

Less: Total acquisitions

      (3,340,684 )       (3,583,658 ) 

Plus: Change in accrued capital expenditures & other

      48,005        135,538  

Plus: Exploratory seismic costs

      9,167        12,488  
  

 

 

     

 

 

  

Capital expenditures

    $ 585,711      $ 1,561,953  

 

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, 2021     Three months ended December 31, 2020  

In thousands

    Crude oil     Natural gas     Total     Crude oil     Natural gas     Total  

Crude oil and natural gas sales (GAAP)

    $ 1,190,435     $ 616,678     $ 1,807,113     $ 643,532     $ 173,039     $ 816,571  

Less: Transportation expenses

      (55,912 )      (12,407 )      (68,319 )      (38,208 )      (10,405 )      (48,613 ) 
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

    

 

 

  

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

    $ 1,134,523     $ 604,271     $ 1,738,794     $ 605,324     $ 162,634     $ 767,958  

Sales volumes (MBbl/MMcf/MBoe)

      15,501       95,757       31,460       16,210       89,793       31,176  
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

    

 

 

  

Net sales price (non-GAAP)

    $ 73.19     $ 6.31     $ 55.27     $ 37.34     $ 1.81     $ 24.63  
     Year ended December 31, 2021     Year ended December 31, 2020  

In thousands

    Crude oil     Natural gas     Total     Crude oil     Natural gas     Total  

Crude oil and natural gas sales (GAAP)

    $ 3,949,294     $ 1,844,447     $ 5,793,741     $ 2,199,976     $ 355,458     $ 2,555,434  

Less: Transportation expenses

      (185,130 )      (39,859 )      (224,989 )      (158,989 )      (37,703 )      (196,692 ) 
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

    

 

 

  

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

    $ 3,764,164     $ 1,804,588     $ 5,568,752     $ 2,040,987     $ 317,755     $ 2,358,742  

Sales volumes (MBbl/MMcf/MBoe)

      58,757       370,110       120,442       58,793       306,528       109,881  
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

    

 

 

  

Net sales price (non-GAAP)

    $ 64.06     $ 4.88     $ 46.24     $ 34.71     $ 1.04     $ 21.47  

 

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,  
       2021        2020        2021        2020  

Total G&A per Boe (GAAP)

      $ 2.12        $ 2.14        $ 1.94        $ 1.79  

Less: Non-cash equity compensation per Boe

        (0.58 )         (0.53 )         (0.52 )         (0.59 ) 
    

 

 

       

 

 

       

 

 

       

 

 

  

Cash G&A per Boe (non-GAAP)

      $ 1.54        $ 1.61        $ 1.42        $ 1.20  

 

16

Calculation of Return on Capital Employed (ROCE)

The following table shows the calculation of ROCE for 2021.

 

In thousands    2021  

Net income (loss) attributable to Continental Resources

    $ 1,660,968  

Non-cash (gain) loss on derivatives, net

      (20,814 ) 

Non-cash equity compensation

      63,173  

Interest expense

      251,598  

(Gain) loss on extinguishment of debt

      290  

Tax effect(1)

      (72,091 ) 
  

 

 

  

Adjusted Net Operating Profit After Tax

    $ 1,883,124  

Total debt - beginning of period

      5,532,418  

Less: Cash and cash equivalents - beginning of period

      (47,470 ) 
  

 

 

  

Net Debt - beginning of period

      5,484,948  

Equity attributable to Continental Resources - beginning of period

      6,056,446  
  

 

 

  

Capital employed - beginning of period

      11,541,394  

Total debt - end of period

      6,828,892  

Less: Cash and cash equivalents - end of period

      (20,868 ) 
  

 

 

  

Net Debt - end of period

      6,808,024  

Equity attributable to Continental Resources - end of period

      7,475,456  
  

 

 

  

Capital employed - end of period

      14,283,480  

Average capital employed

    $ 12,912,437  
  

 

 

  

ROCE

      14.6 % 

 

(1)

Computed by applying a combined federal and state statutory tax rate of 24.5% to the pre-tax amount of adjustments.

 

17

Continental Resources, Inc.

2022 Guidance

As of February 14, 2022

 

     2022
 

Full-year average oil production (Bopd)

    195,000 to 205,000
 

Full-year average natural gas production (Mcfpd)

    1,040,000 to 1,140,000
 

Capital expenditures budget

    $2.3 billion
 

Full-Year Operating Expenses:

   
 

Production expense per Boe

    $3.50 to $4.00
 

Production tax (% of net oil & gas revenue)

    7.5% to 8.0%
 

Cash G&A expense per Boe(1)

    $1.20 to $1.40
 

Non-cash equity compensation per Boe

    $0.50 to $0.60
 

DD&A per Boe

    $14.00 to $16.00
 

Average Price Differentials:

   
 

NYMEX WTI crude oil (per barrel of oil)

    ($3.00) to ($4.00)
 

Henry Hub natural gas(2) (per Mcf)

    +$0.10 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 $1.70 to $2.00 per Boe.

2.

Includes natural gas liquids production in differential range.

 

2022 Capital Expenditures
The following table provides the breakout of budgeted capital expenditures:

 

($ in Millions)

    Bakken
D&C		      Anadarko
D&C		      Powder River
D&C		      Permian
D&C		      Leasehold,
Facilities, Other(1)		  

Capex

    $ 800      $ 400      $ 200      $ 400      $ 500  

 

1.  Includes $23 million of minerals royalty acquisitions attributable to Continental. Excludes $91 million of minerals acquisitions attributable to Franco-Nevada.

 

2022 Operational Detail

The following table provides additional operational detail for wells expected to have first production in 2022:

 

Asset

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

Bakken

    6.5      153        95        116  

Anadarko

    6.5      55        36        41  

Powder River

    2      30        20        20  

Permian

    4      46        45        46  

Total

    19      284        196        223  

 

1.

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

 

18