CONTINENTAL RESOURCES, INC - Quarter Report: 2022 June (Form 10-Q)

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

________________________________________

FORM 10-Q

________________________________________

(Mark One)


☒			QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the quarterly period ended June 30, 2022


☐			TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the transition period from to

Commission File Number: 001-32886

____________________________________

CONTINENTAL RESOURCES, INC

(Exact name of registrant as specified in its charter)

____________________________________

Oklahoma

73-0767549

(State or other jurisdiction of incorporation or organization)

(I.R.S. Employer Identification No.)

20 N. Broadway,

Oklahoma City,

Oklahoma

73102

(Address of principal executive offices)

(Zip Code)

(405) 234-9000

(Registrant’s telephone number, including area code)

Not Applicable

(Former name, former address and former fiscal year, if changed since last report)

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


Title of each class	Trading symbol(s)	Name of each exchange on which registered
Common Stock, $0.01 par value	CLR	New York Stock Exchange

____________________________________

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes x No ¨

Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit such files). Yes x No ¨

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting company, or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company,” and “emerging growth company” in Rule 12b-2 of the Exchange Act.

Large accelerated filer

Accelerated filer

☐

Non-accelerated filer

☐

Smaller reporting company

☐

Emerging growth company

☐

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

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes ☐ No x

363,001,012 shares of our $0.01 par value common stock were outstanding on July 22, 2022.

Table of Contents



PART I. Financial Information
Item 1.	Financial Statements	1
	Condensed Consolidated Balance Sheets	1
	Unaudited Condensed Consolidated Statements of Operations	2
	Unaudited Condensed Consolidated Statements of Equity	3
	Unaudited Condensed Consolidated Statements of Cash Flows	5
	Notes to Unaudited Condensed Consolidated Financial Statements	6
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	21
Item 3.	Quantitative and Qualitative Disclosures About Market Risk	35
Item 4.	Controls and Procedures	36

PART II. Other Information
Item 1.	Legal Proceedings	37
Item 1A.	Risk Factors	37
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	38
Item 3.	Defaults Upon Senior Securities	38
Item 4.	Mine Safety Disclosures	38
Item 5.	Other Information	38
Item 6.	Exhibits	39
	Signature	40

When we refer to “us,” “we,” “our,” “Company,” or “Continental” we are describing Continental Resources, Inc. and our subsidiaries.

Glossary of Crude Oil and Natural Gas Terms

The terms defined in this section may be used throughout this report:

“Bbl” One stock tank barrel, of 42 U.S. gallons liquid volume, used herein in reference to crude oil, condensate or natural gas liquids.

“Boe” Barrels of crude oil equivalent, with six thousand cubic feet of natural gas being equivalent to one barrel of crude oil based on the average equivalent energy content of the two commodities.

“Btu” British thermal unit, which represents the amount of energy needed to heat one pound of water by one degree Fahrenheit and can be used to describe the energy content of fuels.

“completion” The process of treating a drilled well followed by the installation of permanent equipment for the production of crude oil and/or natural gas.

“developed acreage” The number of acres allocated or assignable to productive wells or wells capable of production.

“development well” A well drilled within the proved area of a crude oil or natural gas reservoir to the depth of a stratigraphic horizon known to be productive.

“dry hole” Exploratory or development well that does not produce crude oil and/or natural gas in economically producible quantities.

“exploratory well” A well drilled to find crude oil or natural gas in an unproved area, to find a new reservoir in an existing field previously found to be productive of crude oil or natural gas in another reservoir, or to extend a known reservoir beyond the proved area.

“field” An area consisting of a single reservoir or multiple reservoirs all grouped on, or related to, the same individual geological structural feature or stratigraphic condition. The field name refers to the surface area, although it may refer to both the surface and the underground productive formations.

“formation” A layer of rock which has distinct characteristics that differs from nearby rock.

"gross acres" or "gross wells" Refers to the total acres or wells in which a working interest is owned.

“MBbl” One thousand barrels of crude oil, condensate or natural gas liquids.

“MBoe” One thousand Boe.

“Mcf” One thousand cubic feet of natural gas.

“MMBoe” One million Boe.

“MMBtu” One million British thermal units.

“MMcf” One million cubic feet of natural gas.

“net acres” or "net wells" Refers to the sum of the fractional working interests owned in gross acres or gross wells.

"Net crude oil, natural gas, and natural gas liquids sales" Represents total crude oil, natural gas, and natural gas liquids sales less total transportation expenses. Net crude oil, natural gas, and natural gas liquids sales presented herein are non-GAAP measures. See Part I, Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations—Non-GAAP Financial Measures for a discussion and calculation of this measure.

"Net sales price" Represents the average net wellhead sales price received by the Company for its sales after deducting transportation expenses. Net sales price is calculated by taking revenues less transportation expenses divided by sales volumes for a period. Net sales prices presented herein are non-GAAP measures. See Part I, Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations—Non-GAAP Financial Measures for a discussion and calculation of this measure.

“NGL” or "NGLs" Refers to natural gas liquids, which are hydrocarbon products that are separated during natural gas processing and include ethane, propane, isobutane, normal butane, and natural gasoline.

“NYMEX” The New York Mercantile Exchange.

“play” A portion of the exploration and production cycle following the identification by geologists and geophysicists of areas with potential crude oil and natural gas reserves.

“proved reserves” The quantities of crude oil and natural gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible from a given date forward, from known reservoirs and under existing economic conditions, operating methods, and government regulations prior to the time at which contracts providing the right to operate expire, unless evidence indicates renewal is reasonably certain.

“reservoir” A porous and permeable underground formation containing a natural accumulation of producible crude oil and/or natural gas that is confined by impermeable rock or water barriers and is separate from other reservoirs.

“royalty interest” Refers to the ownership of a percentage of the resources or revenues produced from a crude oil or natural gas property. A royalty interest owner does not bear exploration, development, or operating expenses associated with drilling and producing a crude oil or natural gas property.

“SCOOP” Refers to the South Central Oklahoma Oil Province, a term used to describe properties located in the Anadarko Basin of Oklahoma in which we operate. Our SCOOP acreage extends across portions of Garvin, Grady, Stephens, Carter, McClain and Love counties of Oklahoma and has the potential to contain hydrocarbons from a variety of conventional and unconventional reservoirs overlying and underlying the Woodford formation.

"STACK" Refers to Sooner Trend Anadarko Canadian Kingfisher, a term used to describe a resource play located in the Anadarko Basin of Oklahoma characterized by stacked geologic formations with major targets in the Meramec, Osage and Woodford formations.

“undeveloped acreage” Lease acreage on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of crude oil and/or natural gas.

“unit” The joining of all or substantially all interests in a reservoir or field, rather than a single tract, to provide for development and operation without regard to separate property interests. Also, the area covered by a unitization agreement.

“working interest” The right granted to the lessee of a property to explore for and to produce and own crude oil, natural gas, or other minerals. The working interest owners bear the exploration, development, and operating costs on either a cash, penalty, or carried basis.

Cautionary Statement for the Purpose of the “Safe Harbor” Provisions of the Private Securities Litigation Reform Act of 1995

This report and information incorporated by reference in this report include “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 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, included in this report are forward-looking statements. 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 may include, but are not limited to, statements about:

•the outcome of negotiations and any definitive agreement entered into with respect to the recent non-binding take-private proposal received from the Hamm Family described in Note 1. Organization and Nature of Business—Recent Developments and whether any transaction will be consummated in connection therewith;

•our strategy;

•our business and financial plans;

•our future operations;

•our proved reserves and related development plans;

•technology;

•future commodity prices and differentials;

•the timing and amount of future production of crude oil, natural gas liquids, and natural gas and flaring activities;

•the amount, nature and timing of capital expenditures;

•estimated revenues, expenses and results of operations;

•drilling and completing of wells;

•shutting in of production and the resumption of production activities;

•competition;

•marketing of crude oil, natural gas, and natural gas liquids;

•transportation of crude oil, natural gas, and natural gas liquids to markets;

•property exploitation, property acquisitions and dispositions, strategic investments, or joint development opportunities;

•costs of exploiting and developing our properties and conducting other operations, including any impacts from inflation;

•our financial position, dividend payments, bond repurchases, debt reduction plans, share repurchases, or income tax payments;

•geopolitical events and conditions in, or affecting other, crude oil-producing and natural gas-producing nations;

•credit markets;

•our liquidity and access to capital;

•the impact of governmental policies, laws and regulations, as well as regulatory and legal proceedings involving us and of scheduled or potential regulatory or legal changes;

•our future operating and financial results;

•our future commodity or other hedging arrangements; and

•the ability and willingness of current or potential lenders, hedging contract counterparties, customers, and working interest owners to fulfill their obligations to us or to enter into transactions with us in the future on terms that are acceptable to us.

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 or will not change over time. The risks and uncertainties that may affect the operations, performance and results of the business and forward-looking statements include, but are not limited to, those risk factors and other cautionary statements described under Part II, Item 1A. Risk Factors and elsewhere in this report, our Annual Report on Form 10-K for the year ended December 31, 2021, registration statements we file from time to time with the Securities and Exchange Commission, and other announcements we make 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. Additionally, new factors emerge from time to time, and it is not possible for us to predict all such factors. Should one or more of the risks or uncertainties described in this report or our Annual Report on Form 10-K for the year ended December 31, 2021 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.

iii

Except as expressly stated above or 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.

PART I. Financial Information

ITEM 1. Financial Statements

Continental Resources, Inc. and Subsidiaries

Condensed Consolidated Balance Sheets


	June 30, 2022		December 31, 2021
In thousands, except par values and share data	(Unaudited)
Assets
Current assets:
Cash and cash equivalents	$	553,260	$	20,868
Receivables:
Crude oil, natural gas, and natural gas liquids sales	1,848,508		1,122,415
Joint interest and other	336,143		278,753
Allowance for credit losses	(2,856)		(2,814)
Receivables, net	2,181,795		1,398,354
Derivative assets	2,799		22,334
Inventories	175,254		105,568
Prepaid expenses and other	23,918		17,266
Total current assets	2,937,026		1,564,390
Net property and equipment, based on successful efforts method of accounting	17,881,055		16,975,465
Investment in unconsolidated affiliates	65,749		—
Operating lease right-of-use assets	25,819		16,370
Derivative assets, noncurrent	2,116		13,188
Other noncurrent assets	17,307		21,698
Total assets	$	20,929,072	$	18,591,111
Liabilities and equity
Current liabilities:
Accounts payable trade	$	713,417	$	582,317
Revenues and royalties payable	916,034		627,171
Accrued liabilities and other	372,370		285,740
Current portion of income tax liabilities	88,679		—
Derivative liabilities	237,584		899
Current portion of operating lease liabilities	4,095		1,674
Current portion of long-term debt	637,424		2,326
Total current liabilities	2,969,603		1,500,127
Long-term debt, net of current portion	5,662,567		6,826,566
Other noncurrent liabilities:
Deferred income tax liabilities, net	2,381,414		2,139,884
Asset retirement obligations, net of current portion	245,412		215,701
Derivative liabilities, noncurrent	227,167		318
Operating lease liabilities, net of current portion	20,802		13,800
Other noncurrent liabilities	36,283		38,390
Total other noncurrent liabilities	2,911,078		2,408,093
Commitments and contingencies (Note 9)
Equity:
Preferred stock, $0.01 par value; 25,000,000 shares authorized; no shares issued and outstanding	—		—
Common stock, $0.01 par value; 1,000,000,000 shares authorized; 363,002,130 shares issued and outstanding at June 30, 2022; 364,297,520 shares issued and outstanding at December 31, 2021	3,630		3,643
Additional paid-in capital	1,042,891		1,131,602
Retained earnings	7,961,406		6,340,211
Total shareholders’ equity attributable to Continental Resources	9,007,927		7,475,456
Noncontrolling interests	377,897		380,869
Total equity	9,385,824		7,856,325
Total liabilities and equity	$	20,929,072	$	18,591,111

The accompanying notes are an integral part of these condensed consolidated financial statements.

Continental Resources, Inc. and Subsidiaries

Unaudited Condensed Consolidated Statements of Operations


	Three months ended June 30,				Six months ended June 30,
In thousands, except per share data	2022		2021		2022		2021
Revenues:
Crude oil, natural gas, and natural gas liquids sales	$	2,829,173	$	1,282,914	$	5,103,434	$	2,530,447
Loss on derivative instruments, net	(195,744)		(62,178)		(671,682)		(105,685)
Crude oil and natural gas service operations	17,045		14,389		34,960		26,178
Total revenues	2,650,474		1,235,125		4,466,712		2,450,940

Operating costs and expenses:
Production expenses	153,238		96,504		290,518		189,569
Production and ad valorem taxes	204,246		94,293		362,611		178,269
Transportation, gathering, processing, and compression	76,352		52,445		151,201		102,701
Exploration expenses	4,634		2,291		17,651		6,936
Crude oil and natural gas service operations	10,444		5,663		19,005		10,153
Depreciation, depletion, amortization and accretion	446,633		471,858		905,662		981,466
Property impairments	15,826		11,610		40,074		23,046

General and administrative expenses	62,574		55,553		137,411		108,401
Net (gain) loss on sale of assets and other	10		(260)		(155)		(467)
Total operating costs and expenses	973,957		789,957		1,923,978		1,600,074
Income from operations	1,676,517		445,168		2,542,734		850,866
Other income (expense):
Interest expense	(72,236)		(60,951)		(144,791)		(125,902)
Gain (loss) on extinguishment of debt	(403)		(94)		(403)		(290)
Other	1,240		298		13		550
	(71,399)		(60,747)		(145,181)		(125,642)
Income before income taxes	1,605,118		384,421		2,397,553		725,224
Provision for income taxes	(389,271)		(94,947)		(580,355)		(175,475)
Income before equity in net loss of affiliate	1,215,847		289,474		1,817,198		549,749
Equity in net loss of affiliate	(76)		—		(76)		—
Net income	1,215,771		289,474		1,817,122		549,749
Net income attributable to noncontrolling interests	7,024		149		10,618		782
Net income attributable to Continental Resources	$	1,208,747	$	289,325	$	1,806,504	$	548,967

Net income per share attributable to Continental Resources:
Basic	$	3.38	$	0.80	$	5.05	$	1.52
Diluted	$	3.35	$	0.79	$	4.99	$	1.51

The accompanying notes are an integral part of these condensed consolidated financial statements.

Continental Resources, Inc. and Subsidiaries

Unaudited Condensed Consolidated Statements of Equity


Three Months Ended June 30, 2022
	Shareholders’ equity attributable to Continental Resources
In thousands, except share data	Shares outstanding	Common stock		Additional paid-in capital		Treasury stock		Retained earnings		Total shareholders’ equity of Continental Resources		Noncontrolling interests		Total equity













Balance at March 31, 2022	363,126,085	3,631		1,034,977		—		6,854,183		7,892,791		377,652		8,270,443
Net income	—	—		—		—		1,208,747		1,208,747		7,024		1,215,771
Cash dividends declared	—	—		—		—		(101,631)		(101,631)		—		(101,631)
Change in dividends payable	—	—		—		—		107		107		—		107
Stock-based compensation	—	—		14,857		—		—		14,857		—		14,857
Restricted stock:
Granted	135,855	1		—		—		—		1		—		1
Repurchased and canceled	(110,718)	(1)		(6,943)		—		—		(6,944)		—		(6,944)
Forfeited	(149,092)	(1)		—		—		—		(1)		—		(1)
Contributions from noncontrolling interests	—	—		—		—		—		—		2,003		2,003
Distributions to noncontrolling interests	—	—		—		—		—		—		(8,782)		(8,782)
Balance at June 30, 2022	363,002,130	$	3,630	$	1,042,891	$	—	$	7,961,406	$	9,007,927	$	377,897	$	9,385,824



Six Months Ended June 30, 2022
	Shareholders’ equity attributable to Continental Resources
In thousands, except share data	Shares outstanding	Common stock		Additional paid-in capital		Treasury stock		Retained earnings		Total shareholders’ equity of Continental Resources		Noncontrolling interests		Total equity
Balance at December 31, 2021	364,297,520	$	3,643	$	1,131,602	$	—	$	6,340,211	$	7,475,456	$	380,869	$	7,856,325
Net income	—	—		—		—		1,806,504		1,806,504		10,618		1,817,122
Cash dividends declared	—	—		—		—		(185,397)		(185,397)		—		(185,397)
Change in dividends payable	—	—		—		—		88		88		—		88
Common stock repurchased	—	—		—		(99,855)		—		(99,855)		—		(99,855)
Common stock retired	(1,842,422)	(18)		(99,837)		99,855		—		—		—		—
Stock-based compensation	—	—		44,087		—		—		44,087		—		44,087
Restricted stock:
Granted	1,431,883	14		—		—		—		14		—		14
Repurchased and canceled	(591,742)	(6)		(32,961)		—		—		(32,967)		—		(32,967)
Forfeited	(293,109)	(3)		—		—		—		(3)		—		(3)
Contributions from noncontrolling interests	—	—		—		—		—		—		3,806		3,806
Distributions to noncontrolling interests	—	—		—		—		—		—		(17,396)		(17,396)
Balance at June 30, 2022	363,002,130	$	3,630	$	1,042,891	$	—	$	7,961,406	$	9,007,927	$	377,897	$	9,385,824

The accompanying notes are an integral part of these condensed consolidated financial statements.

Continental Resources, Inc. and Subsidiaries

Unaudited Condensed Consolidated Statements of Equity (Continued)


Three Months Ended June 30, 2021
	Shareholders’ equity attributable to Continental Resources
In thousands, except share data	Shares outstanding	Common stock		Additional paid-in capital		Treasury stock		Retained earnings		Total shareholders’ equity of Continental Resources		Noncontrolling interests		Total equity














Balance at March 31, 2021	367,491,013	$	3,675	$	1,213,115	$	—	$	5,107,288	$	6,324,078	$	373,128	$	6,697,206
Net income	—	—		—		—		289,325		289,325		149		289,474
Cash dividends declared	—	—		—		—		(40,429)		(40,429)		—		(40,429)
Change in dividends payable	—	—		—		—		5		5		—		5



Stock-based compensation	—	—		13,618		—		—		13,618		—		13,618
Restricted stock:
Granted	126,780	1		—		—		—		1		—		1
Repurchased and canceled	(16,768)	—		(510)		—		—		(510)		—		(510)
Forfeited	(37,126)	—		—		—		—		—		—		—
Contributions from noncontrolling interests	—	—		—		—		—		—		3,012		3,012
Distributions to noncontrolling interests	—	—		—		—		—		—		(6,703)		(6,703)
Balance at June 30, 2021	367,563,899	$	3,676	$	1,226,223	$	—	$	5,356,189	$	6,586,088	$	369,586	$	6,955,674



Six Months Ended June 30, 2021
	Shareholders’ equity attributable to Continental Resources
In thousands, except share data	Shares outstanding	Common stock		Additional paid-in capital		Treasury stock		Retained earnings		Total shareholders’ equity of Continental Resources		Noncontrolling interests		Total equity
Balance at December 31, 2020	365,220,435	$	3,652	$	1,205,148	$	—	$	4,847,646	$	6,056,446	$	366,279	$	6,422,725
Net income	—	—		—		—		548,967		548,967		782		549,749

Cash dividends declared	—	—		—		—		(40,429)		(40,429)		—		(40,429)
Change in dividends payable	—	—		—		—		5		5		—		5


Stock-based compensation	—	—		30,518		—		—		30,518		—		30,518
Restricted stock:										—
Granted	2,853,222	28		—		—		—		28		—		28
Repurchased and canceled	(407,252)	(3)		(9,443)		—		—		(9,446)		—		(9,446)
Forfeited	(102,506)	(1)		—		—		—		(1)		—		(1)
Contributions from noncontrolling interests	—	—		—		—		—		—		14,475		14,475
Distributions to noncontrolling interests	—	—		—		—		—		—		(11,950)		(11,950)
Balance at June 30, 2021	367,563,899	$	3,676	$	1,226,223	$	—	$	5,356,189	$	6,586,088	$	369,586	$	6,955,674

The accompanying notes are an integral part of these condensed consolidated financial statements.

Continental Resources, Inc. and Subsidiaries

Unaudited Condensed Consolidated Statements of Cash Flows


	Six months ended June 30,
In thousands	2022		2021
Cash flows from operating activities
Net income	$	1,817,122	$	549,749
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, depletion, amortization and accretion	907,749		980,340
Property impairments	40,074		23,046
Non-cash loss on derivatives	494,142		60,164
Stock-based compensation	44,101		30,546
Provision for deferred income taxes	241,530		175,475
Equity in net loss of affiliate	76		—
Dry hole costs	12,053		—
Net (gain) loss on sale of assets and other	(155)		(467)
(Gain) loss on extinguishment of debt	403		290
Other, net	8,400		4,917
Changes in assets and liabilities:
Accounts receivable	(785,171)		(329,849)
Inventories	(69,662)		(17,106)
Other current assets	(5,704)		(3,039)
Accounts payable trade	78,597		64,812
Revenues and royalties payable	288,324		113,671
Accrued liabilities and other	83,624		59,713
Current income taxes liability	88,679		—
Other noncurrent assets and liabilities	(1,908)		856
Net cash provided by operating activities	3,242,274		1,713,118
Cash flows from investing activities
Exploration and development	(1,309,681)		(585,843)
Purchase of producing crude oil and natural gas properties	(437,377)		(156,351)
Purchase of other property and equipment	(37,645)		(29,342)
Proceeds from sale of assets	2,126		322
Contributions to unconsolidated affiliates	(65,782)		—
Net cash used in investing activities	(1,848,359)		(771,214)
Cash flows from financing activities
Credit facility borrowings	1,916,000		995,000
Repayment of credit facility	(2,416,000)		(1,155,000)

Redemption and repurchase of Senior Notes	(31,829)		(630,782)



Repayment of other debt	(1,155)		(1,113)
Debt issuance costs	(199)		—
Contributions from noncontrolling interests	4,902		13,140
Distributions to noncontrolling interests	(16,841)		(11,236)
Repurchase of common stock	(99,855)		—
Repurchase of restricted stock for tax withholdings	(32,967)		(9,446)
Dividends paid on common stock	(183,579)		(39,899)
Net cash used in financing activities	(861,523)		(839,336)
Net change in cash and cash equivalents	532,392		102,568
Cash and cash equivalents at beginning of period	20,868		47,470
Cash and cash equivalents at end of period	$	553,260	$	150,038

The accompanying notes are an integral part of these condensed consolidated financial statements.

Continental Resources, Inc. and Subsidiaries

Notes to Unaudited Condensed Consolidated Financial Statements

Note 1. Organization and Nature of Business

Nature of Business

Continental Resources, Inc. (the “Company”) was formed in 1967 and is incorporated under the laws of the State of Oklahoma. The Company’s principal business is the exploration, development, management, and production of crude oil and natural gas and associated products with properties primarily located in four leading basins in the United States – the Bakken field of North Dakota and Montana, the Anadarko Basin of Oklahoma, the Permian Basin of Texas, and the Powder River Basin of Wyoming. Additionally, the Company pursues the acquisition and management of perpetually owned minerals located in certain of its key operating areas. For the six months ended June 30, 2022, crude oil accounted for 51% of the Company’s total production and 71% of its crude oil, natural gas, and natural gas liquids revenues.

Recent Developments

On June 14, 2022, the Company’s Board of Directors (the “Board”) received a non-binding proposal from Harold G. Hamm, on behalf of himself, the Harold G. Hamm Trust and certain trusts established for the benefit of Mr. Hamm’s family members (collectively, the “Hamm Family”) to acquire for cash all of the outstanding shares of common stock of the Company, other than shares owned by the Hamm Family and shares underlying unvested equity awards issued pursuant to the Company's long-term incentive plans, for a purchase price of $70.00 per share.

The Board has formed a special committee of independent directors to evaluate and consider the Hamm Family’s proposal. The special committee has hired independent legal and financial advisors to assist it in this process, and such evaluation is ongoing.

The Hamm Family’s proposal constitutes only an indication of interest by the Hamm Family and does not constitute a binding commitment with respect to the proposed transaction or any other transaction. No agreement, arrangement or understanding between the Company and the Hamm Family relating to any proposed transaction will be created unless definitive documentation is executed and delivered by the Hamm Family, the Company, and all other appropriate parties. No assurance can be given that the Hamm Family’s proposal will result in a transaction occurring, its timing, or ultimate terms.

Note 2. Basis of Presentation and Significant Accounting Policies

Basis of presentation

The condensed consolidated financial statements include the accounts of the Company, its wholly-owned subsidiaries, and entities in which the Company has a controlling financial interest. Intercompany accounts and transactions have been eliminated upon consolidation. Noncontrolling interests reflected herein represent third party ownership in the net assets of consolidated subsidiaries. The portions of consolidated net income and equity attributable to the noncontrolling interests are presented separately in the Company’s financial statements.

Investments in entities in which the Company has the ability to exercise significant influence, but does not control, are accounted for using the equity method of accounting. In applying the equity method, the investments are initially recognized at cost and are subsequently adjusted for the Company's proportionate share of earnings, losses, contributions, and distributions as applicable. See Note 13. Equity Investment for discussion of a new strategic investment made by the Company in 2022 that is accounted for under the equity method.

This report has been prepared pursuant to the rules and regulations of the Securities and Exchange Commission (the “SEC”) applicable to interim financial information. Because this is an interim period filing presented using a condensed format, it does not include all disclosures required by accounting principles generally accepted in the United States (“U.S. GAAP”), although the Company believes the disclosures are adequate to make the information not misleading. You should read this Quarterly Report on Form 10-Q (“Form 10-Q”) together with the Company’s Annual Report on Form 10-K for the year ended December 31, 2021 (“2021 Form 10-K”), which includes a summary of the Company’s significant accounting policies and other disclosures.

The condensed consolidated financial statements as of June 30, 2022 and for the three and six month periods ended June 30, 2022 and 2021 are unaudited. The condensed consolidated balance sheet as of December 31, 2021 was derived from the audited balance sheet included in the 2021 Form 10-K. The Company has evaluated events or transactions through the date this report on Form 10-Q was filed with the SEC in conjunction with its preparation of these condensed consolidated financial statements.

The preparation of financial statements in conformity with U.S. GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities, the disclosure and estimation of contingent assets and liabilities at the date of the financial statements, and the reported amounts of revenues and expenses during the reporting periods. Actual results may differ from those estimates. The most significant estimates and assumptions impacting reported

Continental Resources, Inc. and Subsidiaries

Notes to Unaudited Condensed Consolidated Financial Statements

results are estimates of the Company’s crude oil and natural gas reserves, which are used to compute depreciation, depletion, amortization and impairment of proved crude oil and natural gas properties. In the opinion of management, all adjustments (consisting only of normal recurring adjustments) necessary for a fair presentation in accordance with U.S. GAAP have been included in these unaudited condensed consolidated financial statements. The results of operations for any interim period are not necessarily indicative of the results of operations that may be expected for any other interim period or for an entire year.

Earnings per share

Basic net income per share is computed by dividing net income attributable to the Company by the weighted-average number of shares outstanding for the period. In periods where the Company has net income, diluted earnings per share reflects the potential dilution of non-vested restricted stock awards, which are calculated using the treasury stock method. The following table presents the calculation of basic and diluted weighted average shares outstanding and net income per share attributable to the Company for the three and six months ended June 30, 2022 and 2021.


	Three months ended June 30,				Six months ended June 30,
In thousands, except per share data	2022		2021		2022		2021
Net income attributable to Continental Resources (numerator)	$	1,208,747	$	289,325	$	1,806,504	$	548,967
Weighted average shares (denominator):
Weighted average shares - basic	357,575		361,347		357,871		361,069
Non-vested restricted stock	3,618		2,873		4,154		2,961
Weighted average shares - diluted	361,193		364,220		362,025		364,030
Net income per share attributable to Continental Resources:
Basic	$	3.38	$	0.80	$	5.05	$	1.52
Diluted	$	3.35	$	0.79	$	4.99	$	1.51

Credit risk

The Company's principal exposure to credit risk is through receivables associated with the sale of its production and receivables associated with billings to joint interest owners. Accordingly, the Company classifies its receivables into two portfolio segments as depicted on the condensed consolidated balance sheets as "Receivables—Crude oil, natural gas, and natural gas liquids sales” and "Receivables—Joint interest and other.” The Company determines its credit loss allowance for each portfolio segment by considering a number of factors, primarily including the Company’s history of credit losses with adjustment as needed to reflect current conditions, the length of time accounts are past due, whether amounts relate to operated properties or non-operated properties, the ability to recoup amounts owed through netting of production proceeds, the balance of co-owner prepayments if any, and a party's ability to pay. Historically, the Company's credit losses have been immaterial. There were no significant write-offs, recoveries, or changes in the Company's allowance for credit losses during the three and six month periods ended June 30, 2022 and 2021.

Inventories

Inventory is comprised of crude oil held in storage or as line fill in pipelines, pipeline imbalances, and tubular goods and equipment to be used in the Company's exploration and development activities. Crude oil and natural gas inventories are valued at the lower of cost or net realizable value primarily using the first-in, first-out inventory method. Tubular goods and equipment are valued primarily using a weighted average cost method applied to specific classes of inventory items.

The components of inventory as of June 30, 2022 and December 31, 2021 consisted of the following:


In thousands	June 30, 2022		December 31, 2021
Tubular goods and equipment	$	33,530	$	12,506
Crude oil and natural gas	141,724		93,062
Total	$	175,254	$	105,568

Continental Resources, Inc. and Subsidiaries

Notes to Unaudited Condensed Consolidated Financial Statements

Note 3. Property Acquisitions

2022

On March 25, 2022, the Company acquired oil and gas properties in the Powder River Basin of Wyoming for cash consideration of $403 million, representing a $450 million purchase price less customary closing adjustments made pursuant to the acquisition agreement. The acquisition was accounted for as an asset acquisition under ASC Topic 805 and included approximately 172,000 net leasehold acres and producing properties with production totaling approximately 18,000 barrels of oil equivalent per day at the time of closing. The Company recognized approximately $15.3 million of asset retirement obligations, $31.3 million of assumed production and ad valorem tax payment obligations, and $10.1 million of right-of-use assets and corresponding lease liabilities associated with the acquired properties.

On April 15, 2022, the Company acquired oil and gas properties in the Permian Basin of Texas for cash consideration of $197.0 million, consisting of a $20 million escrow deposit paid in March 2022 upon execution of the definitive purchase agreement and a $177.0 million payment made at closing in April 2022. The acquisition was accounted for as an asset acquisition under ASC Topic 805 and was comprised primarily of undeveloped leasehold acreage with an immaterial amount of production.

2021

In March 2021, the Company acquired oil and gas properties in the Powder River Basin of Wyoming for cash consideration of $206.6 million, consisting of a $21.5 million escrow deposit paid in December 2020 upon execution of the definitive purchase agreement and a $185.1 million payment made at closing in March 2021. The acquisition was accounted for as an asset acquisition under ASC Topic 805 and included approximately 130,000 net acres and producing properties with production totaling approximately 7,200 net barrels of oil equivalent per day at the time of closing. The Company recognized approximately $4.9 million of asset retirement obligations and $8.2 million of right-of-use assets and corresponding lease liabilities associated with the acquired properties.

Note 4. Supplemental Cash Flow Information

The following table discloses supplemental cash flow information about cash paid for interest and income tax payments and refunds. Also disclosed is information about investing activities that affects recognized assets and liabilities but does not result in cash receipts or payments.


	Six months ended June 30,
In thousands	2022		2021
Supplemental cash flow information:
Cash paid for interest	$	135,018	$	87,643
Cash paid for income taxes (1)	250,145		3
Cash received for income tax refunds	13		2
Non-cash investing activities:
Asset retirement obligation additions and revisions, net	24,790		8,747

(1) Balance for 2022 represents estimated quarterly payments for 2022 U.S. federal income taxes based on an estimate of federal taxable income for the year.

As of June 30, 2022 and December 31, 2021, the Company had $293.2 million and $242.9 million, respectively, of accrued capital expenditures included in “Net property and equipment” with an offsetting amount in “Accounts payable trade” in the condensed consolidated balance sheets.

As of June 30, 2022 and December 31, 2021, the Company had $0.6 million and $1.7 million, respectively, of accrued contributions from noncontrolling interests included in "Receivables–Joint interest and other" with an offsetting amount in "Equity–Noncontrolling interests" in the condensed consolidated balance sheets.

As of June 30, 2022 and December 31, 2021, the Company had $3.0 million and $2.5 million, respectively, of accrued distributions to noncontrolling interests included in "Revenues and royalties payable" with an offsetting amount in "Equity–Noncontrolling interests" in the condensed consolidated balance sheets.

Continental Resources, Inc. and Subsidiaries

Notes to Unaudited Condensed Consolidated Financial Statements

Note 5. Revenues

Below is a discussion of the nature, timing, and presentation of revenues arising from the Company's major revenue-generating arrangements.

Operated crude oil revenues – The Company pays third parties to transport the majority of its operated crude oil production from lease locations to downstream market centers, at which time the Company's customers take title and custody of the product in exchange for prices based on the particular market where the product was delivered. Operated crude oil revenues are recognized during the month in which control transfers to the customer and it is probable the Company will collect the consideration it is entitled to receive. Crude oil sales proceeds from operated properties are generally received by the Company within one month after the month in which a sale has occurred. Operated crude oil revenues are presented separately from transportation expenses as the Company controls the operated production prior to its transfer to customers. Transportation expenses associated with the Company's operated crude oil production totaled $62.7 million and $43.9 million for the three months ended June 30, 2022 and 2021, respectively, and $120.6 million and $84.0 million for the six months ended June 30, 2022 and 2021, respectively.

Operated natural gas and natural gas liquids revenues – The Company sells a substantial majority of its operated natural gas production to midstream customers at its lease locations based on market prices in the field where the sales occur. Under these arrangements, the midstream customers obtain control of the unprocessed gas stream inclusive of natural gas liquids ("NGLs") at the lease location and the Company's revenues from each sale are determined using contractually agreed pricing formulas which contain multiple components, including the volume and Btu content of the natural gas sold, the midstream customer's proceeds from the sale of residue gas and NGLs at secondary downstream markets, and contractual pricing adjustments reflecting the midstream customer's estimated recoupment of its investment over time. Such revenues are recognized net of pricing adjustments applied by the midstream customer during the month in which control transfers to the customer at the delivery point and it is probable the Company will collect the consideration it is entitled to receive. Natural gas and NGL sales proceeds from operated properties are generally received by the Company within one month after the month in which a sale has occurred.

Under certain arrangements, the Company may elect to take a volume of processed residue gas and/or NGLs in-kind at the tailgate of the midstream customer's processing plant in lieu of a monetary settlement for the sale of the Company's operated production. When the Company elects to take volumes in kind, it takes possession of the processed products at the tailgate of the processing facility and either sells them at the tailgate or pays third parties to transport the products to downstream delivery points, where it then sells to customers at prices applicable to those downstream markets. In such situations, operated revenues are recognized during the month in which control transfers to the customer at the delivery point and it is probable the Company will collect the consideration it is entitled to receive. Operated sales proceeds are generally received by the Company within one month after the month in which a sale has occurred. In these scenarios, the Company's revenues include the pricing adjustments applied by the midstream processing entity according to the applicable contractual pricing formula, but exclude the transportation expenses the Company incurs to transport the processed products to downstream customers. Transportation expenses associated with these arrangements totaled $13.6 million and $8.5 million for the three months ended June 30, 2022 and 2021, respectively, and $30.6 million and $18.7 million for the six months ended June 30, 2022 and 2021, respectively.

Non-operated crude oil, natural gas, and NGL revenues – The Company's proportionate share of production from non-operated properties is generally marketed at the discretion of the operators. For non-operated properties, the Company receives a net payment from the operator representing its proportionate 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 to be received by the Company during the month in which production occurs and it is probable the Company will collect the consideration it is entitled to receive. Proceeds are generally received by the Company within two to three months after the month in which production occurs.

Revenues from derivative instruments – See Note 6. Derivative Instruments for discussion of the Company's accounting for its derivative instruments.

Revenues from service operations – Revenues from the Company's crude oil and natural gas service operations consist primarily of revenues associated with water gathering, recycling, and disposal activities and the treatment and sale of crude oil reclaimed from waste products. Revenues associated with such activities, which are derived using market-based rates or rates commensurate with industry guidelines, are recognized during the month in which services are performed, the Company has an unconditional right to receive payment, and collectability is probable. Payment is generally received by the Company within one month after the month in which services are provided.

Continental Resources, Inc. and Subsidiaries

Notes to Unaudited Condensed Consolidated Financial Statements

Disaggregation of revenues

The following table presents the disaggregation of the Company's crude oil and natural gas revenues by operating area for the three and six months ended June 30, 2022 and 2021. Sales of natural gas and NGLs are combined, as a substantial majority of the Company's natural gas sales contracts represent wellhead sales of unprocessed gas.


	Three months ended June 30, 2022						Three months ended June 30, 2021
In thousands	Crude Oil		Natural Gas and NGLs		Total		Crude Oil		Natural Gas and NGLs		Total
Bakken	$	1,071,043	$	253,607	$	1,324,650	$	695,899	$	92,163	$	788,062
Anadarko Basin	329,666		529,353		859,019		225,179		200,919		426,098
Powder River Basin	161,644		38,216		199,860		27,036		2,569		29,605
Permian Basin	336,532		46,258		382,790		—		—		—
All other	62,596		258		62,854		39,155		(6)		39,149
Crude oil, natural gas, and natural gas liquids sales	$	1,961,481	$	867,692	$	2,829,173	$	987,269	$	295,645	$	1,282,914



	Six months ended June 30, 2022						Six months ended June 30, 2021
In thousands	Crude Oil		Natural Gas and NGLs		Total		Crude Oil		Natural Gas and NGLs		Total

Bakken	$	2,034,360	$	493,475	$	2,527,835	$	1,238,241	$	186,626	$	1,424,867
Anadarko Basin	610,828		872,710		1,483,538		405,667		584,144		989,811
Powder River Basin	241,558		46,508		288,066		37,633		3,636		41,269
Permian Basin	598,916		84,683		683,599		—		—		—
All other	119,667		729		120,396		74,496		4		74,500
Crude oil, natural gas, and natural gas liquids sales	$	3,605,329	$	1,498,105	$	5,103,434	$	1,756,037	$	774,410	$	2,530,447

Continental Resources, Inc. and Subsidiaries

Notes to Unaudited Condensed Consolidated Financial Statements

Note 6. Derivative Instruments

From time to time the Company enters into derivative contracts to economically hedge against the variability in cash flows associated with future sales of production. The Company recognizes its derivative instruments on the balance sheet as either assets or liabilities measured at fair value. The estimated fair value is based upon various factors, including commodity exchange prices, over-the-counter quotations, and, in the case of collars, volatility, the risk-free interest rate, and the time to expiration. The calculation of the fair value of collars requires the use of an option-pricing model. See Note 7. Fair Value Measurements.

At June 30, 2022 the Company had outstanding derivative contracts as set forth in the tables below.


Natural gas derivatives
			Weighted Average Hedge Price ($/MMBtu)
Period and Type of Contract	Average Volumes Hedged		Basis Swaps		Swaps		Sold Put		Floor		Ceiling
July 2022 - December 2023
Basis Swaps - NGPL TXOK	75,000	MMBtus/day	$	(0.17)
July 2022 - Sept 2022
Swaps - Henry Hub	500,000	MMBtus/day			$	4.15
Collars - Henry Hub	110,000	MMBtus/day							$	4.50	$	6.00
Swaps - WAHA	45,000	MMBtus/day			$	3.41
October 2022 - December 2022
Swaps - Henry Hub	160,000	MMBtus/day			$	4.48
Collars - Henry Hub	360,000	MMBtus/day							$	3.88	$	5.45
Three-way collars - Henry Hub	50,000	MMBtus/day					$	3.00	$	4.07	$	5.00
Swaps - WAHA	45,000	MMBtus/day			$	3.41
January 2023 - December 2023
Swaps - Henry Hub	308,000	MMBtus/day			$	3.49
Collars - Henry Hub	139,000	MMBtus/day							$	3.62	$	4.95
Three-way collars - Henry Hub	12,500	MMBtus/day					$	3.00	$	4.32	$	5.00
Swaps - WAHA	40,000	MMBtus/day			$	2.69
January 2024 - December 2024
Swaps - Henry Hub	310,500	MMBtus/day			$	3.26
Collars - Henry Hub	50,000	MMBtus/day							$	3.12	$	4.09
January 2025 - December 2025
Swaps - Henry Hub	37,000	MMBtus/day			$	3.39

Crude oil derivatives

Period and Type of Contract

Average Volumes Hedged

Weighted Average Hedge Price Differential ($/Bbl)

July 2022 - December 2022

NYMEX Roll Swaps

55,500

Bbls/day

1.77

January 2023 - December 2023

NYMEX Roll Swaps

12,000

Bbls/day

1.07

Derivative gains and losses

Cash receipts and payments in the following table reflect the gains or losses on derivative contracts which matured during the applicable period, calculated as the difference between the contract price and the market settlement price of matured contracts. The Company's derivative contracts are settled based upon reported settlement prices on commodity exchanges, with crude oil derivative settlements based on NYMEX West Texas Intermediate ("WTI") pricing and natural gas derivative settlements based primarily on NYMEX Henry Hub pricing. Non-cash gains and losses below represent the change in fair value of derivative instruments which continued to be held at period end and the reversal of previously recognized non-cash gains or losses on

Continental Resources, Inc. and Subsidiaries

Notes to Unaudited Condensed Consolidated Financial Statements

derivative contracts that matured during the period.


	Three months ended June 30,				Six months ended June 30,
In thousands	2022		2021		2022		2021
Cash received (paid) on derivatives:
Crude oil fixed price swaps	$	—	$	(14,429)	$	—	$	(44,463)
Crude oil collars	—		(4,409)		—		(9,365)
Crude oil NYMEX roll swaps	(5,592)		963		(7,072)		1,123
Natural gas basis swaps (NGPL TXOK)	1,563		—		$	1,491	$	—
Natural gas fixed price swaps (HH)	(137,354)		1,741		(141,583)		3,950
Natural gas collars (HH)	(13,917)		50		$	(13,917)	$	3,234
Natural gas 3-way collars (HH)	—		—		$	(16,459)	$	—
Cash received (paid) on derivatives, net	(155,300)		(16,084)		(177,540)		(45,521)
Non-cash gain (loss) on derivatives:
Crude oil fixed price swaps	—		8,205		—		—
Crude oil collars	—		2,304		—		227
Crude oil NYMEX roll swaps	(8,519)		(3,501)		(16,159)		(3,326)
Natural gas basis swaps (NGPL TXOK)	(1,321)		—		4,792		—
Natural gas fixed price swaps (WAHA)	(395)		—		(14,073)		—
Natural gas fixed price swaps (HH)	(40,819)		(40,641)		(368,494)		(34,555)
Natural gas collars (HH)	7,978		(7,641)		(90,258)		(17,690)
Natural gas 3-way collars (HH)	2,632		(4,820)		(9,950)		(4,820)
Non-cash gain (loss) on derivatives, net	(40,444)		(46,094)		(494,142)		(60,164)
Loss on derivative instruments, net	$	(195,744)	$	(62,178)	$	(671,682)	$	(105,685)

Balance sheet offsetting of derivative assets and liabilities

The Company’s derivative contracts are recorded at fair value in the condensed consolidated balance sheets under the captions “Derivative assets,” “Derivative assets, noncurrent,” “Derivative liabilities,” and “Derivative liabilities, noncurrent” as applicable. Derivative assets and liabilities with the same counterparty that are subject to contractual terms which provide for net settlement are reported on a net basis in the condensed consolidated balance sheets.

The following table presents the gross amounts of recognized derivative assets and liabilities, as applicable, the amounts offset under netting arrangements with counterparties, and the resulting net amounts presented in the condensed consolidated balance sheets for the periods presented, all at fair value.



In thousands	June 30, 2022		December 31, 2021
Commodity derivative assets:
Gross amounts of recognized assets	$	13,139	$	42,903
Gross amounts offset on balance sheet	(8,224)		(7,381)
Net amounts of assets on balance sheet	4,915		35,522
Commodity derivative liabilities:
Gross amounts of recognized liabilities	(472,975)		(8,598)
Gross amounts offset on balance sheet	8,224		7,381
Net amounts of liabilities on balance sheet	$	(464,751)	$	(1,217)

Continental Resources, Inc. and Subsidiaries

Notes to Unaudited Condensed Consolidated Financial Statements

The following table reconciles the net amounts disclosed above to the individual financial statement line items in the condensed consolidated balance sheets.



In thousands	June 30, 2022		December 31, 2021
Derivative assets	$	2,799	$	22,334
Derivative assets, noncurrent	2,116		13,188
Net amounts of assets on balance sheet	4,915		35,522
Derivative liabilities	(237,584)		(899)
Derivative liabilities, noncurrent	(227,167)		(318)
Net amounts of liabilities on balance sheet	(464,751)		(1,217)
Total derivative assets (liabilities), net	$	(459,836)	$	34,305

Note 7. Fair Value Measurements

The Company follows a three-level valuation hierarchy for disclosure of fair value measurements. The valuation hierarchy categorizes assets and liabilities measured at fair value into one of three different levels depending on the observability of the inputs employed in the measurement. The three levels are defined as follows:

•Level 1: Observable inputs that reflect unadjusted quoted prices for identical assets or liabilities in active markets as of the reporting date.

•Level 2: Observable market-based inputs or unobservable inputs corroborated by market data. These are inputs other than quoted prices in active markets included in Level 1, which are either directly or indirectly observable as of the reporting date.

•Level 3: Unobservable inputs not corroborated by market data and may be used with internally developed methodologies that result in management’s best estimate of fair value.

A financial instrument’s categorization within the hierarchy is based upon the lowest level of input that is significant to the fair value measurement. Level 1 inputs are given the highest priority in the fair value hierarchy while Level 3 inputs are given the lowest priority. The Company’s assessment of the significance of a particular input to the fair value measurement requires judgment and may affect the placement of assets and liabilities within the levels of the hierarchy. As Level 1 inputs generally provide the most reliable evidence of fair value, the Company uses Level 1 inputs when available.

Assets and Liabilities Measured at Fair Value on a Recurring Basis

The Company's derivative instruments are reported at fair value on a recurring basis. In determining the fair values of swap contracts, a discounted cash flow method is used due to the unavailability of relevant comparable market data for the Company’s exact contracts. The discounted cash flow method estimates future cash flows based on quoted market prices for forward commodity prices and a risk-adjusted discount rate. The fair values of swap contracts are calculated mainly using significant observable inputs (Level 2). Calculation of the fair values of collars requires the use of an industry-standard option pricing model that considers various inputs including quoted forward prices for commodities, time value, volatility factors, and current market and contractual prices for the underlying instruments, as well as other relevant economic measures. These assumptions are observable in the marketplace or can be corroborated by active markets or broker quotes and are therefore designated as Level 2 within the valuation hierarchy. The Company’s calculation of fair value for each of its derivative positions is compared to the counterparty valuation for reasonableness.

Continental Resources, Inc. and Subsidiaries

Notes to Unaudited Condensed Consolidated Financial Statements

The following tables summarize the valuation of derivative instruments by pricing levels that were accounted for at fair value on a recurring basis as of June 30, 2022 and December 31, 2021.



	Fair value measurements at June 30, 2022 using:
In thousands	Level 1		Level 2		Level 3		Total
Derivative assets (liabilities):
Natural gas fixed price swaps (WAHA)	$	—	$	(14,073)	$	—	$	(14,073)
Natural gas fixed price swaps (HH)	—		(340,886)		—		(340,886)
Natural gas basis swaps (NGPL TXOK)	—		4,615		—		4,615
Natural gas collars (HH)	—		(86,272)		—		(86,272)
Natural gas 3-way collars (HH)	—		(8,018)		—		(8,018)
Crude oil NYMEX roll swaps	—		(15,202)		—		(15,202)
Total	$	—	$	(459,836)	$	—	$	(459,836)



	Fair value measurements at December 31, 2021 using:
In thousands	Level 1		Level 2		Level 3		Total
Derivative assets (liabilities):
Natural gas fixed price swaps (HH)	$	—	$	27,608	$	—	$	27,608
Natural gas basis swaps (NGPL TXOK)	—		(177)		—		$	(177)
Natural gas collars (HH)	—		3,986		—		$	3,986
Natural gas 3-way collars (HH)	—		1,931		—		$	1,931
Crude oil NYMEX roll swaps	—		957		—		$	957
Total	$	—	$	34,305	$	—	$	34,305

Assets Measured at Fair Value on a Nonrecurring Basis

Certain assets are reported at fair value on a nonrecurring basis in the condensed consolidated financial statements. The following methods and assumptions were used to estimate the fair values for those assets.

Asset impairments – Proved crude oil and natural gas properties are reviewed for impairment on a field-by-field basis each quarter. The estimated future cash flows expected in connection with the field are compared to the carrying amount of the field to determine if the carrying amount is recoverable. If the carrying amount of the field exceeds its estimated undiscounted future cash flows, the carrying amount of the field is reduced to its estimated fair value. Risk-adjusted probable and possible reserves may be taken into consideration when determining estimated future net cash flows and fair value when such reserves exist and are economically recoverable. Due to the unavailability of relevant comparable market data, a discounted cash flow method is used to determine the fair value of proved properties. Significant unobservable inputs (Level 3) utilized in the determination of discounted future net cash flows include future commodity prices adjusted for differentials, forecasted production based on decline curve analysis, estimated future operating and development costs, property ownership interests, and a 10% discount rate. At June 30, 2022, the Company's commodity price assumptions were based on forward NYMEX strip prices through year-end 2026 and were then escalated at 3% per year thereafter. Operating cost assumptions were based on current costs escalated at 3% per year beginning in 2023.

Unobservable inputs to the Company's fair value assessments are reviewed and revised as warranted based on a number of factors, including reservoir performance, new drilling, commodity prices, changes in costs, technological advances, new geological or geophysical data, or other economic factors. Fair value measurements of proved properties are reviewed and approved by certain members of the Company’s management.

For the six months ended June 30, 2022, the Company determined the carrying amount of a property in an emerging play was not recoverable from future cash flows and therefore was impaired in the amount of $11.8 million, all of which was recognized in the 2022 first quarter. For the three and six months ended June 30, 2021, estimated future net cash flows were determined to be in excess of cost basis, and therefore no impairment was recorded for the Company's proved crude oil and natural gas properties for the 2021 periods.

Certain unproved crude oil and natural gas properties were impaired during the three and six months ended June 30, 2022 and 2021, reflecting recurring amortization of undeveloped leasehold costs on properties the Company expects will not be transferred to proved properties over the lives of the leases based on drilling plans, experience of successful drilling, and the average holding period.

Continental Resources, Inc. and Subsidiaries

Notes to Unaudited Condensed Consolidated Financial Statements

The following table sets forth the non-cash impairments of both proved and unproved properties for the indicated periods. Proved and unproved property impairments are recorded under the caption “Property impairments” in the unaudited condensed consolidated statements of operations.


	Three months ended June 30,				Six months ended June 30,
In thousands	2022		2021		2022		2021
Proved property impairments	$	—	$	—	$	11,821	$	—
Unproved property impairments	15,826		11,610		28,253		23,046
Total	$	15,826	$	11,610	$	40,074	$	23,046

Financial Instruments Not Recorded at Fair Value

The following table sets forth the estimated fair values of financial instruments that are not recorded at fair value in the condensed consolidated financial statements.


	June 30, 2022				December 31, 2021
In thousands	Carrying Amount		Estimated Fair Value		Carrying Amount		Estimated Fair Value
Debt:
Credit facility	$	—	$	—	$	500,000	$	500,000
Notes payable	21,207		19,800		22,356		22,000
4.5% Senior Notes due 2023	635,056		636,900		648,078		670,200
3.8% Senior Notes due 2024	890,819		885,300		908,061		950,000
2.268% Senior Notes due 2026	793,337		708,500		792,621		795,200
4.375% Senior Notes due 2028	992,471		939,900		991,880		1,082,100
5.75% Senior Notes due 2031	1,483,070		1,447,300		1,482,319		1,769,600
2.875% Senior Notes due 2032	791,876		627,900		791,521		780,500
4.9% Senior Notes due 2044	692,155		555,200		692,056		781,500
Total debt	$	6,299,991	$	5,820,800	$	6,828,892	$	7,351,100

The fair value of credit facility borrowings approximate carrying value based on borrowing rates available to the Company for bank loans with similar terms and maturities and are classified as Level 2 in the fair value hierarchy.

The fair value of notes payable is determined using a discounted cash flow approach based on the interest rate and payment terms of the notes payable and an assumed discount rate. The fair value of notes payable is significantly influenced by the discount rate assumption, which is derived by the Company and is unobservable. Accordingly, the fair value of notes payable is classified as Level 3 in the fair value hierarchy.

The fair values of the Company's senior notes are based on quoted market prices and, accordingly, are classified as Level 1 in the fair value hierarchy.

The carrying values of all classes of cash and cash equivalents, trade receivables, and trade payables are considered to be representative of their respective fair values due to the short term maturities of those instruments.

Continental Resources, Inc. and Subsidiaries

Notes to Unaudited Condensed Consolidated Financial Statements

Note 8. Debt

The Company's debt, net of unamortized discounts, premiums, and debt issuance costs totaling $50.4 million and $54.2 million at June 30, 2022 and December 31, 2021, respectively, consists of the following.


In thousands	June 30, 2022		December 31, 2021
Credit facility	$	—	$	500,000
Notes payable	21,207		22,356
4.5% Senior Notes due 2023 (1)	635,056		648,078
3.8% Senior Notes due 2024	890,819		908,061
2.268% Senior Notes due 2026	793,337		792,621
4.375% Senior Notes due 2028	992,471		991,880
5.75% Senior Notes due 2031	1,483,070		1,482,319
2.875% Senior Notes due 2032	791,876		791,521
4.9% Senior Notes due 2044	692,155		692,056
Total debt	$	6,299,991	$	6,828,892
Less: Current portion of long-term debt (1)	637,424		2,326
Long-term debt, net of current portion	$	5,662,567	$	6,826,566

(1) The Company's 2023 Notes, which have a face value of $636.0 million at June 30, 2022, are scheduled to mature on April 15, 2023 and, accordingly, are included as a current liability in the caption “Current portion of long-term debt” in the condensed consolidated balance sheets as of June 30, 2022.

Credit Facility

The Company has an unsecured credit facility, maturing in October 2026, with aggregate lender commitments totaling $2.0 billion, which may be increased up to a total of $4.0 billion upon agreement between the Company and participating lenders. The Company had no outstanding borrowings on its credit facility at June 30, 2022.

Credit facility borrowings, if any, bear interest at market-based interest rates plus a margin based on the terms of the borrowing and the credit ratings assigned to the Company's senior, unsecured, long-term indebtedness. The Company incurs commitment fees based on currently assigned credit ratings of 0.20% per annum on the daily average amount of unused borrowing availability.

The credit facility contains certain restrictive covenants including a requirement that the Company maintain a consolidated net debt to total capitalization ratio of no greater than 0.65 to 1.00. This ratio represents the ratio of net debt (calculated as total face value of debt plus outstanding letters of credit less cash and cash equivalents) divided by the sum of net debt plus total shareholders' equity plus, to the extent resulting in a reduction of total shareholders’ equity, the amount of any non-cash impairment charges incurred, net of any tax effect, after June 30, 2014. The Company was in compliance with the credit facility covenants at June 30, 2022.

Senior Notes

The following table summarizes the face values, maturity dates, semi-annual interest payment dates, and optional redemption periods related to the Company’s outstanding senior note obligations at June 30, 2022.

2023 Notes

2024 Notes

2026 Notes

2028 Notes

2031 Notes

2032 Notes

2044 Notes

Face value (in thousands)

$636,000

$893,126

$800,000

$1,000,000

$1,500,000

$800,000

$700,000

Maturity date

April 15, 2023

June 1, 2024

November 15, 2026

January 15, 2028

January 15, 2031

April 1, 2032

June 1, 2044

Interest payment dates

April 15, Oct 15

June 1, Dec 1

May 15, Nov 15

Jan 15, July 15

Jan 15,
Jul 15

April 1, Oct 1

June 1, Dec 1

Make-whole redemption period (1)

Jan 15, 2023

Mar 1, 2024

Nov 15, 2023

Oct 15, 2027

Jul 15, 2030

January 1. 2032

Dec 1, 2043

Continental Resources, Inc. and Subsidiaries

Notes to Unaudited Condensed Consolidated Financial Statements

(1)At any time prior to the indicated dates, the Company has the option to redeem all or a portion of its senior notes of the applicable series at the “make-whole” redemption amounts specified in the respective senior note indentures plus any accrued and unpaid interest to the date of redemption. On or after the indicated dates, the Company may redeem all or a portion of its senior notes at a redemption amount equal to 100% of the principal amount of the senior notes being redeemed plus any accrued and unpaid interest to the date of redemption.

The Company’s senior notes are not subject to any mandatory redemption or sinking fund requirements.

The indentures governing the Company’s senior notes contain covenants that, among other things, limit the Company’s ability to create liens securing certain indebtedness, enter into certain sale-leaseback transactions, or consolidate, merge or transfer certain assets. These covenants are subject to a number of important exceptions and qualifications. The Company was in compliance with these covenants at June 30, 2022.

The senior notes are obligations of Continental Resources, Inc. Additionally, certain of the Company’s wholly-owned subsidiaries (Banner Pipeline Company, L.L.C., CLR Asset Holdings, LLC, The Mineral Resources Company, SCS1 Holdings LLC, Continental Innovations LLC, Jagged Peak Energy LLC, and Parsley SoDe Water LLC) fully and unconditionally guarantee the senior notes on a joint and several basis. The financial information of the guarantor group is not materially different from the consolidated financial statements of the Company. The Company’s other subsidiaries, whose assets, equity, and results of operations attributable to the Company are not material, do not guarantee the senior notes.

Retirement of Senior Notes

2022

In the second quarter of 2022, the Company repurchased a portion of its 2023 Notes and 2024 Notes in open market transactions, including $13.6 million face value of its 2023 Notes at an aggregate cost of $13.9 million and $17.9 million face value of its 2024 Notes at an aggregate cost of $18.3 million, in each case, including accrued and unpaid interest to the repurchase dates. The Company recognized pre-tax losses on extinguishment of debt totaling $0.4 million related to the repurchases, which included the pro-rata write-off of deferred financing costs and unamortized debt discount associated with the repurchased notes. The losses are reflected in the caption “Gain (loss) on extinguishment of debt” in the unaudited condensed consolidated statements of operations.

2021

In January 2021, the Company redeemed $400.0 million principal amount of its outstanding 2022 Notes and subsequently redeemed the remaining $230.8 million principal amount of its 2022 Notes in April 2021. The Company recognized a pre-tax loss on extinguishment of debt in the 2021 first quarter related to the January 2021 redemption totaling $0.2 million and an additional pre-tax loss on extinguishment of debt in the 2021 second quarter related to the April 2021 redemption totaling $0.1 million, which included the pro-rata write-off of deferred financing costs and unamortized debt premium associated with the redeemed notes.

Notes payable

In June 2020, the Company borrowed an aggregate of $26.0 million under two 10-year amortizing term loans secured by the Company’s corporate office building and its interest in parking facilities in Oklahoma City, Oklahoma. The loans mature in May 2030 and bear interest at a fixed rate of 3.50% per annum through June 9, 2025, at which time the interest rate will be reset and fixed through the maturity date. Principal and interest are payable monthly through the maturity date and, accordingly, $2.4 million is included as a current liability in the caption “Current portion of long-term debt” in the condensed consolidated balance sheets as of June 30, 2022 associated with the loans.

Note 9. Commitments and Contingencies

Transportation, gathering, and processing commitments – The Company has entered into transportation, gathering, and processing commitments to guarantee capacity on crude oil and natural gas pipelines and natural gas processing facilities. Certain of the commitments, which have varying terms extending as far as 2031, require the Company to pay per-unit transportation, gathering, or processing charges regardless of the amount of capacity used. Future commitments remaining as of June 30, 2022 under the arrangements amount to approximately $1.19 billion, of which $142 million is expected to be incurred in the remainder of 2022, $273 million in 2023, $255 million in 2024, $164 million in 2025, $139 million in 2026, and $214 million thereafter. A portion of these future costs will be borne by other interest owners. The Company is not committed under the above contracts to deliver fixed and determinable quantities of crude oil or natural gas in the future. These commitments do not qualify as leases under ASC Topic 842 and are not recognized on the Company's balance sheet.

Continental Resources, Inc. and Subsidiaries

Notes to Unaudited Condensed Consolidated Financial Statements

Strategic investment – See Note 13. Equity Investment for discussion of future spending commitments associated with a new strategic investment announced by the Company in the first quarter of 2022.

Litigation

In December 2017, the Company filed an action in Garfield County, Oklahoma state court against Hiland Partners Holdings, LLC (“Hiland”), a subsidiary of Kinder Morgan, Inc. The Company alleged breach of contract and fraud. The parties entered into a settlement agreement in June 2018, under which Continental agreed to release its claims in exchange for Hiland’s construction of certain infrastructure projects by November 1, 2020. After such deadline passed, Continental filed an amended petition asserting the original claims and additional claims for breach of contract. The Company has vigorously prosecuted the case, and the parties have agreed to temporarily stay the case pending ongoing settlement discussions. As such, the nature and ultimate realization of any recovery is uncertain and cannot be predicted.

In March 2022, the Company was named as a defendant in a case filed in the U.S. District Court for the Northern District of California by gasoline consumer plaintiffs alleging that, beginning in March 2020, the Company and the other named defendants conspired with Russia, OPEC and others to raise the price of oil and gasoline by reducing the supply of these products. The plaintiffs are seeking unspecified damages and injunctive relief. On July 1, 2022, the Company, together with other named defendants, filed motions to dismiss. The Company intends to vigorously defend the case.

The Company is involved in various other legal proceedings including, but not limited to, commercial disputes, claims from royalty and surface owners, property damage claims, personal injury claims, regulatory compliance matters, disputes with tax authorities and other matters. While the outcome of these legal matters cannot be predicted with certainty, the Company does not expect them to have a material adverse effect on its financial condition, results of operations or cash flows. As of June 30, 2022, and December 31, 2021, the Company had recognized a liability within “Other noncurrent liabilities” of $10.0 million and $7.9 million, respectively, for various matters, none of which are believed to be individually significant.

Environmental risk – Due to the nature of the crude oil and natural gas business, the Company is exposed to possible environmental risks. The Company is not aware of any material environmental issues or claims.

Note 10. Stock-Based Compensation

The Company has granted restricted stock to employees and directors pursuant to the Continental Resources, Inc. 2013 Long-Term Incentive Plan as amended ("2013 Plan") and 2022 Long-Term Incentive Plan ("2022 Plan"). The Company’s associated compensation expense, which is included in the caption “General and administrative expenses” in the unaudited condensed consolidated statements of operations, was $14.8 million and $13.6 million for the three months ended June 30, 2022 and 2021, respectively, and $44.1 million and $30.5 million for the six months ended June 30, 2022 and 2021, respectively.

In May 2022, the Company adopted the 2022 Plan and reserved a maximum of 15,818,785 shares of common stock that may be issued pursuant to the plan. The 2022 Plan replaced the Company's 2013 Plan as the instrument used to grant long-term incentive awards and no further awards will be granted under the 2013 Plan. However, restricted stock awards granted under the 2013 Plan prior to the adoption of the 2022 Plan will remain outstanding in accordance with their terms. Subject to limited exceptions, the 2022 Plan allows previously issued shares to be reissued if such shares are subsequently forfeited or withheld to satisfy tax withholdings. As of June 30, 2022, the Company had 15,762,789 shares of common stock available for long-term incentive awards to employees and directors under the 2022 Plan.

Restricted stock is awarded in the name of the recipient and constitutes issued and outstanding shares of the Company’s common stock for all corporate purposes during the period of restriction and, except as otherwise provided under the 2013 Plan, 2022 Plan, or agreement relevant to a given award, includes the right to vote the restricted stock and to receive dividends, subject to forfeiture. Restricted stock grants generally vest over periods ranging from 1 to 3 years.

A summary of changes in non-vested restricted shares outstanding for the six months ended June 30, 2022 is presented below.


	Number of non-vested shares	Weighted average grant-date fair value
Non-vested restricted shares outstanding at December 31, 2021	5,894,508	$	28.38
Granted	1,431,883	55.32
Vested	(1,634,157)	36.80
Forfeited	(293,109)	25.48
Non-vested restricted shares outstanding at June 30, 2022	5,399,125	$	33.13

Continental Resources, Inc. and Subsidiaries

Notes to Unaudited Condensed Consolidated Financial Statements

The grant date fair value of restricted stock represents the closing market price of the Company’s common stock on the date of grant. Compensation expense for a restricted stock grant is determined at the grant date fair value and is recognized over the vesting period as services are rendered by employees and directors. The Company estimates the number of forfeitures expected to occur in determining the amount of stock-based compensation expense to recognize. There are no post-vesting restrictions related to the Company’s restricted stock. The fair value at the vesting date of restricted stock that vested during the six months ended June 30, 2022 was approximately $91 million. As of June 30, 2022, there was approximately $107 million of unrecognized compensation expense related to non-vested restricted stock. This expense is expected to be recognized over a weighted average period of 1.5 years.

Note 11. Shareholders' Equity

2022 Share Repurchases

In May 2019 the Board approved the initiation of a share repurchase program to acquire up to $1 billion of the Company's common stock beginning in June 2019. On February 8, 2022, the Board approved an increase in the size of the program from $1.0 billion to $1.5 billion, inclusive of cumulative amounts repurchased as of February 8, 2022.

During the three months ended March 31, 2022 the Company repurchased and retired approximately 1.84 million shares of its common stock at an aggregate cost of $99.9 million. No additional share repurchases have been made subsequent to March 31, 2022. The Company has repurchased and retired a cumulative total of approximately 18.81 million shares at an aggregate cost of $540.9 million since the inception of its share repurchase program in June 2019, leaving $959.1 million of authorized repurchasing capacity under the modified program as of June 30, 2022.

The timing and amount of the Company's share repurchases are subject to market conditions and management discretion. The share repurchase program does not require the Company to repurchase a specific number of shares and may be modified, suspended, or terminated by the Board at any time.

2022 Dividend Payments

On February 9, 2022, the Company declared a quarterly cash dividend of $0.23 per share on its outstanding common stock, which amounted to $82.5 million and was paid on March 4, 2022 to shareholders of record as of February 22, 2022.

On April 27, 2022, the Company declared a quarterly cash dividend of $0.28 per share on its outstanding common stock, which amounted to $100.1 million and was paid on May 23, 2022 to shareholders of record as of May 9, 2022.

Dividend Declaration

On July 27, 2022, the Company declared a quarterly cash dividend of $0.28 per share on its outstanding common stock, which will be paid on August 22, 2022 to shareholders of record as of August 8, 2022.

Note 12. Income Taxes

The Company's provision for income taxes and resulting effective tax rates were as follows for the periods presented.


	Three months ended June 30,						Six months ended June 30,
In thousands, except tax rates	2022			2021			2022			2021
Current tax provision	$	242,723		$	—		$	338,825		$	—
Deferred tax provision	146,548			94,947			241,530			175,475
Provision for income taxes	389,271			94,947			580,355			175,475
Effective tax rate	24.3		%	24.7		%	24.2		%	24.2		%

The Company computes its quarterly income tax provision under the effective tax rate method based on applying an anticipated annual effective tax rate to year-to-date pre-tax income, except for discrete items. Income taxes for discrete items are computed and recorded in the period in which the specific transaction occurs.

The Company's effective tax rate differs from the United States federal statutory tax rate due to the effect of state income taxes, equity compensation, changes in valuation allowances, and other tax items as reflected in the table below.

Continental Resources, Inc. and Subsidiaries

Notes to Unaudited Condensed Consolidated Financial Statements


	Three months ended June 30,						Six months ended June 30,
In thousands, except tax rates	2022			2021			2022			2021
Income before income taxes	$	1,605,118		$	384,421		$	2,397,553		$	725,224
U.S. federal statutory tax rate	21.0		%	21.0		%	21.0		%	21.0		%
Expected income tax provision based on U.S. federal statutory tax rate	337,075			80,728			503,486			152,297
Items impacting the effective tax rate:
State and local income taxes, net of federal benefit	56,434			13,555			84,103			26,451
Equity compensation	(927)			147			(4,377)			6,137
Other, net	(3,311)			112			(2,857)			(4,920)
Change in valuation allowance	—			405			—			(4,490)
Provision for income taxes	$	389,271		$	94,947		$	580,355		$	175,475
Effective tax rate	24.3		%	24.7		%	24.2		%	24.2		%

Note 13. Equity Investment

In March 2022 the Company began investing in an affiliate of Summit Carbon Solutions (“Summit”) to develop carbon capture and sequestration infrastructure. Summit was founded in 2020 with the goal of decarbonizing the biofuel and agriculture industries and seeks to lower greenhouse gas emissions by connecting industrial facilities via strategic infrastructure to capture, transport, and store carbon dioxide (“CO2”) safely and permanently in the Midwestern United States.

The Company has committed to invest a total of $250 million with Summit over 2022 and 2023 to fund a portion of Summit's development and construction of capture, transportation, and sequestration infrastructure, while also leveraging the Company's operational and geologic expertise to facilitate the underground storage of CO2. Summit intends to primarily capture CO2 from ethanol plants and other industrial sources in Iowa, Nebraska, Minnesota, North Dakota, and South Dakota, and aggregate and transport the CO2 to North Dakota via pipeline, where it will be sequestered in subsurface geologic formations. The project is expected to become operational in 2024.

The Company contributed $62.5 million in the first quarter of 2022 toward its $250 million commitment to Summit, which is included in the caption “Investment in unconsolidated affiliates” in the unaudited condensed consolidated balance sheet. Upon completion of Summit's ongoing equity raises, the Company expects to hold approximately 22% ownership interest in the equity of Summit Carbon Holdings, the parent company of Summit Carbon Solutions. The Company accounts for its investment in Summit under the equity method of accounting. The Company’s share of earnings/losses from its investment was immaterial for the three and six months ended June 30, 2022.

ITEM 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations

The following discussion and analysis should be read in conjunction with the unaudited condensed consolidated financial statements and notes thereto included elsewhere in this report and our historical consolidated financial statements and notes included in our Form 10-K for the year ended December 31, 2021.

The following discussion and analysis includes forward-looking statements and should be read in conjunction with the risk factors described in Part II, Item 1A. Risk Factors included in this report and in our Form 10-K for the year ended December 31, 2021, along with Cautionary Statement for the Purpose of the “Safe Harbor” Provisions of the Private Securities Litigation Reform Act of 1995 at the beginning of this report, for information about the risks and uncertainties that could cause our actual results to be materially different than our forward-looking statements.

Overview

We are an independent crude oil and natural gas company engaged in the exploration, development, management, and production of crude oil and natural gas and associated products with properties primarily located in four leading basins in the United States – the Bakken field of North Dakota and Montana, the Anadarko Basin of Oklahoma, the Permian Basin of Texas, and the Powder River Basin of Wyoming. Additionally, we pursue the acquisition and management of perpetually owned minerals located in certain of our key operating areas. We derive the majority of our operating income and cash flows from the sale of crude oil, natural gas, and natural gas liquids and expect this to continue in the future. Our common stock trades on the New York Stock Exchange under the symbol “CLR” and our corporate internet website is www.clr.com.

Recent developments

On June 14, 2022, our Board of Directors (the “Board”) received a non-binding proposal from Harold G. Hamm, on behalf of himself, the Harold G. Hamm Trust and certain trusts established for the benefit of Mr. Hamm’s family members (collectively, the “Hamm Family”) to acquire for cash all of the outstanding shares of common stock of the Company, other than shares owned by the Hamm Family and shares underlying unvested equity awards issued pursuant to the Company's long-term incentive plans, for a purchase price of $70.00 per share.

Second Quarter 2022 Highlights

Financial and operating highlights for the second quarter of 2022 are summarized below.

•Generated $1.74 billion in operating cash flows in the 2022 second quarter, bringing year to date operating cash flows to $3.24 billion.

•Production averaged 400,168 Boe per day for the 2022 second quarter, a 7% sequential increase from the 2022 first quarter and 18% higher than the 2021 second quarter.

•Completed strategic leasehold acquisition to further expand our operations in the Permian Basin for cash consideration of $197 million.

•Increased our quarterly fixed dividend by 22% to $0.28 per share of common stock which was paid on May 23, 2022.

•Reduced outstanding debt by $266 million in the 2022 second quarter, bringing year to date debt reduction to $531 million.

•Exited the second quarter with $2.55 billion of liquidity, representing $553 million of cash and $2.0 billion of borrowing capacity on our undrawn credit facility.

Financial and Operating Metrics

Commodity prices have increased significantly in 2022 compared to 2021 levels resulting from the ongoing rebalancing of crude oil and natural gas supply and demand fundamentals coupled with the disruption of global hydrocarbon markets prompted by the outbreak of military conflict between Russia and Ukraine. The increase in commodity prices contributed to improved operating results and cash flows for the three and six month periods ended June 30, 2022 compared to the comparable 2021 periods. Additionally, our property acquisitions in the Permian Basin and Powder River Basin over the past year contributed to increased production, revenues, and cash flows in 2022 compared to the 2021 periods. Commodity prices remain volatile and unpredictable and our operating results for the first half of 2022 may not be indicative of future results. Given the uncertainty surrounding the Russia/Ukraine conflict and ongoing volatility in commodity prices, we are unable to predict the extent to which the conflict or other factors will have on the Company’s performance during the remainder of 2022 and beyond.

The following table contains financial and operating metrics 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 June 30,						Six months ended June 30,
	2022			2021			2022			2021
Average daily production:
Crude oil (Bbl per day)	198,313			166,765			196,550			159,350
Natural gas (Mcf per day) (1)	1,211,125			1,031,603			1,143,068			984,334
Crude oil equivalents (Boe per day)	400,168			338,699			387,062			323,405
Average net sales prices (2):
Crude oil ($/Bbl)	$	106.41		$	62.37		$	98.70		$	57.95
Natural gas ($/Mcf) (1)	$	7.75		$	3.06		$	7.09		$	4.24
Crude oil equivalents ($/Boe)	$	76.02		$	39.99		$	70.96		$	41.47
Crude oil net sales price discount to NYMEX ($/Bbl)	$	(2.30)		$	(3.83)		$	(2.88)		$	(4.16)
Natural gas net sales price premium to NYMEX ($/Mcf) (1)	$	0.52		$	0.23		$	0.95		$	1.48
Production expenses ($/Boe)	$	4.23		$	3.14		$	4.16		$	3.24
Production and ad valorem taxes (% of net crude oil and natural gas sales)	7.4		%	7.7		%	7.3		%	7.3		%
Depreciation, depletion, amortization and accretion ($/Boe)	$	12.33		$	15.33		$	12.98		$	16.76
Total general and administrative expenses ($/Boe)	$	1.73		$	1.81		$	1.97		$	1.85

(1) Natural gas production volumes, sales volumes, and net sales prices presented throughout management's discussion and analysis reflect the combined value for natural gas and natural gas liquids.

(2) See the subsequent section titled Non-GAAP Financial Measures for a discussion and calculation of net sales prices, which are non-GAAP measures.

Three months ended June 30, 2022 compared to the three months ended June 30, 2021

Results of Operations

The following table presents selected financial and operating information for the periods presented.


	Three months ended June 30,
In thousands	2022		2021
Crude oil, natural gas, and natural gas liquids sales	$	2,829,173	$	1,282,914
Loss on derivative instruments, net	(195,744)		(62,178)
Crude oil and natural gas service operations	17,045		14,389
Total revenues	2,650,474		1,235,125
Operating costs and expenses	(973,957)		(789,957)
Other expenses, net	(71,399)		(60,747)
Income before income taxes	1,605,118		384,421
Provision for income taxes	(389,271)		(94,947)
Income before equity in net loss of affiliate	1,215,847		289,474
Equity in net loss of affiliate	(76)		—
Net income	1,215,771		289,474
Net income attributable to noncontrolling interests	7,024		149
Net income attributable to Continental Resources	$	1,208,747	$	289,325
Production volumes:
Crude oil (MBbl)	18,047		15,176
Natural gas (MMcf)	110,212		93,876
Crude oil equivalents (MBoe)	36,415		30,822
Sales volumes:
Crude oil (MBbl)	17,844		15,127
Natural gas (MMcf)	110,212		93,876
Crude oil equivalents (MBoe)	36,213		30,773

Production

The following table summarizes the changes in our average daily Boe production by major operating area for the second quarter period.


Boe production per day	2Q 2022	2Q 2021	% Change
Bakken	162,840	174,637	(7	%)
Anadarko Basin	160,583	151,813	6	%
Powder River Basin	27,211	6,002	353	%
Permian Basin	43,527	—	—	%
All other	6,007	6,247	(4	%)
Total	400,168	338,699	18	%

The following table summarizes the changes in our production by product for the second quarter period.


	Three months ended June 30,						Volume increase	Volume percent increase
	2022			2021
	Volume	Percent		Volume	Percent
Crude oil (MBbl)	18,047	50	%	15,176	49	%	2,871	19	%
Natural gas (MMcf)	110,212	50	%	93,876	51	%	16,336	17	%
Total (MBoe)	36,415	100	%	30,822	100	%	5,593	18	%

The 19% increase in crude oil production in the 2022 second quarter was primarily driven by our property acquisitions in the Permian Basin and Powder River Basin over the past year, which increased our 2022 second quarter production by 3,066 MBbls and 1,115 MBbls, respectively, compared to the 2021 second quarter. These increases were partially offset by an 827 MBbls, or 8%, decrease in Bakken crude oil production due to the effects of severe winter weather in April 2022 that resulted in the curtailment of a portion of our production, delays in drilling and completion of wells, and other operational constraints. Additionally, crude oil production in the Anadarko Basin decreased 456 MBbls, or 13%, due to a change in allocation of capital from oil-weighted projects to gas-weighted projects in the play over the past year and the timing of well completions.

The 17% increase in natural gas production in the 2022 second quarter was due in part to the previously described property acquisitions over the past year. Properties acquired in the Permian Basin increased our 2022 second quarter production by 5,370 MMcf while properties acquired in the Powder River Basin increased our production by 4,890 MMcf compared to the 2021 second quarter. Additionally, natural gas production in the Anadarko Basin increased 7,523 MMcf, or 12%, over the 2021 second quarter due to new well completions over the past year. These increases were partially offset by a 1,477 MMcf, or 5%, decrease in Bakken natural gas production due to the previously described weather-related production curtailments and operational constraints in April 2022.

Revenues

Net crude oil, natural gas, and natural gas liquids sales and related net sales prices presented below are non-GAAP measures. See the subsequent section titled Non-GAAP Financial Measures for a discussion and calculation of these measures.

Net crude oil, natural gas, and natural gas liquids sales. Net sales totaled $2.75 billion for the second quarter of 2022, a 124% increase compared to net sales of $1.23 billion for the 2021 second quarter due to significant increases in net sales prices and sales volumes as discussed below.

Total sales volumes for the second quarter of 2022 increased 5,440 MBoe, or 18%, compared to the 2021 second quarter primarily due to new wells added from our property acquisitions over the past year. For the second quarter of 2022, our crude oil sales volumes increased 18% and our natural gas sales volumes increased 17% compared to the 2021 second quarter.

Our crude oil net sales prices averaged $106.41 per barrel in the 2022 second quarter compared to $62.37 per barrel for the 2021 second quarter due to the previously described increase in market prices along with improved price differentials. The differential between NYMEX West Texas Intermediate calendar month prices and our realized crude oil net sales prices improved to an average of $2.30 per barrel for the 2022 second quarter compared to $3.83 per barrel for the 2021 second quarter, reflecting strong price realizations across our assets.

Our natural gas net sales prices averaged $7.75 per Mcf for the 2022 second quarter compared to $3.06 per Mcf for the 2021 second quarter due to the previously described increase in market prices along with improved price differentials. The difference between our net sales prices and NYMEX Henry Hub calendar month natural gas prices improved to a premium of $0.52 per Mcf for the 2022 second quarter compared to a premium of $0.23 per Mcf for the 2021 second quarter, again reflecting strong price realizations across our assets.

Derivatives. The continued improvement in commodity prices during the second quarter of 2022 had a significant unfavorable impact on the fair value of our derivatives, which resulted in negative revenue adjustments totaling $195.7 million for the period, representing $155.3 million of cash losses and $40.4 million of unsettled non-cash losses, compared to negative revenue adjustments totaling $62.2 million in the second quarter of 2021.

Operating Costs and Expenses

Production Expenses. Production expenses increased $56.7 million, or 59%, to $153.2 million for the second quarter of 2022 compared to $96.5 million for the second quarter of 2021 due to an increase in the number of producing wells from drilling activities and property acquisitions, cost inflation for services and materials, and higher workover-related activities aimed at enhancing production from producing properties prompted by the favorable commodity price environment. Production expenses on a per-Boe basis averaged $4.23 per Boe for the 2022 second quarter compared to $3.14 per Boe for the 2021 second quarter, the increase of which reflects higher workover-related activities, cost inflation, and the addition of oil-weighted production acquired in the Permian and Powder River basins over the past year which typically have higher per-unit operating costs compared to gas-weighted properties in the Anadarko Basin.

Production and Ad Valorem Taxes. Production and ad valorem taxes increased $109.9 million, or 117%, to $204.2 million for the second quarter of 2022 compared to $94.3 million for the second quarter of 2021 due to the previously described increase in sales. Our production taxes as a percentage of net sales averaged 7.4% for the second quarter of 2022 compared to 7.7% for the second quarter of 2021.

Depreciation, Depletion, Amortization and Accretion. Total DD&A decreased $25.3 million, or 5%, to $446.6 million for the second quarter of 2022 compared to $471.9 million for the second quarter of 2021 primarily due to a decrease in our DD&A rate per Boe as further discussed below, partially offset by the previously described 18% increase in total sales volumes. The following table shows the components of our DD&A on a unit of sales basis for the periods presented.


	Three months ended June 30,
$/Boe	2022		2021
Crude oil and natural gas	$	12.04	$	15.03
Other equipment	0.20		0.21
Asset retirement obligation accretion	0.09		0.09
Depreciation, depletion, amortization and accretion	$	12.33	$	15.33

Estimated proved reserves are a key component in our computation of DD&A expense. Proved reserves are determined using the unweighted arithmetic average of the first-day-of-the-month commodity prices for the preceding twelve months as required by SEC rules. Holding all other factors constant, if proved reserves are revised downward due to commodity price declines or other reasons, the rate at which we record DD&A expense increases. Conversely, if proved reserves are revised upward, the rate at which we record DD&A expense decreases.

Our proved reserves have been revised upward over the past year prompted by significant increases in first-day-of-the-month commodity prices and other factors, which, when coupled with improvements in capital efficiency and strong well productivity, resulted in a decrease in our DD&A rate for crude oil and natural gas properties in the second quarter of 2022 compared to the second quarter of 2021 and helped offset the additional DD&A recognized in 2022 from increased sales volumes.

Property Impairments. Total property impairments increased $4.2 million to $15.8 million for the second quarter of 2022 compared to $11.6 million for the second quarter of 2021, reflecting an increase in the amortization of undeveloped leasehold costs driven by an increase in our balance of unproved properties resulting from property acquisitions over the past year. There were no proved property impairments recognized in the second quarter periods of 2022 and 2021.

General and Administrative Expenses. Total G&A expenses increased $7.0 million, or 13%, to $62.6 million for the second quarter of 2022 compared to $55.6 million for the second quarter of 2021.

Total G&A expenses include non-cash charges for equity compensation of $14.8 million and $13.6 million for the second quarters of 2022 and 2021, respectively. G&A expenses other than equity compensation totaled $47.8 million for the 2022 second quarter, an increase of $5.8 million compared to $42.0 million for the 2021 second quarter primarily due to the growth of our operations and increases in payroll costs and employee benefits, partially offset by higher overhead recoveries from joint interest owners driven by increased drilling, completion, and production activities compared to the 2021 second quarter.

The following table shows the components of G&A expenses on a unit of sales basis for the periods presented.


	Three months ended June 30,
$/Boe	2022		2021
General and administrative expenses	$	1.32	$	1.37
Non-cash equity compensation	0.41		0.44
Total general and administrative expenses	$	1.73	$	1.81

Interest Expense. Interest expense increased $11.3 million, or 19%, to $72.2 million for the second quarter of 2022 compared to $61.0 million for the second quarter of 2021 due to an increase in our weighted average outstanding debt balance from $4.9 billion for the second quarter of 2021 to $6.6 billion for the second quarter of 2022. This increase was driven by debt incurred in the fourth quarter of 2021 to fund a portion of our December 2021 acquisition of properties in the Permian Basin.

Income Taxes. For the second quarters of 2022 and 2021 we provided for income taxes at a combined federal and state tax rate of 24.5% of our pre-tax income. We recorded an income tax provision of $389.3 million for the 2022 second quarter and an income tax provision of $94.9 million for the 2021 second quarter, which resulted in effective tax rates of 24.3% and 24.7%, respectively, after taking into account statutory tax rates, permanent taxable differences, tax effects from equity compensation, changes in valuation allowances, and other items. See Notes to Unaudited Condensed Consolidated Financial Statements–Note 12. Income Taxes for a summary of the sources and tax effects of items comprising our effective tax rates.

Six months ended June 30, 2022 compared to the six months ended June 30, 2021

Results of Operations

The following table presents selected financial and operating information for the periods presented.


	Six months ended June 30,
In thousands	2022		2021
Crude oil, natural gas, and natural gas liquids sales	$	5,103,434	$	2,530,447
Loss on derivative instruments, net	(671,682)		(105,685)
Crude oil and natural gas service operations	34,960		26,178
Total revenues	4,466,712		2,450,940
Operating costs and expenses	(1,923,978)		(1,600,074)
Other expenses, net	(145,181)		(125,642)
Income before income taxes	2,397,553		725,224
Provision for income taxes	(580,355)		(175,475)
Income before equity in net loss of affiliate	1,817,198		549,749
Equity in net loss of affiliate	(76)		—
Net income	1,817,122		549,749
Net income attributable to noncontrolling interests	10,618		782
Net income attributable to Continental Resources	$	1,806,504	$	548,967
Production volumes:
Crude oil (MBbl)	35,576		28,842
Natural gas (MMcf)	206,895		178,165
Crude oil equivalents (MBoe)	70,058		58,536
Sales volumes:
Crude oil (MBbl)	35,305		28,853
Natural gas (MMcf)	206,895		178,165
Crude oil equivalents (MBoe)	69,787		58,547

Production

The following table summarizes the changes in our average daily Boe production by major operating area for the year to date period.


Boe production per day	YTD 6/30/2022	YTD 6/30/2021	% Change
Bakken	167,097	167,646	—	%
Anadarko Basin	152,319	145,137	5	%
Powder River Basin	19,475	4,243	359	%
Permian Basin	41,896	—	—
All other	6,275	6,379	(2	%)
Total	387,062	323,405	20	%

The following table summarizes the changes in our production by product for the year to date period.


	Six months ended June 30,						Volume increase	Volume percent increase
	2022			2021
	Volume	Percent		Volume	Percent
Crude oil (MBbl)	35,576	51	%	28,842	49	%	6,734	23	%
Natural gas (MMcf)	206,895	49	%	178,165	51	%	28,730	16	%
Total (MBoe)	70,058	100	%	58,536	100	%	11,522	20	%

The 23% increase in crude oil production for year to date 2022 compared to year to date 2021 was primarily driven by our property acquisitions in the Permian Basin and Powder River Basin over the past year, which increased our year to date 2022 production by 5,874 MBbls and 1,772 MBbls, respectively, compared to year to date 2021. These increases were partially offset by a 630 MBbls, or 9%, decrease in Anadarko Basin crude oil production due to a change in allocation of capital from oil-weighted projects to gas-weighted projects in the play over the past year and the timing of well completions.

The 16% increase in natural gas production for year to date 2022 compared to year to date 2021 was due in part to the previously described property acquisitions over the past year. Properties acquired in the Permian Basin increased our year to date 2022 production by 10,258 MMcf while properties acquired in the Powder River Basin increased our production by 5,912 MMcf compared to year to date 2021. Additionally, natural gas production in the Anadarko Basin increased 11,579 MMcf, or 10%, compared to year to date 2021 due to new well completions over the past year.

Revenues

Net crude oil, natural gas, and natural gas liquids sales. Net sales for year to date 2022 totaled $4.95 billion, an increase of 104% compared to net sales of $2.43 billion for the comparable 2021 period due to significant increases in net sales prices and sales volumes as discussed below.

Total sales volumes for year to date 2022 increased 11,240 MBoe, or 19%, compared to year to date 2021 primarily due to new wells added from our property acquisitions over the past year. For year to date 2022, our crude oil sales volumes increased 22% and our natural gas sales volumes increased 16% compared to year to date 2021.

Our crude oil net sales prices averaged $98.70 per barrel for year to date 2022 compared to $57.95 per barrel for year to date 2021 due to the previously described increase in market prices along with improved price differentials. The differential between NYMEX WTI calendar month prices and our realized crude oil net sales prices improved to an average of $2.88 per barrel for year to date 2022 compared to $4.16 per barrel for year to date 2021, reflecting strong price realizations across our assets.

Our natural gas net sales prices averaged $7.09 per Mcf for year to date 2022 compared to $4.24 per Mcf for year to date 2021 due to the previously described increase in market prices. The difference between our net sales prices and NYMEX Henry Hub calendar month natural gas prices was a premium of $0.95 per Mcf for year to date 2022 compared to a premium of $1.48 per Mcf for year to date 2021. The decrease in premium was driven by price volatility and significant improvement in Henry Hub prices as compared to increases in NGL prices during the 2022 second quarter, causing the uplift in price realizations for our full gas stream relative to Henry Hub benchmark prices to be less significant in the current period.

Derivatives. The significant improvement in commodity prices during the six months ended June 30, 2022 had a significant unfavorable impact on the fair value of our derivatives, which resulted in negative revenue adjustments totaling $671.7 million for the period, representing $177.5 million of cash losses and $494.1 million of unsettled non-cash losses, compared to negative revenue adjustments totaling $105.7 million in the comparable 2021 period.

Crude oil and natural gas service operations. Our crude oil and natural gas service operations consist primarily of revenues associated with water gathering, recycling, and disposal activities, which are impacted by our production volumes and the timing and extent of our drilling and completion projects. Revenues associated with such activities increased $8.8 million, or 34%, from $26.2 million for year to date 2021 to $35.0 million for year to date 2022 primarily due to increased water handling resulting from increased drilling, completion, and production activities compared to the 2021 period, which also contributed to an increase in service-related operating expenses in the current period.

Operating Costs and Expenses

Production Expenses. Production expenses increased $100.9 million, or 53%, to $290.5 million for year to date 2022 compared to $189.6 million for year to date 2021 due to an increase in the number of producing wells from drilling activities and property acquisitions, cost inflation for services and materials, and higher workover-related activities aimed at enhancing production from producing properties prompted by the favorable commodity price environment. Production expenses on a per-Boe basis averaged $4.16 per Boe for year to date 2022 compared to $3.24 per Boe for year to date 2021, the increase of which reflects higher workover-related activities, cost inflation, and the addition of oil-weighted production acquired in the Permian and Powder River basins over the past year which typically have higher per-unit operating costs compared to gas-weighted properties in the Anadarko Basin.

Production and Ad Valorem Taxes. Production and ad valorem taxes increased $184.3 million, or 103%, to $362.6 million for year to date 2022 compared to $178.3 million for year to date 2021 due to the previously described increase in sales. Our production taxes as a percentage of net sales averaged 7.3% for year to date 2022, consistent with 7.3% for year to date 2021.

Exploration expenses. Exploration expenses, which consist primarily of exploratory geological and geophysical costs and dry hole costs that are expensed as incurred, increased $10.7 million to $17.7 million for year to date 2022 compared to $6.9 million for year to date 2021. The year to date 2022 period includes $12.1 million of dry hole costs associated with an unsuccessful exploratory well with no comparable dry hole costs incurred in the year to date 2021 period.

Depreciation, Depletion, Amortization and Accretion. Total DD&A decreased $75.8 million, or 8%, to $905.7 million for year to date 2022 compared to $981.5 million for the comparable 2021 period due to the previously described decrease in our DD&A rate per Boe in 2022 partially offset by the 19% increase in our total sales volumes. The following table shows the components of our DD&A on a unit of sales basis for the periods presented.


	Six months ended June 30,
$/Boe	2022		2021
Crude oil and natural gas	$	12.68	$	16.46
Other equipment	0.21		0.21
Asset retirement obligation accretion	0.09		0.09
Depreciation, depletion, amortization and accretion	$	12.98	$	16.76

Property Impairments. Total property impairments increased $17.0 million to $40.1 million for the year to date period of 2022 compared to $23.0 million for year to date 2021, primarily reflecting an $11.8 million proved property impairment recognized in the 2022 first quarter on a property in an emerging play with no proved property impairments being recognized in the prior year period. Additionally, impairments of unproved properties increased $5.2 million for year to date 2022 compared to year to date 2021, reflecting an increase in the amortization of undeveloped leasehold costs driven by an increase in our balance of unproved properties resulting from property acquisitions over the past year.

General and Administrative Expenses. Total G&A expenses increased $29.0 million, or 27%, to $137.4 million for year to date 2022 compared to $108.4 million for year to date 2021.

Total G&A expenses include non-cash charges for equity compensation of $44.1 million and $30.5 million for the year to date periods of 2022 and 2021, respectively. This increase was primarily driven by approximately $10 million of incremental expenses recognized on restricted stock awards whose vesting terms were modified and accelerated in the 2022 first quarter upon the retirement of certain management personnel from the Company.

G&A expenses other than equity compensation totaled $93.3 million for year to date 2022, an increase of $15.4 million compared to $77.9 million for the comparable 2021 period primarily due to the growth of our operations and increases in payroll costs and employee benefits, partially offset by higher overhead recoveries from joint interest owners driven by increased drilling, completion, and production activities compared to the prior period.

The following table shows the components of G&A expenses on a unit of sales basis for the periods presented.


	Six months ended June 30,
$/Boe	2022		2021
General and administrative expenses	$	1.34	$	1.33
Non-cash equity compensation	0.63		0.52
Total general and administrative expenses	$	1.97	$	1.85

Interest Expense. Interest expense increased $18.9 million, or 15%, to $144.8 million for year to date 2022 compared to $125.9 million for the comparable 2021 period due to an increase in our weighted average outstanding debt balance from $5.3 billion for year to date 2021 to $6.7 billion for year to date 2022. This increase was driven by debt incurred in the fourth quarter of 2021 to fund a portion of our December 2021 acquisition of properties in the Permian Basin.

Income Taxes. For the six months ended June 30, 2022 and 2021 we provided for income taxes at a combined federal and state tax rate of 24.5% of our pre-tax income. We recorded an income tax provision of $580.4 million for the year to date period of 2022 and an income tax provision of $175.5 million for year to date 2021, which resulted in effective tax rates of 24.2% and 24.2%, respectively, after taking into account statutory tax rates, permanent taxable differences, tax effects from equity compensation, changes in valuation allowances, and other items. See Notes to Unaudited Condensed Consolidated Financial Statements–Note 12. Income Taxes for a summary of the sources and tax effects of items comprising our effective tax rates.

Liquidity and Capital Resources

Our primary sources of liquidity have historically been cash flows generated from operating activities, financing provided by our credit facility and the issuance of debt securities. Additionally, asset dispositions and joint development arrangements have provided a source of cash flow for use in reducing debt and enhancing liquidity. We are committed to operating in a responsible manner to preserve financial flexibility, liquidity, and the strength of our balance sheet.

At July 28, 2022, we had no outstanding borrowings and $2.0 billion of borrowing availability under our credit facility. Our credit facility, which is unsecured and has no borrowing base subject to redetermination, does not mature until October 2026.

Our credit facility has an accordion feature that allows us to increase lender commitments from $2.0 billion up to a total of $4.0 billion upon agreement between the Company and participating lenders.

Recent developments

As previously described, on June 14, 2022 our Board received a non-binding proposal from the Hamm Family to acquire for cash all of the outstanding shares of common stock of Continental, other than shares owned by the Hamm Family and shares underlying unvested equity awards issued pursuant to Continental’s long-term incentive plans, for a purchase price of $70.00 per share.

The Hamm Family collectively holds approximately 83% of Continental's total outstanding shares as of June 30, 2022. There are approximately 58 million shares of Continental's common stock that are not held by the Hamm Family. The aggregate market value of such shares is approximately $4.1 billion using the $70.00 per share price offered by the Hamm Family in its non-binding take-private proposal.

While no assurance can be given that the take-private transaction will ultimately be consummated, if such transaction does occur the purchase of outstanding shares not held by the Hamm Family is expected to be funded by Continental through a combination of funding sources, including the use of cash on hand, utilization of credit facility borrowing capacity, bank term loan facilities, and/or the issuance of debt securities.

Based on our planned capital spending, our forecasted cash flows, and projected levels of indebtedness, we expect to maintain compliance with the covenants under our credit facility and senior note indentures, including additional debt that may be incurred to fund the potential take-private transaction described above. Further, based on current market indications, we expect to meet our contractual cash commitments to third parties as of June 30, 2022, including those subsequently described under the heading Future Capital Requirements, recognizing we may be required to meet such commitments even if our business plan assumptions were to change. We monitor our capital spending closely based on actual and projected cash flows and have the ability to reduce spending or dispose of assets if needed to preserve liquidity and financial flexibility to fund our operations.

Cash Flows

Cash flows from operating activities

Net cash provided by operating activities increased $1.53 billion, or 89%, to $3.24 billion for year to date 2022 compared to $1.71 billion for year to date 2021 driven by a $2.6 billion increase in crude oil, natural gas, and NGL revenues due to the previously described increases in commodity prices and sales volumes in the current period. This increase was partially offset by a $132 million increase in realized cash losses on matured commodity derivatives, a $250 million increase in cash payments for U.S. federal income taxes, a $184 million increase in production and ad valorem taxes associated with higher revenues, and increases in certain other cash operating expenses primarily due to an increase in sales volumes and growth of our Company over the past year. Increased cash operating expenses included a $101 million increase in production expenses and a $49 million increase in transportation, gathering, processing, and compression expenses.

Cash flows from investing activities

Net cash used in investing activities increased $1.08 billion to $1.85 billion for year to date 2022 compared to $771 million for year to date 2021, reflecting our planned increase in budgeted spending and an increase in the magnitude of year to date property acquisitions. Non-acquisition capital expenditures attributable to us for full year 2022 are budgeted to be between $2.6 billion and $2.7 billion compared to $1.54 billion of non-acquisition capital spending for full year 2021. Our investing cash flows for year to date 2022 include $403 million paid to acquire properties in the Powder River Basin and $197 million paid to acquire properties in the Permian Basin as discussed in Note 3. Property Acquisitions as well as $63 million paid for the new strategic investment in an affiliate of Summit Carbon Solutions described in Note 13. Equity Investment in Notes to Unaudited Condensed Consolidated Financial Statements.

Cash flows from financing activities

Net cash used in financing activities for year to date 2022 totaled $862 million, primarily consisting of $500 million of net repayments on our credit facility, $184 million of cash dividends paid on common stock, $100 million of cash used to repurchase shares of our common stock, and $32 million of cash used to repurchase senior notes.

Net cash used in financing activities for year to date 2021 totaled $839 million, primarily consisting of $631 million of cash used to redeem senior notes, $160 million of net repayments on our credit facility, and $40 million of cash dividends paid on common stock.

Future Sources of Financing

Although we cannot provide any assurance, we believe funds from operating cash flows, our cash balance, and availability under our credit facility should be sufficient to meet our normal operating needs, debt service obligations, budgeted capital expenditures, cash payments for income taxes, and dividend payments for at least the next 12 months and to meet our contractual cash commitments to third parties beyond 12 months.

Based on current market indications, our budgeted capital spending plans for 2022 are expected to be funded from operating cash flows. Any deficiencies in operating cash flows relative to budgeted spending are expected to be funded by borrowings under our credit facility. If cash flows are materially impacted by declines in commodity prices, we have the ability to reduce our capital expenditures or utilize the availability of our credit facility if needed to fund our operations and business plans.

We may choose to access banking or capital markets for additional financing or capital to fund our operations or to finance business opportunities or developments that may arise. Further, we may sell assets or enter into strategic joint development opportunities in order to obtain funding if such transactions can be executed on satisfactory terms. However, no assurance can be given that such transactions will occur.

Credit facility

We have an unsecured credit facility, maturing in October 2026, with aggregate lender commitments totaling $2.0 billion, which may be increased up to a total of $4.0 billion upon agreement between the Company and participating lenders. The commitments are from a syndicate of 12 banks and financial institutions. We believe each member of the current syndicate has the capability to fund its commitment. As of July 28, 2022, we had no outstanding borrowings and $2.0 billion of borrowing availability on our credit facility.

The commitments under our credit facility are not dependent on a borrowing base calculation subject to periodic redetermination based on changes in commodity prices and proved reserves. Additionally, downgrades or other negative rating actions with respect to our credit rating do not trigger a reduction in our current credit facility commitments, nor do such actions trigger a security requirement or change in covenants. Downgrades of our credit rating will, however, trigger increases in our credit facility's interest rates and commitment fees paid on unused borrowing availability under certain circumstances.

Our credit facility contains restrictive covenants that may limit our ability to, among other things, incur additional indebtedness, incur liens, engage in sale and leaseback transactions, or merge, consolidate or sell all or substantially all of our assets. Our credit facility also contains a requirement that we maintain a consolidated net debt to total capitalization ratio of no greater than 0.65 to 1.00. See Notes to Unaudited Condensed Consolidated Financial Statements–Note 8. Debt for a discussion of how this ratio is calculated pursuant to our credit agreement.

We were in compliance with our credit facility covenants at June 30, 2022 and expect to maintain such compliance. At June 30, 2022, our consolidated net debt to total capitalization ratio was 0.36. We do not believe the credit facility covenants are reasonably likely to limit our ability to undertake additional debt financing if needed to support our business. Additionally, our credit facility covenants are not expected to limit our ability to incur debt if needed to finance the Hamm Family's proposed take-private transaction if such transaction is consummated. At June 30, 2022, our total debt would have needed to independently increase by approximately $13.7 billion above the existing level at that date (with no corresponding increase in cash or reduction in refinanced debt) to reach the maximum covenant ratio of 0.65 to 1.00. Alternatively, our total shareholders' equity would have needed to independently decrease by approximately $7.4 billion (excluding the after-tax impact of any non-cash impairment charges) below the existing level at June 30, 2022 to reach the maximum covenant ratio.

Future Capital Requirements

Our material future cash requirements are summarized below. Based on current market indications, we expect to meet our contractual cash commitments to third parties as of June 30, 2022, recognizing we may be required to meet such commitments even if our business plan assumptions were to change.

Senior notes

Our debt includes outstanding senior note obligations totaling $6.33 billion at June 30, 2022, exclusive of interest payment obligations thereon. Our senior notes are not subject to any mandatory redemption or sinking fund requirements. The earliest scheduled senior note maturity is our $636 million of 2023 Notes due in April 2023, which is reflected as a current liability in the caption “Current portion of long-term debt” in the condensed consolidated balance sheets as of June 30, 2022. We expect to be able to generate or obtain sufficient funds necessary to fully redeem our 2023 Notes by the maturity date. For further information on the face values, maturity dates, semi-annual interest payment dates, optional redemption periods and covenant restrictions related to our senior notes, refer to Note 8. Debt in Notes to Unaudited Condensed Consolidated Financial Statements.

We were in compliance with our senior note covenants at June 30, 2022 and expect to maintain such compliance. We do not believe the senior note covenants will materially limit our ability to undertake additional debt financing if needed to support our business. Additionally, our senior note covenants are not expected to limit our ability to incur debt if needed to finance the Hamm Family's proposed take-private transaction if such transaction is consummated.

Downgrades or other negative rating actions with respect to the credit ratings assigned to our senior unsecured debt do not trigger additional senior note covenants.

Transportation, gathering, and processing commitments

We have entered into transportation, gathering, and processing commitments to guarantee capacity on crude oil and natural gas pipelines and natural gas processing facilities that require us to pay per-unit charges regardless of the amount of capacity used. Future commitments remaining as of June 30, 2022 under the arrangements amount to approximately $1.19 billion. See Note 9. Commitments and Contingencies in Notes to Unaudited Condensed Consolidated Financial Statements for additional information.

Capital expenditures

Our capital expenditures budget for 2022 is expected to be $2.6 billion to $2.7 billion. Costs of acquisitions and investments, such as those described in Note 3. Property Acquisitions and Note 13. Equity Investment in Notes to Unaudited Condensed Consolidated Financial Statements, are not budgeted, with the exception of planned levels of spending for mineral acquisitions.

For the six months ended June 30, 2022, we invested $1.17 billion in our capital program excluding $662.3 million of unbudgeted acquisitions, excluding $3.7 million of mineral acquisitions attributable to Franco-Nevada, and including $50.3 million of capital costs associated with increased accruals for capital expenditures as compared to December 31, 2021. Our 2022 year to date capital expenditures were allocated as shown in the table below.


In millions	1Q 2022		2Q 2022		YTD 2022
Exploration and development drilling	$	426.2	$	504.7	$	930.9
Land costs	24.3		31.2		55.5
Mineral acquisitions attributable to Continental	0.5		0.4		0.9
Capital facilities, workovers, water infrastructure, and other corporate assets	72.3		110.9		183.2
Seismic	0.6		1.3		1.9
Capital expenditures attributable to Continental, excluding unbudgeted acquisitions	523.9		648.5		1,172.4

Unbudgeted acquisitions	443.1		219.2		662.3
Total capital expenditures attributable to Continental	$	967.0	$	867.7	$	1,834.7
Mineral acquisitions attributable to Franco-Nevada	1.9		1.8		3.7
Total capital expenditures	$	968.9	$	869.5	$	1,838.4

Our drilling and completion activities and the actual amount and timing of our capital expenditures may differ materially from our budget as a result of, among other things, available cash flows, unbudgeted acquisitions, actual drilling and completion results, operational process improvements, the availability of drilling and completion rigs and other services and equipment, cost inflation, the availability of transportation, gathering and processing capacity, changes in commodity prices, and

regulatory, technological and competitive developments. We monitor our capital spending closely based on actual and projected cash flows and may adjust our spending should commodity prices materially change from current levels. We expect to continue participating as a buyer of properties when and if we have the ability to increase our position in strategic plays at attractive terms.

Strategic Investment

See Note 13. Equity Investment in Notes to Unaudited Condensed Consolidated Financial Statements for discussion of future spending commitments associated with a new strategic investment made by the Company with Summit Carbon Solutions beginning in the first quarter of 2022.

Cash Payments for Income Taxes

In April 2022 we made an estimated quarterly payment for 2022 U.S. federal income taxes of $125 million and made an additional estimated quarterly payment in June 2022 of $125 million based on an estimate of federal taxable income for the year. Significant judgment is involved in estimating future taxable income as we are required to make assumptions about future commodity prices, projected production, development activities, capital spending, profitability, and general economic conditions, all of which are subject to material revision in future periods as better information becomes available. As of June 30, 2022, the publicly available forward commodity strip prices for the remainder of 2022 averaged approximately $99.00 per barrel for crude oil and $5.70 per Mcf for natural gas. If commodity prices remain at these levels for the remainder of the year, we expect to utilize the full amount of our federal net operating loss carryforwards and certain state net operating loss carryforwards and generate significant taxable income in 2022, which would result in us continuing to make estimated cash payments for income taxes for the third and fourth quarters of 2022 that could approximate the $125 million quarterly payments made in April and June 2022. Because of the significant uncertainty inherent in numerous factors utilized in projecting taxable income, we cannot predict the amount of future income tax payments with certainty.

Dividend Declaration

Share repurchase program

In May 2019 the Board approved the initiation of a share repurchase program to acquire up to $1 billion of our common stock beginning in June 2019. On February 8, 2022, the Board approved an increase in the size of the share repurchase program to $1.5 billion. As of the date of this filing, we have repurchased and retired a cumulative total of approximately 18.81 million shares under the program at an aggregate cost of $540.9 million, leaving $959.1 million of authorized repurchasing capacity under the modified program. The timing and amount of the Company's share repurchases are subject to market conditions and management discretion. The share repurchase program does not require the Company to repurchase a specific number of shares and may be modified, suspended, or terminated by the Board at any time.

Senior note redemptions and repurchases

In recent periods we have redeemed or repurchased a portion of our outstanding senior notes. From time to time, we may execute additional redemptions or repurchases of our senior notes for cash in open market transactions, privately negotiated transactions, or otherwise. The timing and amount of any such redemptions or repurchases will depend on prevailing market conditions, our liquidity and prospects for future access to capital, and other factors. The amounts involved in any such transactions, individually or in the aggregate, may be material. Our $636 million of 2023 Notes is due in April 2023, which we plan to fully redeem by the maturity date.

Derivative Instruments

The fair value of our derivative instruments at June 30, 2022 was a net liability of $459.8 million. See Note 6. Derivative Instruments in Notes to Unaudited Condensed Consolidated Financial Statements for further discussion of our hedging activities, including a summary of derivative contracts in place as of June 30, 2022. The estimated fair value of our derivatives is highly sensitive to market price volatility and therefore subject to significant fluctuations from period to period. See Item 3. Quantitative and Qualitative Disclosures About Market Risk for information on how hypothetical changes in commodity prices would impact the fair value of our derivatives as of June 30, 2022.

Dakota Access Pipeline

In response to a July 2020 U.S. District Court decision vacating the U.S. Army Corps of Engineers (“Corps”) grant of an easement to the Dakota Access Pipeline (“DAPL”) and issuance of an order requiring the Corps to conduct an environmental impact statement for the pipeline, the Corps is currently conducting the court-ordered environmental review to determine whether DAPL poses a threat to the drinking water supply of the Standing Rock Sioux Reservation. DAPL currently remains in operation. The owners of DAPL appealed the District Court decision to the U.S. Supreme Court in September 2021, but the appeal was rejected on February 22, 2022. The Corps continues to conduct the review, which is estimated to be completed no later than November 2022. Once the review is completed, the Corps will determine whether DAPL is safe to operate or must be shut down. We are unable to determine the outcome or the impact of this matter on DAPL in the future.

We utilize DAPL to transport a portion of our Bakken crude oil production to ultimate markets on the U.S. gulf coast. Our transportation commitment on the pipeline totals 30,000 barrels per day which will continue through February 2026 at which time the commitment decreases to 26,450 barrels per day through July 2028.

If transportation capacity on DAPL becomes restricted or unavailable, we have the ability to utilize other third party pipelines or rail facilities to transport our Bakken crude oil production to market, although such alternatives may be more costly. A restriction of DAPL’s takeaway capacity may have an impact on prices for Bakken-produced barrels and result in wider differentials relative to WTI benchmark prices in the future, the amount of which is uncertain.

Legislative and Regulatory Developments

The crude oil and natural gas industry in the United States is subject to various types of regulation at the federal, state and local levels. President Biden, in pursuit of his regulatory agenda, has issued, and may continue to issue, executive orders that result in more stringent and costly requirements for the domestic crude oil and natural gas industry and there is the potential for the revision of existing laws and regulations or the adoption of new legislation that could adversely affect the oil and gas industry, including those pertaining to the taxation of oil and gas exploration and production activities. Such changes, if enacted, could have a material adverse effect on our results of operations and cash flows. See Part I, Item 1. Business—Regulation of the Crude Oil and Natural Gas Industry in our Form 10-K for the year ended December 31, 2021 for a discussion of significant laws and regulations that have been enacted or are currently being considered by regulatory bodies that may affect us in the areas in which we operate.

SEC rule proposal on climate-related disclosures

In March 2022, the SEC proposed rule amendments that would create a wide range of new climate-related disclosure obligations for registrants. The proposed rules would require registrants to include certain climate-related information in registration statements and annual reports, including (i) climate-related risks and their actual or likely material impacts on the registrant’s business, strategy, and outlook; (ii) the registrant’s governance of climate-related risks and relevant risk management processes; (iii) information on the registrant’s greenhouse gas emissions, which, for accelerated and large accelerated filers and with respect to certain emissions, would be subject to assurance; (iv) certain climate-related financial statement metrics and related disclosures in a note to audited financial statements; and (v) information about climate-related targets, goals, and transition plans. The proposed rules have not been finalized and may be subject to challenges and litigation. Thus, the ultimate scope and impact of the proposed rules on our business remain uncertain. To the extent new rules, if finalized, impose additional reporting obligations on us, we could face increased costs.

Inflation

Certain drilling and completion costs and costs of oilfield services, equipment, and materials decreased in recent years as service providers reduced their costs in response to reduced demand arising from historically low crude oil prices. However, inflationary pressures returned in 2021 and continue to persist in 2022 in conjunction with the significant increase in commodity prices over the past year, labor shortages, and other factors. Additionally, supply chain disruptions stemming from the COVID-19 pandemic have led to shortages of certain materials and equipment and resulting increases in material and labor costs. Our capital spending budget for 2022 includes an estimate for the impact of cost inflation and, despite inflationary pressures, we expect to continue generating significant amounts of free cash flow at current commodity price levels.

Critical Accounting Policies and Estimates

There have been no changes in our critical accounting policies and estimates from those disclosed in our 2021 Form 10-K.

Non-GAAP Financial Measures

Net crude oil, natural gas, and natural gas liquids sales and net sales prices

Revenues and transportation expenses associated with production from our operated properties are reported separately as discussed in Notes to Unaudited Condensed Consolidated Financial Statements–Note 5. Revenues. 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 have presented crude oil, natural gas, and natural gas liquids sales net of transportation expenses in Management’s Discussion and Analysis of Financial Condition and Results of Operations, which we refer to as "net crude oil, natural gas, and natural gas liquids sales," a non-GAAP measure. Average sales prices calculated using net 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. 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, natural gas, and natural gas liquids sales (GAAP) to net crude oil, natural gas, and natural gas liquids sales and related net sales prices (non-GAAP) for the three and six months ended June 30, 2022 and 2021.


	Three months ended June 30, 2022						Three months ended June 30, 2021
In thousands	Crude oil		Natural gas and NGLs		Total		Crude oil		Natural gas and NGLs		Total
Crude oil, natural gas, and NGL sales (GAAP)	$	1,961,481	$	867,692	$	2,829,173	$	987,269	$	295,645	$	1,282,914
Less: Transportation expenses	(62,714)		(13,638)		(76,352)		(43,898)		(8,547)		(52,445)
Net crude oil, natural gas, and NGL sales (non-GAAP)	$	1,898,767	$	854,054	$	2,752,821	$	943,371	$	287,098	$	1,230,469
Sales volumes (MBbl/MMcf/MBoe)	17,844		110,212		36,213		15,127		93,876		30,773
Net sales price (non-GAAP)	$	106.41	$	7.75	$	76.02	$	62.37	$	3.06	$	39.99


	Six months ended June 30, 2022						Six months ended June 30, 2021
In thousands	Crude oil		Natural gas and NGLs		Total		Crude oil		Natural gas and NGLs		Total
Crude oil, natural gas, and NGL sales (GAAP)	$	3,605,329	$	1,498,105	$	5,103,434	$	1,756,037	$	774,410	$	2,530,447
Less: Transportation expenses	(120,601)		(30,600)		(151,201)		(83,977)		(18,724)		(102,701)
Net crude oil, natural gas, and NGL sales (non-GAAP)	$	3,484,728	$	1,467,505	$	4,952,233	$	1,672,060	$	755,686	$	2,427,746
Sales volumes (MBbl/MMcf/MBoe)	35,305		206,895		69,787		28,853		178,165		58,547
Net sales price (non-GAAP)	$	98.70	$	7.09	$	70.96	$	57.95	$	4.24	$	41.47

ITEM 3. Quantitative and Qualitative Disclosures About Market Risk

General. We are exposed to a variety of market risks including commodity price risk, credit risk, and interest rate risk. We seek to address these risks through a program of risk management which may include the use of derivative instruments.

Commodity Price Risk. Our primary market risk exposure is in the prices we receive from sales of crude oil, natural gas, and natural gas liquids. Realized pricing is primarily driven by the prevailing worldwide price for crude oil and spot market prices applicable to our natural gas and natural gas liquids production. Commodity prices have been volatile and unpredictable for several years, and we expect this volatility to continue in the future. The prices we receive for production depend on many factors outside of our control, including differences between product prices at sales points and the applicable index prices. Based on our average daily production for the six months ended June 30, 2022, and excluding the effect of derivative instruments in place, our annual revenue would increase or decrease by approximately $717 million for each $10.00 per barrel change in crude oil prices at June 30, 2022 and $417 million for each $1.00 per Mcf change in natural gas prices at June 30, 2022.

To reduce price risk caused by market fluctuations in commodity prices, from time to time we may economically hedge a portion of our anticipated production as part of our risk management program. In addition, we may utilize basis contracts to hedge the differential between derivative contract index prices and those of our physical pricing points. Reducing our exposure to price volatility helps secure funds to be used for our capital program and general corporate purposes. Our decision on the quantity and price at which we choose to hedge our production is based in part on our view of current and future market conditions. We may choose not to hedge future production if the price environment for certain time periods is deemed to be unfavorable. Additionally, we may choose to settle existing derivative positions prior to the expiration of their contractual maturities. While hedging, if utilized, limits the downside risk of adverse price movements, it also limits future revenues from upward price movements.

The fair value of our derivative instruments at June 30, 2022 was a net liability of $459.8 million, which is comprised of a $444.6 million net liability associated with our natural gas derivatives and a $15.2 million net liability associated with our crude oil derivatives. The following table shows how a hypothetical +/- 10% change in the underlying forward prices used to calculate the fair value of our derivatives would impact the fair value estimates as of June 30, 2022.


		Hypothetical Fair Value
In thousands	Change in Forward Price	Asset (Liability)
Crude Oil	-10%	($12,000)
Crude Oil	+10%	($18,404)
Natural Gas	-10%	($266,202)
Natural Gas	+10%	($625,609)

Changes in the fair value of our derivatives from the above price sensitivities would produce a corresponding change in our total revenues.

Credit Risk. We monitor our risk of loss due to non-performance by counterparties of their contractual obligations. Our principal exposure to credit risk is through the sale of our production, which we market to energy marketing companies, crude oil refining companies, and natural gas gathering and processing companies ($1.8 billion in receivables at June 30, 2022), and our joint interest and other receivables ($336 million at June 30, 2022).

We monitor our exposure to counterparties on our commodity sales primarily by reviewing credit ratings, financial statements and payment history. We extend credit terms based on our evaluation of each counterparty’s credit worthiness. We have not generally required our counterparties to provide collateral to secure commodity sales receivables owed to us. Historically, our credit losses on commodity sales receivables have been immaterial.

Joint interest receivables arise from billing the individuals and entities who own a partial interest in the wells we operate. These individuals and entities participate in our wells primarily based on their ownership in leases included in units on which we wish to drill. We can do very little to choose who participates in our wells. In order to minimize our exposure to this credit risk we generally request prepayment of drilling costs where it is allowed by contract or state law. For such prepayments, a liability is recorded and subsequently reduced as the associated work is performed. This liability was $19 million at June 30, 2022, which will be used to offset future capital costs when billed. In this manner, we reduce credit risk. We may have the right to place a lien on a co-owner's interest in the well, to net production proceeds against amounts owed in order to secure payment or, if necessary, foreclose on the interest. Historically, our credit losses on joint interest receivables have been immaterial.

Interest Rate Risk. Our exposure to changes in interest rates relates primarily to variable-rate borrowings we may have outstanding from time to time under our credit facility. Such borrowings bear interest at market-based interest rates plus a margin based on the terms of the borrowing and the credit ratings assigned to our senior, unsecured, long-term indebtedness. All of our other long-term indebtedness is fixed rate and does not expose us to the risk of cash flow loss due to changes in market interest rates.

We had no outstanding borrowings on our credit facility at July 28, 2022.

We manage our interest rate exposure by monitoring both the effects of market changes in interest rates and the proportion of our debt portfolio that is variable-rate versus fixed-rate debt. We may utilize interest rate derivatives to alter interest rate exposure in an attempt to reduce interest rate expense related to existing debt issues. Interest rate derivatives may be used solely to modify interest rate exposure and not to modify the overall leverage of the debt portfolio. We currently have no interest rate derivatives.

ITEM 4. Controls and Procedures

Evaluation of Disclosure Controls and Procedures

As of the end of the period covered by this report, an evaluation of the effectiveness of the design and operation of the Company’s disclosure controls and procedures (as defined in Rule 13a-15(e) under the Securities Exchange Act of 1934, as amended (the “Exchange Act”)) was performed under the supervision and with the participation of the Company’s management, including its Chief Executive Officer and Chief Financial Officer. Based on that evaluation, our Chief Executive Officer and Chief Financial Officer concluded the Company’s disclosure controls and procedures were effective as of June 30, 2022 to ensure information required to be disclosed in the reports it files and submits under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms, and information required to be disclosed under the Exchange Act is accumulated and communicated to the Company’s management, including its Chief Executive Officer and Chief Financial Officer, as appropriate to allow timely decisions regarding required disclosure.

Changes in Internal Control over Financial Reporting

During the three months ended June 30, 2022, there were no changes in our internal control over financial reporting (as such term is defined in Rules 13a-15(f) and 15d-15(f) under the Exchange Act) that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

Inherent Limitations on Controls and Procedures

A control system, no matter how well conceived and operated, can provide only reasonable, not absolute, assurance that the objectives of the control system are met. Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risks that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate. Accordingly, even an effective system of internal control will provide only reasonable assurance that the objectives of the internal control system are met.

PART II. Other Information

ITEM 1. Legal Proceedings

See Note 9. Commitments and Contingencies in Notes to Unaudited Condensed Consolidated Financial Statements for a case filed in the Northern District of California and a case filed in Oklahoma state court, which are incorporated herein by reference.

ITEM 1A. Risk Factors

In addition to the information set forth in this Form 10-Q, you should carefully consider the risk factors discussed in Part I, Item 1A. Risk Factors in our 2021 Form 10-K, which could materially affect our business, financial condition or future results. The risks described in this Form 10-Q and in our 2021 Form 10-K are not the only risks facing our Company. Additional risks and uncertainties not currently known to us or that we currently deem to be immaterial also may materially adversely affect our business, financial condition or future results.

A discussion of material changes in our risk factors from those disclosed in our 2021 Form 10-K is as follows.

The take-private transaction proposed by Harold G. Hamm, on behalf of himself, the Harold G. Hamm Trust and certain trusts established for the benefit of Mr. Hamm’s family members (collectively, the “Hamm Family”) may not occur, may increase the volatility of the market price of our common stock, and will result in certain costs and expenses.

On June 14, 2022, the Board received a non-binding proposal from the Hamm Family pursuant to which the Hamm Family would purchase all of the outstanding shares of common stock of the Company, other than shares owned by the Hamm Family and shares underlying unvested equity awards issued under the Company’s long term incentive plans, at a price of $70.00 per share.

The Hamm Family’s proposal provides that no legally binding obligation with respect to any transaction will exist unless and until mutually acceptable definitive documentation is executed and delivered with respect thereto. There can be no assurance that the transaction proposed by the Hamm Family will result in a transaction occurring, its timing, or ultimate terms.

The market price of our common stock may reflect various assumptions as to whether the proposed transaction with the Hamm Family will occur. Variations in the market price of our common stock may occur as a result of changing assumptions regarding the proposed transaction, independent of changes in our business, financial condition or prospects or changes in general market or economic conditions. As a result, the announcement of the execution of a definitive agreement regarding a transaction, or of a failure to reach a definitive agreement regarding a transaction, could result in a significant change in the market price of our common stock.

We expect to incur costs in connection with the consideration of the Hamm Family’s proposal, including costs of financial and legal advisors. Transactions such as the one proposed in the Hamm Family’s proposal often attract litigation and the Company may be required to expend additional resources defending such litigation. It is difficult to estimate the aggregate amount of such costs, although they could be substantial. In addition, if the take-private transaction is consummated we expect to incur additional debt to fund a portion of the transaction. The incurrence of debt may adversely impact our liquidity and financial flexibility and hinder our ability to fully implement our business plans or take advantage of business opportunities. In addition, uncertainty associated with the potential transaction could adversely affect the Company's ability to attract, retain and motivate key employees, which could have a negative effect on our operations and business plans.

ITEM 2. Unregistered Sales of Equity Securities and Use of Proceeds

(a)Recent Sales of Unregistered Securities – Not applicable.

(b)Use of Proceeds – Not applicable.

(c)Purchases of Equity Securities by the Issuer and Affiliated Purchasers – The table below provides information about purchases of shares of our common stock during the three months ended June 30, 2022.


Period	Total number of shares purchased	Average price paid per share		Total number of shares purchased as part of publicly announced plans or programs (1)	Maximum dollar value of shares that may yet be purchased under the plans or programs (in millions) (1)
April 1, 2022 to April 30, 2022:
Repurchases for tax withholdings (2)	101,519	$	63.03	—	—
May 1, 2022 to May 31, 2022:
Repurchases for tax withholdings (2)	8,065	$	57.85	—	—

June 1, 2022 to June 30, 2022:
Repurchases for tax withholdings (2)	1,134	$	70.00	—	—


Total for the quarter	110,718	$	62.72	—

(1)In May 2019 the Board approved the initiation of a share repurchase program to acquire up to $1 billion of our common stock beginning in June 2019 at times and levels deemed appropriate by management. The program was announced on June 3, 2019 and does not have a set expiration date. On February 8, 2022, the Board approved an increase in the size of the share repurchase program to $1.5 billion. As of June 30, 2022, we have repurchased a cumulative $540.9 million of our common stock, leaving approximately $959.1 million of authorized repurchasing capacity under the modified program. The share repurchase program does not require the Company to repurchase a specific number of shares and may be modified, suspended, or terminated by the Board at any time.

(2)Amounts represent shares surrendered by employees to cover tax liabilities in connection with the vesting of restricted stock granted under the Company's 2013 Long-Term Incentive Plan. We paid the associated taxes to the applicable taxing authorities. The price paid per share was the closing price of our common stock on the date the restrictions lapsed on such shares.

ITEM 3. Defaults Upon Senior Securities

Not applicable.

ITEM 4. Mine Safety Disclosures

Not applicable.

ITEM 5. Other Information

Not applicable.

ITEM 6. Exhibits

The exhibits required to be filed pursuant to Item 601 of Regulation S-K are set forth below.


3.1						Conformed version of Third Amended and Restated Certificate of Incorporation of Continental Resources, Inc. as amended by amendments filed on June 15, 2015 and May 21, 2020 filed as Exhibit 3.1 to the Company's Form 10-Q for the quarterly period ended June 30, 2020 (Commission File No. 001-32886) filed August 3, 2020 and incorporated herein by reference.

3.2						Third Amended and Restated Bylaws of Continental Resources, Inc. filed as Exhibit 3.2 to the Company’s Form 10-K for the year ended December 31, 2017 (Commission File No. 001-32886) filed February 21, 2018 and incorporated herein by reference.

10.1†						Continental Resources, Inc. 2022 Long-Term Incentive Plan filed as Exhibit 10.1 to the Company’s Current Report on Form 8-K (Commission File No. 001-32886) filed May 19, 2022 and incorporated herein by reference.

10.2†						Form of Employee Restricted Stock Award Agreement under the Continental Resources, Inc. 2022 Long-Term Incentive Plan filed as Exhibit 10.2 to the Company’s Current Report on Form 8-K (Commission File No. 001-32886) filed May 19, 2022 and incorporated herein by reference.

10.3†						Form of Non-Employee Director Restricted Stock Award Agreement under the Continental Resources, Inc. 2022 Long-Term Incentive Plan filed as Exhibit 10.3 to the Company’s Current Report on Form 8-K (Commission File No. 001-32886) filed May 19, 2022 and incorporated herein by reference.

31.1*						Certification of the Company’s Chief Executive Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 (15 U.S.C. Section 7241).

31.2*						Certification of the Company’s Chief Financial Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 (15 U.S.C. Section 7241).

32**						Certification of the Company’s Chief Executive Officer and Chief Financial Officer Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 (18 U.S.C. Section 1350).

101.INS*						Inline XBRL Instance Document - the Inline XBRL Instance Document does not appear in the Interactive Data file because its XBRL tags are embedded within the Inline XBRL document

101.SCH*						Inline XBRL Taxonomy Extension Schema Document

101.CAL*						Inline XBRL Taxonomy Extension Calculation Linkbase Document

101.DEF*						Inline XBRL Taxonomy Extension Definition Linkbase Document

101.LAB*						Inline XBRL Taxonomy Extension Label Linkbase Document

101.PRE*						Inline XBRL Taxonomy Extension Presentation Linkbase Document

104						Cover Page Interactive Data File (formatted as Inline XBRL and contained in Exhibit 101)

* Filed herewith

** Furnished herewith

† Management contracts or compensatory plans or arrangements filed pursuant to Item 601(b)(10)(iii) of Regulation S-K.

SIGNATURE

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

CONTINENTAL RESOURCES, INC.

Date:

July 28, 2022

By:

/s/ John D. Hart

John D. Hart

Chief Financial Officer and Executive Vice President of Strategic Planning
(Duly Authorized Officer and Principal Financial Officer)