Continental Resources Inc (CLR) 8-K 3Q20 Results and Full-Year 2020 Expectations

Exhibit 99.1

NEWS RELEASE

CONTINENTAL RESOURCES ANNOUNCES THIRD QUARTER 2020 RESULTS;

PRELIMINARY 2021 OUTLOOK

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)

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

• 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

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

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

• 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

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

• 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

• 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

• 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

• 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

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

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

Oklahoma City, November 5, 2020 – 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.

2

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

Boe per day	3Q 2020		3Q 2019		YTD 2020		YTD 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.

3Q20 Financial Update	Three Months Ended September 30, 2020			Nine Months Ended September 30, 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 & Completion	$	120.9 million		$	820.7 million
Leasehold	$	5.5 million		$	31.0 million
Minerals, of which 80% was Recouped from FNV	$	0.6 million		$	23.9 million
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 as reconciliations to the most directly comparable U.S. GAAP financial measures are 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.

3

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.

4

	Three months ended September 30,						Nine months ended 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 day)		297,001			332,315			286,922			331,989
Average net sales prices (non-GAAP), excluding effect from derivatives: (1)
Crude oil ($/Bbl)	$	35.93		$	51.28		$	33.71		$	51.99
Natural gas ($/Mcf)	$	0.98		$	1.12		$	0.72		$	1.78
Crude oil equivalents ($/Boe)	$	23.23		$	33.30		$	20.21		$	34.95
Production expenses ($/Boe)	$	3.19		$	3.73		$	3.45		$	3.68
Production taxes (% of net crude oil and gas sales)		7.8	%		8.5	%		8.3	%		8.4	%
DD&A ($/Boe)	$	16.58		$	15.81		$	16.37		$	16.18
Total general and administrative expenses ($/Boe) (2)	$	1.63		$	1.54		$	1.65		$	1.57
Net income (loss) attributable to Continental Resources (in thousands)	$	(79,422	)	$	158,162		$	(504,372	)	$	581,695
Diluted net income (loss) per share attributable to Continental Resources	$	(0.22	)	$	0.43		$	(1.39	)	$	1.56
Adjusted net income (loss) (non-GAAP) (in thousands) (1)	$	(58,871	)	$	199,389		$	(342,139	)	$	635,135
Adjusted diluted net income (loss) per share (non-GAAP) (1)	$	(0.16	)	$	0.54		$	(0.95	)	$	1.70
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 and administrative expense and non-cash equity compensation expense. Cash general and 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.

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 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

6

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 Relations	Senior Vice President, Public 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

7

Continental Resources, Inc. and Subsidiaries

Unaudited Condensed Consolidated Statements of Income (Loss)

	Three months ended September 30,						Nine months ended September 30,
	2020			2019			2020			2019
	In thousands, except per share data
Revenues:
Crude oil and natural gas sales	$	701,468		$	1,081,400		$	1,738,863		$	3,328,409
Gain (loss) on derivative instruments, net		(17,853	)		1,195			(25,635	)		53,519
Crude oil and natural gas service operations		8,755			21,602			35,602			54,886
Total revenues		692,370			1,104,197			1,748,830			3,436,814
Operating costs and expenses:
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 service operations		3,316			8,224			15,288			26,616
Depreciation, depletion, amortization and accretion		461,191			484,031			1,288,185			1,464,672
Property impairments		18,518			20,199			264,976			66,854
General and administrative expenses		45,273			46,993			129,713			141,837
Net (gain) loss on sale of assets and other		800			535			5,914			647
Total operating costs and expenses		724,265			825,473			2,271,089			2,473,277
Income (loss) from operations		(31,895	)		278,724			(522,259	)		963,537
Other income (expense):
Interest expense		(63,884	)		(68,090	)		(192,547	)		(204,398	)
Gain (loss) on extinguishment of debt		—			(4,584	)		64,573			(4,584	)
Other		224			1,119			1,385			3,196
		(63,660	)		(71,555	)		(126,589	)		(205,786	)
Income (loss) before income taxes		(95,555	)		207,169			(648,848	)		757,751
(Provision) benefit for income taxes		13,972			(49,747	)		138,350			(177,386	)
Net income (loss)		(81,583	)		157,422			(510,498	)		580,365
Net loss attributable to noncontrolling interests		(2,161	)		(740	)		(6,126	)		(1,330	)
Net income (loss) attributable to Continental Resources	$	(79,422	)	$	158,162		$	(504,372	)	$	581,695
Net income (loss) per share attributable to Continental Resources:
Basic	$	(0.22	)	$	0.43		$	(1.39	)	$	1.56
Diluted	$	(0.22	)	$	0.43		$	(1.39	)	$	1.56

8

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 portion		5,629,133		5,324,079
Other noncurrent liabilities		1,846,917		1,959,451
Equity attributable to Continental Resources		6,132,684		6,741,667
Equity attributable to noncontrolling interests		371,430		366,684
Total liabilities and equity	$	14,728,224	$	15,727,907

(1) Balance is net of accumulated depreciation, depletion and amortization of $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 September 30,						Nine months ended September 30,
In thousands	2020			2019			2020			2019
Net income (loss)	$	(81,583	)	$	157,422		$	(510,498	)	$	580,365
Adjustments to reconcile net 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 liabilities		(117,125	)		46,153			17,273			(27,702	)
Net cash provided by operating activities		291,197			806,972			934,767			2,311,876
Net cash used in investing activities		(162,923	)		(696,182	)		(1,181,866	)		(2,253,927	)
Net cash provided by (used in) financing activities		(113,693	)		(282,002	)		228,936			(305,458	)
Effect of exchange rate changes on cash		—			(10	)		—			20
Net change in cash and cash equivalents		14,581			(171,222	)		(18,163	)		(247,489	)
Cash and cash equivalents at beginning of period		6,656			206,482			39,400			282,749
Cash and cash equivalents at end of period	$	21,237		$	35,260		$	21,237		$	35,260

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 September 30,
	2020						2019
In thousands, except per share data	$			Diluted EPS			$			Diluted EPS
Net income (loss) attributable to Continental Resources (GAAP)	$	(79,422	)	$	(0.22	)	$	158,162		$	0.43
Adjustments:
Non-cash loss on derivatives		7,901						29,289
Property impairments		18,518						20,199
Net loss on sale of assets and other		800						535
Loss on extinguishment of debt		—						4,584
Total tax effect of adjustments (1)		(6,668	)					(13,380	)
Total adjustments, net of tax		20,551			0.06			41,227			0.11
Adjusted net income (loss) (non-GAAP)	$	(58,871	)	$	(0.16	)	$	199,389		$	0.54
Weighted average diluted shares outstanding		360,257						370,676
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 EPS			$			Diluted EPS
Net income (loss) attributable to Continental Resources (GAAP)	$	(504,372	)	$	(1.39	)	$	581,695		$	1.56
Adjustments:
Non-cash (gain) loss on derivatives		8,560						(1,303	)
Property impairments		264,976						66,854
Net loss on sale of assets and other		5,914						647
(Gain) loss on extinguishment of debt		(64,573	)					4,584
Total tax effect of adjustments (1)		(52,644	)					(17,342	)
Total adjustments, net of tax		162,233			0.44			53,440			0.14
Adjusted net income (loss) (non-GAAP)	$	(342,139	)	$	(0.95	)	$	635,135		$	1.70
Weighted average diluted shares outstanding		361,948						373,506
Adjusted diluted net income (loss) per share (non-GAAP)	$	(0.95	)				$	1.70

(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 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.

12

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

	Three months ended September 30,						Nine months ended September 30,
In thousands	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 income taxes		(13,972	)		49,747			(138,350	)		177,386
Depreciation, depletion, amortization and accretion		461,191			484,031			1,288,185			1,464,672
Property impairments		18,518			20,199			264,976			66,854
Exploration expenses		1,041			2,472			14,638			7,399
Impact from derivative instruments:
Total (gain) loss on derivatives, net		17,853			(1,195	)		25,635			(53,519	)
Total cash (paid) received on derivatives, net		(9,952	)		30,484			(17,075	)		52,216
Non-cash (gain) loss on derivatives, net		7,901			29,289			8,560			(1,303	)
Non-cash equity compensation		16,331			12,870			48,086			37,153
(Gain) loss on extinguishment of debt		—			4,584			(64,573	)		4,584
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 September 30,						Nine months ended 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 provision (benefit)		—			—			(2,223	)		—
Interest expense		63,884			68,090			192,547			204,398
Exploration expenses, excluding dry hole costs		901			2,472			8,182			7,399
Gain (loss) on sale of assets and other, net		(800	)		(535	)		(5,914	)		(647	)
Other, net		1,004			(2,142	)		(6,515	)		(9,220	)
Changes in assets and liabilities		117,125			(46,153	)		(17,273	)		27,702
EBITDAX (non-GAAP)	$	473,311		$	828,704		$	1,103,571		$	2,541,508

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 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 interests		516
Less: Distributions to noncontrolling interests		(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

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 September 30, 2020									Three months ended September 30, 2019
In thousands	Crude oil			Natural gas			Total			Crude oil			Natural gas			Total
Crude oil and natural gas sales (GAAP)	$	623,955		$	77,513		$	701,468		$	989,297		$	92,103		$	1,081,400
Less: Transportation expenses		(46,890	)		(8,382	)		(55,272	)		(53,038	)		(9,000	)		(62,038	)
Net crude oil and natural gas sales (non-GAAP)	$	577,065		$	69,131		$	646,196		$	936,259		$	83,103		$	1,019,362
Sales volumes (MBbl/MMcf/MBoe)		16,063			70,510			27,815			18,258			74,101			30,608
Net sales price (non-GAAP)	$	35.93		$	0.98		$	23.23		$	51.28		$	1.12		$	33.30
	Nine months ended September 30, 2020									Nine months ended September 30, 2019
In thousands	Crude oil			Natural gas			Total			Crude oil			Natural gas			Total
Crude oil and natural gas sales (GAAP)	$	1,556,445		$	182,418		$	1,738,863		$	2,905,561		$	422,848		$	3,328,409
Less: Transportation expenses		(120,780	)		(27,299	)		(148,079	)		(140,666	)		(23,903	)		(164,569	)
Net crude oil and natural gas sales (non-GAAP)	$	1,435,665		$	155,119		$	1,590,784		$	2,764,895		$	398,945		$	3,163,840
Sales volumes (MBbl/MMcf/MBoe)		42,583			216,735			78,706			53,179			224,045			90,520
Net sales price (non-GAAP)	$	33.71		$	0.72		$	20.21		$	51.99		$	1.78		$	34.95

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 September 30,						Nine months ended September 30,
	2020			2019			2020			2019
Total G&A per Boe (GAAP)	$	1.63		$	1.54		$	1.65		$	1.57
Less: Non-cash equity compensation per Boe		(0.59	)		(0.42	)		(0.61	)		(0.41	)
Cash G&A per Boe (non-GAAP)	$	1.04		$	1.12		$	1.04		$	1.16

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 (Mcfpd)	800,000 to 820,000
Capital expenditures budget	$1.2 billion
Operating Expenses:
Production expense per Boe	Updated: $3.50 to $3.75 Previous: $3.50 to $4.00
Production tax (% of net oil & gas revenue)	8.3% to $8.5%
Cash G&A expense per Boe(1)	Updated: $1.10 to $1.30 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 oil)	($5.50) to ($6.50)
Henry Hub natural gas(3) (per Mcf)	($0.75) to ($1.25)

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 $1.60 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).

17