Benzinga | Nov 5, 2020 05:13PM EST

Continental Resources Sees FY 2021 Cash Flow From Operations Of $1.6B

Continental Resources Announces Third Quarter 2020 Results; Preliminary 2021 Outlook

OKLAHOMA CITY, Nov. 5, 2020 /PRNewswire/ --

3Q20 Results and Full-Year 2020 Expectations

* $291.2 Million Cash Flow from Operations in 3Q20; $258.3 Million Free Cash Flow (Non-

GAAP)

* $149.4 Million in Non-Acquisition Capex in 3Q20; On Track for $1.2 Billion in Full-Year

2020

* 297 MBoepd Average Daily Production in 3Q20 (57% Oil)

o Maintain 2020 Average Annual Production Guidance of 155 to 165 MBopd & 800 to 820

MMcfpd

o December 2020 Exit Rate Production of 315 to 325 MBoepd

* $1.63 Total G&A per Boe in 3Q20 in Line with Initial 2020 Guidance; $1.04 Cash G&A per

Boe (Non-GAAP) and $3.19 Production Expense per Boe in 3Q20 Below Initial 2020

Guidance

* Improved Cost Metric Guidance for 2020

o 2020 Total G&A per Boe Guidance of $1.60 to $1.90 (Previously $1.60 to $2.00)

o 2020 Cash G&A per Boe Guidance: $1.10 to $1.30 (Previously $1.10 to $1.40)

o 2020 Production Expense per Boe Guidance: $3.50 to $3.75 (Previously $3.50 to $4.00)

* Operating Efficiencies Improve Year-Over-Year All-In Completed Well Costs (CWC) per

Well

o South: $9.0 Million CWC Improved 14% YoY (80% Structural); Targeting $8.9 Million YE20

o Bakken: $7.2 Million CWC Improved 12% YoY (70% Structural); Targeting $6.9 Million YE20

Preliminary 2021 Outlook

* Oklahoma Oil & Gas Assets Provide Optionality to Capitalize on Strong Gas Prices in 2021

* Maximizing Free Cash Flow (FCF) & Prioritizing Debt Paydown

o Projecting Annual Cash Flow from Operations of $1.6 Billion and Annual FCF of Approximately

$400 Million (Approx. 8.0% FCF Yield) at the Midpoint of Projected Capex Spend at $40 WTI

o Projecting Annual Cash Flow from Operations of $1.85 Billion and Annual FCF of

Approximately $650 Million (Approx. 14.0% FCF Yield) at the Midpoint of Projected Capex

Spend at $45 WTI

o Projecting Total Debt Below $5.0 Billion at YE21; $4.0 Billion or Below by YE22/2023

* Projecting 65-75% Cash Flow from Operations (CFFO) Reinvestment Rate for 2021

o Projecting $1.2 to $1.3 Billion Capex Spend in 2021 at $40 to $45 WTI

o Projecting Low Single Digit Production Growth YoY with Cash Flow Breakeven Price of $32

WTI

Continental Resources, Inc. (NYSE:CLR) (the "Company") today announced third quarter 2020 operating and financial results, as well as its preliminary 2021 outlook.

The Company reported a net loss of $79.4 million, or $0.22 per diluted share, for the quarter ended September 30, 2020. In third quarter 2020, typically excluded items in aggregate represented $20.5 million, or $0.06 per diluted share of Continental's reported net loss. Adjusted net loss for third quarter 2020 was $58.9 million, or $0.16 per diluted share (non-GAAP). Net cash provided by operating activities for third quarter 2020 was $291.2 million and free cash flow was $258.3 million. EBITDAX was $473.3 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.

"The production we voluntarily curtailed was back on line in the third quarter 2020, performing well as anticipated. As we look to year end 2020 and into 2021, we will continue our track record of delivering sustainable free cash flow alongside ongoing debt reduction, low cost leadership and unmatched shareholder alignment, while responsibly fueling a better world through our ESG stewardship," said Bill Berry, Chief Executive Officer.

Production & Operations Update

Third quarter 2020 total production averaged 297,001 Boepd. Third quarter 2020 oil production averaged 169,265 Bopd. Third quarter 2020 natural gas production averaged 766.4 MMcfpd. The Company maintains its full-year 2020 production guidance of 155,000 to 165,000 Bopd and 800,000 to 820,000 Mcfpd. The Company expects exit rate production of 315,000 to 325,000 Boepd in December 2020.

Technical innovations and operating efficiencies in the Bakken and Oklahoma continue to reduce cycle times and CWC, which include drilling and completion, full facilities costs and artificial lift. In the Bakken, CWC have improved 12% year-over-year to $7.2 million per well, with a $6.9 million target by year-end 2020. Approximately 70% of cost savings are structural. In Oklahoma, CWC have improved 14% year-over-year to $9.0 million per well, with an $8.9 million target by year-end 2020. Approximately 80% of cost savings are structural.

"The capital efficiency of our operations continues to improve through our teams' innovation and consistent performance from our assets. At the same time, our teams are constantly seeking strategic opportunities to cost-effectively grow our assets. We recently closed on a bolt-on acquisition in SCOOP that added 19,500 net acres and up to 185 high quality, oil-weighted operated wells to our inventory," said Jack Stark, President and Chief Operating Officer.

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

3Q 3Q YTD YTD Boe per day 2020 2019 2020 2019 Bakken 160,661 191,268 150,366 194,872 South 129,583 133,266 129,559 128,826 All other 6,757 7,781 6,997 8,291 Total 297,001 332,315 286,922 331,989



Financial Update

"Continental has consistently demonstrated low cost leadership and despite the market volatility we have faced this year, 2020 will be no exception. Thanks to our unique combination of assets and operational efficiencies, Continental will deliver positive free cash flow for the fifth consecutive year alongside improved guidance for LOE per Boe and cash G&A per Boe," said John Hart, Chief Financial Officer.





Three Months Nine Months Ended Ended

3Q20 Financial Update September 30, September 30, 2020 2020

Cash and Cash Equivalents $21.2 million Total Debt $5.63 billion Net Debt (non-GAAP)(1) $5.61 billion Average Net Sales Price (non-GAAP)(1) Per Barrel of Oil $35.93 $33.71 Per Mcf of Gas $0.98 $0.72 Per Boe $23.23 $20.21 Production Expense per Boe $3.19 $3.45 Total G&A Expenses per Boe $1.63 $1.65 Crude Oil Differential per Barrel ($5.00) ($6.03) Natural Gas Differential per Mcf ($1.05) ($1.19) Non-Acquisition Capital Expenditures $149.4 million $990.9 million Exploration & Development Drilling & $120.9 million $820.7 millionCompletion

Leasehold $5.5 million $31.0 million Minerals, of which 80% was Recouped from $0.6 million $23.9 millionFNV

Workovers, Recompletions and Other $22.4 million $115.3 million





(1) Net debt and net sales prices represent non-GAAP financial measures.Further information about these non-GAAP financial measures as well asreconciliations to the most directly comparable U.S. GAAP financial measuresare provided subsequently under the header Non-GAAP Financial Measures.



Preliminary 2021 Outlook

"As a continuation of Continental's historic track record of sustainable cash flow and debt reduction, we are projecting a 65% to 75% cash flow from operations reinvestment rate for 2021, with free cash flow projections of approximately $400 million at $40 WTI and $650 million at $45 WTI. Additionally, Continental is prioritizing debt paydown and expects to significantly reduce total debt to $5 billion or below by year end 2021, and down to $4 billion or below by year end 2022 or 2023," said Bill Berry, Chief Executive Officer.

In anticipation of stronger gas fundamentals in 2021, the Company shifted Oklahoma rigs to gassier areas in the second quarter 2020. To date, approximately 202 MMcfpd of the Company's 2021 natural gas is hedged, with two-thirds of the hedges representing collars with a weighted average floor price of $2.67 and a weighted average ceiling price of $3.44. The Company expects to continue an active and ongoing hedging program in 2021 and 2022. In Oklahoma, condensate wells are delivering strong early time results, with 20 recently completed SCOOP condensate wells performing in line with or better than expectations and are expected to deliver over 50% rates of return at $3.00 Henry Hub. With oil and gas inventory depth and direct access to multiple premium oil and gas markets in Oklahoma, the Company has the flexibility to capitalize on both oil and gas commodity prices.

The Company is projecting a 65% to 75% cash flow from operations (CFFO) reinvestment rate for 2021. At the midpoint of projected 2021 Capex, the Company is projecting annual cash flow from operations of $1.6 billion and annual free cash flow (FCF) of approximately $400 million at $40 WTI. The Company is projecting annual cash flow from operations of $1.85 billion and annual FCF of approximately $650 million at $45 WTI. The Company is projecting approximately 8.0% to 14.0% free cash flow yield at $40 to $45 WTI. Free cash flow yield is estimated by dividing the 2021 annual FCF estimate range by the Company's current market capitalization, as of November 5, 2020. Additionally, the Company is projecting total debt below $5.0 billion at year-end 2021 and $4.0 billion or below by year-end 2022 and 2023.

In 2021, the Company is projecting $1.2 to $1.3 billion of Capex at $40 to $45 WTI and $3 Henry Hub. The Company is projecting a low single digit production growth year-over-year in 2021 and expects a cash flow breakeven price of $32 WTI in 2021.

The Company will provide its full 2021 guidance, capital expenditures budget and operating details during its historical timeframe of early next year. The Company's full 2020 guidance, capital expenditures budget and operating details can be found at the conclusion of this press release.

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 Nine months ended September 30, September 30,

2020 2019 2020 2019 Average daily production: Crude oil (Bbl per day) 169,265 198,074 155,088 195,209 Natural gas (Mcf per day) 766,416 805,446 791,005 820,679 Crude oil equivalents (Boe per 297,001 332,315 286,922 331,989day)

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

$ $ $ $ Crude oil ($/Bbl) 33.71 51.99 35.93 51.28

$ $ $ $ Natural gas ($/Mcf) 0.72 1.78 0.98 1.12

$ $ $ $ Crude oil equivalents ($/Boe) 20.21 34.95 23.23 33.30

$ $ $ $ Production expenses ($/Boe) 3.45 3.68 3.19 3.73

Production taxes (% of net crude 7.8% 8.5% 8.3% 8.4%oil and gas sales)

$ $ $ $ DD&A ($/Boe) 16.37 16.18 16.58 15.81

Total general and administrative $ $ $ $ expenses ($/Boe) (2) 1.65 1.57 1.63 1.54

Net income (loss) attributable to $ $ $ $ Continental Resources (in 158,162 (504,372) 581,695thousands) (79,422)

Diluted net income (loss) per $ $ $ $ share attributable to Continental (1.39) 1.56Resources (0.22) 0.43

Adjusted net income (loss) $ $ $ $ (non-GAAP) (in thousands) (1) 199,389 (342,139) 635,135 (58,871)

Adjusted diluted net income $ $ $ $ (loss) per share (non-GAAP) (1) (0.95) 1.70 (0.16) 0.54

Net cash provided by operating $ $ $ $ activities (in thousands) 291,197 806,972 934,767 2,311,876

EBITDAX (non-GAAP) (in thousands) $ $ $ $ (1) 473,311 828,704 1,103,571 2,541,508



(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 andadministrative expense and non-cash equity compensation expense. Cash generaland administrative expense per Boe was $1.04, $1.12, $1.04, and $1.16 for 3Q 2020, 3Q 2019, YTD 2020, and YTD 2019, respectively. Non-cash equity compensation expense per Boe was $0.59, $0.42, $0.61, and $0.41 for 3Q 2020, 3Q 2019, YTD 2020, and YTD 2019, respectively.

Third Quarter Earnings Conference Call

The Company plans to host a conference call to discuss third quarter 2020 results on Friday, November 6, 2020 at 10:00 a.m. ET (9:00 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: 10:00 a.m. ET, Friday, November 6, 2020

Dial-in: 1-888-317-6003

Intl. dial-in: 1-412-317-6061

Conference ID: 8013830

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: 10147993

The Company plans to publish a third quarter 2020 summary presentation to its website at www.CLR.com prior to the start of its conference call on Friday, November 6, 2020.

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 2020, the Company will celebrate 53 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 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, 2019, Quarterly Reports on Form 10-Q for the quarters ended March 31, 2020 and June 30, 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 remain subject to change as more well data is analyzed.

Investor Contact: Media Contact:

Rory Sabino Kristin Thomas

Vice President, Investor Senior Vice President, Public Relations Relations

405-234-9620 405-234-9480

Rory.Sabino@CLR.com Kristin.Thomas@CLR.com



Lucy Guttenberger

Investor Relations Analyst

405-774-5878

Lucy.Guttenberger@CLR.com









Continental Resources, Inc. and Subsidiaries

Unaudited Condensed Consolidated Statements of Income (Loss)

Three months ended Nine months ended September 30, September 30,

2020 2019 2020 2019 Revenues: In thousands, except per share data

Crude oil and natural gas $ $ $ $ sales 701,468 1,081,400 1,738,863 3,328,409

Gain (loss) on derivative (17,853) 1,195 (25,635) 53,519instruments, net

Crude oil and natural gas 8,755 21,602 35,602 54,886service operations

Total revenues 692,370 1,104,197 1,748,830 3,436,814

Operating costs andexpenses:

Production expenses 88,701 114,050 271,852 333,446 Production taxes 50,153 86,931 132,444 267,237 Transportation expenses 55,272 62,038 148,079 164,569 Exploration expenses 1,041 2,472 14,638 7,399 Crude oil and natural gas 3,316 8,224 15,288 26,616service operations

Depreciation, depletion, 461,191 484,031 1,288,185 1,464,672amortization and accretion

Property impairments 18,518 20,199 264,976 66,854 General and administrative 45,273 46,993 129,713 141,837expenses

Net (gain) loss on sale of 800 535 5,914 647assets and other

Total operating costs and 724,265 825,473 2,271,089 2,473,277expenses

Income (loss) from (31,895) 278,724 (522,259) 963,537operations

Other income (expense): Interest expense (63,884) (68,090) (192,547) (204,398) Gain (loss) on - (4,584) 64,573 (4,584)extinguishment of debt

Other 224 1,119 1,385 3,196 (63,660) (71,555) (126,589) (205,786) Income (loss) before income (95,555) 207,169 (648,848) 757,751taxes

(Provision) benefit for 13,972 (49,747) 138,350 (177,386)income taxes

Net income (loss) (81,583) 157,422 (510,498) 580,365 Net loss attributable to (2,161) (740) (6,126) (1,330)noncontrolling interests

Net income (loss) $ $ $ $ attributable to Continental (79,422) 158,162 (504,372) 581,695Resources

Net income (loss) per shareattributable to Continental Resources:

$ $ $ $ Basic 0.43 1.56 (0.22) (1.39)

$ $ $ $ Diluted 0.43 1.56 (0.22) (1.39)









Continental Resources, Inc. and Subsidiaries

Unaudited Condensed Consolidated Balance Sheets

In thousands September 30, 2020 December 31, 2019 Assets Cash and cash equivalents $ $ 21,237 39,400

Other current assets 678,525 1,167,615 Net property and equipment (1) 14,004,414 14,497,726 Other noncurrent assets 24,048 23,166 Total assets $ $ 14,728,224 15,727,907

Liabilities and equity Current liabilities $ $ 748,060 1,336,026

Long-term debt, net of current 5,629,133 5,324,079portion

Other noncurrent liabilities 1,846,917 1,959,451 Equity attributable to Continental 6,132,684 6,741,667Resources

Equity attributable to 371,430 366,684noncontrolling interests

Total liabilities and equity $ $ 14,728,224 15,727,907





(1) Balance is net of accumulated depreciation, depletion and amortizationof $14.21 billion and $12.77 billion as of September 30, 2020 and December 31,2019, respectively.







Continental Resources, Inc. and Subsidiaries

Unaudited Condensed Consolidated Statements of Cash Flows

Three months ended Nine months ended September 30, September 30,

In thousands 2020 2019 2020 2019 Net income (loss) $ $ $ $ (81,583) 157,422 (510,498) 580,365

Adjustments to reconcilenet income (loss) to net

cash provided by operating activities:

Non-cash expenses 489,905 603,397 1,427,992 1,759,213 Changes in assets and (117,125) 46,153 17,273 (27,702)liabilities

Net cash provided by 291,197 806,972 934,767 2,311,876operating activities

Net cash used in (162,923) (696,182) (1,181,866) (2,253,927)investing activities

Net cash provided by(used in) financing (113,693) (282,002) 228,936 (305,458)activities

Effect of exchange rate - (10) - 20changes on cash

Net change in cash and 14,581 (171,222) (18,163) (247,489)cash equivalents

Cash and cash equivalents 6,656 206,482 39,400 282,749at beginning of period

Cash and cash equivalents $ $ $ $ at end of period 21,237 21,237 35,260 35,260







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.





Three months ended September 30, 2020 2019 In thousands, except per share data $ Diluted $ Diluted EPS EPS

Net income (loss) attributable to $ $ $ $ Continental Resources (GAAP) (79,422) (0.22) 158,162 0.43

Adjustments: Non-cash loss on 7,901 29,289derivatives

Property 18,518 20,199impairments

Net loss on sale of 800 535assets and other

Loss on extinguishment of - 4,584debt

Total tax effect of (6,668) (13,380)adjustments (1)

Totaladjustments, net 20,551 0.06 41,227 0.11of tax

Adjusted net income $ ($0.16) $ $ (loss) (non-GAAP) (58,871) 199,389 0.54

Weighted average diluted 360,257 370,676shares outstanding

Adjusted diluted net income (loss) $ $ per share (non-GAAP) (0.16) 0.54

Nine months ended September 30, 2020 2019 In thousands, except per share data $ Diluted $ Diluted EPS EPS

Net income (loss) attributable to $ $ $ $ Continental Resources (GAAP) (504,372) (1.39) 581,695 1.56

Adjustments: Non-cash (gain) loss on 8,560 (1,303)derivatives

Property 264,976 66,854impairments

Net loss on sale of 5,914 647assets and other

(Gain) loss on (64,573) 4,584extinguishment of debt

Total tax effect of (52,644) (17,342)adjustments (1)

Totaladjustments, net 162,233 0.44 53,440 0.14of tax

Adjusted net income $ ($0.95) $ $ (loss) (non-GAAP) (342,139) 635,135 1.70

Weighted average diluted 361,948 373,506shares outstanding

Adjusted diluted net income (loss) $ $ per share (non-GAAP) (0.95) 1.70







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





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 September 30, 2020, the Company's total debt was $5.63 billion and its net debt amounted to $5.61 billion, representing total debt of $5.63 billion less cash and cash equivalents of $21.2 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.

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

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





Three months ended Nine months ended September 30, September 30,

In thousands 2020 2019 2020 2019 Net income (loss) $ $ $ $ (81,583) 157,422 (510,498) 580,365

Interest expense 63,884 68,090 192,547 204,398 Provision (benefit) for (13,972) 49,747 (138,350) 177,386income taxes

Depreciation, depletion, 461,191 484,031 1,288,185 1,464,672amortization and accretion

Property impairments 18,518 20,199 264,976 66,854 Exploration expenses 1,041 2,472 14,638 7,399 Impact from derivativeinstruments:

Total (gain) loss on 17,853 (1,195) 25,635 (53,519)derivatives, net

Total cash (paid) received (9,952) 30,484 (17,075) 52,216on derivatives, net

Non-cash (gain) loss on 7,901 29,289 8,560 (1,303)derivatives, net

Non-cash equity compensation 16,331 12,870 48,086 37,153 Gain (loss) on - 4,584 (64,573) 4,584extinguishment of debt

EBITDAX (non-GAAP) $ $ $ $ 473,311 828,704 1,103,571 2,541,508









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







Three months ended Nine months ended September 30, September 30,

In thousands 2020 2019 2020 2019 Net cash provided by $ $ $ $ operating activities 291,197 806,972 934,767 2,311,876

Current income tax - - (2,223) -provision (benefit)

Interest expense 63,884 68,090 192,547 204,398 Exploration expenses, 901 2,472 8,182 7,399excluding dry hole costs

Gain (loss) on sale of (800) (535) (5,914) (647)assets and other, net

Other, net 1,004 (2,142) (6,515) (9,220) Changes in assets and 117,125 (46,153) (17,273) 27,702liabilities

EBITDAX (non-GAAP) $ $ $ $ 473,311 828,704 1,103,571 2,541,508







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 three months ended September 30, 2020.





In thousands 3Q 2020 Net cash provided by operating activities (GAAP) $ 291,197 Exclude: Changes in working capital items 117,125 Less: Capital expenditures (1) (149,371) Plus: Contributions from noncontrolling interest 516 Less: Distributions to noncontrolling interest (1,171) Free cash flow (non-GAAP) $ 258,296

(1) Capital expenditures are calculated as follows: In thousands 3Q 2020 Cash paid for capital expenditures $ 163,092 Less: Total acquisitions (4,092) Plus: Change in accrued capital expenditures & other (9,629)

Plus: Exploratory seismic costs - Capital expenditures $ 149,371







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 September 30, Three months ended September 30, 2020 2019

In thousands Crude oil Natural Total Crude oil Natural Total gas gas

Crude oil andnatural gas $623,955 $77,513 $701,468 $989,297 $92,103 $1,081,400sales (GAAP)

Less:Transportation (46,890) (8,382) (55,272) (53,038) (9,000) (62,038)expenses

Net crude oiland natural $577,065 $69,131 $646,196 $936,259 $83,103 $1,019,362gas sales (non-GAAP)

Sales volumes(MBbl/MMcf/ 16,063 70,510 27,815 18,258 74,101 30,608MBoe)

Net salesprice $35.93 $0.98 $23.23 $51.28 $1.12 $33.30(non-GAAP)





Nine months ended September 30, Nine months ended September 30, 2020 2019

In thousands Crude oil Natural Total Crude oil Natural Total gas gas

Crude oil andnatural gas $1,556,445 $182,418 $1,738,863 $2,905,561 $422,848 $3,328,409sales (GAAP)

Less:Transportation (120,780) (27,299) (148,079) (140,666) (23,903) (164,569)expenses

Net crude oiland natural $1,435,665 $155,119 $1,590,784 $2,764,895 $398,945 $3,163,840gas sales (non-GAAP)

Sales volumes(MBbl/MMcf/ 42,583 216,735 78,706 53,179 224,045 90,520MBoe)

Net salesprice $33.71 $0.72 $20.21 $51.99 $1.78 $34.95(non-GAAP)





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 Nine months ended September 30, September 30,

2020 2019 2020 2019 Total G&A per Boe $ $ $ $ (GAAP) 1.63 1.54 1.65 1.57

Less: Non-cash equity (0.59) (0.42) (0.61) (0.41)compensation per Boe

Cash G&A per Boe $ $ $ $ (non-GAAP) 1.04 1.12 1.04 1.16





Continental Resources, Inc. 2020 Guidance As of November 5, 2020

2020 Full-year average oil production (Bopd) 155,000 to 165,000 Full-year average natural gas production 800,000 to 820,000 (Mcfpd)

Capital expenditures budget $1.2 billion

Operating Expenses: Updated: $3.50 to $3.75 Production expense per Boe Previous: $3.50 to $4.00 Production tax (% of net oil & gas 8.3% to $8.5% revenue)

Updated: $1.10 to $1.30 Cash G&A expense per Boe(1) Previous: $1.10 to $1.40 Non-cash equity compensation per Boe $0.50 to $0.60 DD&A per Boe $15.00 to $17.00

Average Price Differentials: NYMEX WTI crude oil(2) (per barrel of ($5.50) to ($6.50) oil)

Henry Hub natural gas(3) (per Mcf) ($0.75) to ($1.25)







Cash G&A is a non-GAAP measure and excludes the range of values shown for1. 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 $1.60 to $1.90 per Boe.

2. Includes second half 2020 guidance of ($5.00) to ($5.50).

3. Includes natural gas liquids production in differential range. Includes second half 2020 guidance of ($0.50) to ($1.00).





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SOURCE Continental Resources