UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

(Mark One)



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

For the quarterly period ended ~~September~~June 30, ~~2017~~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.~~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~~

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 ~~and posted on its corporate Web site, if any,~~ every Interactive Data File required to be submitted ~~and posted~~ 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 ~~and post~~ 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

☐

~~Large accelerated filer~~

~~Accelerated filer~~

~~Non-accelerated filer~~

¨ ~~(Do not check if a smaller reporting company)~~

~~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

~~375,208,904~~363,001,012 shares of our $0.01 par value common stock were outstanding on ~~October 31, 2017.~~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 ~~Comprehensive Income (Loss)~~Operations	2
	Unaudited Condensed Consolidated ~~Statement~~Statements of ~~Shareholders’~~ Equity	3
	Unaudited Condensed Consolidated Statements of Cash Flows	45
	Notes to Unaudited Condensed Consolidated Financial Statements	56
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	1921
Item 3.	Quantitative and Qualitative Disclosures About Market Risk	3335
Item 4.	Controls and Procedures	3536

PART II. Other Information
Item 1.	Legal Proceedings	3637
Item 1A.	Risk Factors	3637
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	3638
Item 3.	Defaults Upon Senior Securities	3638
Item 4.	Mine Safety Disclosures	3638
Item 5.	Other Information	3638
Item 6.	Exhibits	3739
	Signature	3840

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.

~~“DD&A”~~ ~~Depreciation, depletion, amortization and accretion.~~

“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.

~~“enhanced recovery”~~ The recovery of crude oil and natural gas through the injection of liquids or gases into the reservoir, supplementing its natural energy. Enhanced recovery methods are sometimes applied when production slows due to depletion of the natural pressure.

“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.

~~“horizontal drilling”~~ ~~A drilling technique used in certain formations where a well is drilled vertically to a certain depth and then drilled horizontally within a specified interval.~~

“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.

~~“productive well”~~ ~~A well found to be capable of producing hydrocarbons in sufficient quantities such that proceeds from the sale of the production exceed production expenses and taxes.~~

~~“prospect”~~ A potential geological feature or formation which geologists and geophysicists believe may contain hydrocarbons. A prospect can be in various stages of evaluation, ranging from a prospect that has been fully evaluated and is ready to drill to a prospect that will require substantial additional seismic data processing and interpretation.

“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~~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. ~~A significant portion of our STACK acreage is located in over-pressured portions of Blaine, Dewey and Custer counties of Oklahoma.~~

“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 ~~crude oil and natural gas~~proved reserves and related development plans;

•technology;

•future ~~crude oil, natural gas liquids, and natural gas~~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;

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

•competition;

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

•transportation of crude oil, natural gas, ~~liquids,~~ 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;~~operations, including any impacts from inflation;

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

~~general economic conditions;~~•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, ~~if any,~~ our Annual Report on Form 10-K for the year ended December 31, ~~2016,~~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.

~~iii~~

PART I. Financial Information


~~ITEM 1.~~	~~Financial Statements~~

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)	0		0
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.

September 30, 2017 December 31, 2016
In thousands, except par values and share data (Unaudited)
Assets
Current assets:
Cash and cash equivalents $ 10,765
$ 16,643
Receivables:
Crude oil and natural gas sales 471,533
404,750
Affiliated parties 56
99
Joint interest and other, net 451,977
364,850
Derivative assets 11,197
4,061
Inventories 105,210
111,987
Prepaid expenses and other 10,237
10,843
Total current assets 1,060,975
913,233
Net property and equipment, based on successful efforts method of accounting 12,919,202
12,881,227
Other noncurrent assets 14,910
17,316
Total assets $ 13,995,087
$ 13,811,776

Liabilities and shareholders’ equity
Current liabilities:
Accounts payable trade $ 670,966
$ 476,342
Revenues and royalties payable 264,289
217,425
Payables to affiliated parties 146
148
Accrued liabilities and other 190,646
176,770
Derivative liabilities 1,144
59,489
Current portion of long-term debt 2,268
2,219
Total current liabilities 1,129,459
932,393
Long-term debt, net of current portion 6,612,281
6,577,697
Other noncurrent liabilities:
Deferred income tax liabilities, net 1,860,094
1,890,305
Asset retirement obligations, net of current portion 101,673
94,436
Other noncurrent liabilities 14,801
14,949
Total other noncurrent liabilities 1,976,568
1,999,690
Commitments and contingencies (Note 7)

Shareholders’ 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; 375,196,507 shares issued and outstanding at September 30, 2017; 374,492,357 shares issued and outstanding at December 31, 2016 3,752
3,745
Additional paid-in capital 1,396,854
1,375,290
Accumulated other comprehensive income (loss) 269
(260 )
Retained earnings 2,875,904
2,923,221
Total shareholders’ equity 4,276,779
4,301,996
Total liabilities and shareholders’ equity $ 13,995,087
$ 13,811,776

Continental Resources, Inc. and Subsidiaries

Unaudited Condensed Consolidated Statements of ~~Comprehensive Income (Loss)~~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.

Three months ended September 30, Nine months ended September 30,
In thousands, except per share data 2017 2016 2017 2016
Revenues:
Crude oil and natural gas sales $ 704,818
$ 505,892
$ 1,965,216
$ 1,435,194
Gain (loss) on crude oil and natural gas derivatives, net 8,602
15,668
83,482
(24,477 )
Crude oil and natural gas service operations 13,323
4,639
24,959
19,867
Total revenues 726,743
526,199
2,073,657
1,430,584

Operating costs and expenses:
Production expenses 84,514
67,022
239,842
219,745
Production taxes 51,264
34,583
134,462
104,216
Exploration expenses 1,389
3,987
9,591
8,726
Crude oil and natural gas service operations 3,349
2,605
10,664
9,224
Depreciation, depletion, amortization and accretion 420,243
414,671
1,198,169
1,320,423
Property impairments 35,130
57,689
209,819
202,728
General and administrative expenses 44,006
44,389
130,413
113,043
Net (gain) loss on sale of assets and other (4,905 ) (5,564 ) 764
(104,690 )
Total operating costs and expenses 634,990
619,382
1,933,724
1,873,415
Income (loss) from operations 91,753
(93,183 ) 139,933
(442,831 )
Other income (expense):
Interest expense (74,756 ) (82,074 ) (218,672 ) (244,949 )
Other 394
360
1,209
1,178

(74,362 ) (81,714 ) (217,463 ) (243,771 )
Income (loss) before income taxes 17,391
(174,897 ) (77,530 ) (686,602 )
(Provision) benefit for income taxes (6,770 ) 65,276
25,063
259,254
Net income (loss) $ 10,621
$ (109,621 ) $ (52,467 ) $ (427,348 )
Basic net income (loss) per share $ 0.03
$ (0.30 ) $ (0.14 ) $ (1.15 )
Diluted net income (loss) per share $ 0.03
$ (0.30 ) $ (0.14 ) $ (1.15 )

Comprehensive income (loss):
Net income (loss) $ 10,621
$ (109,621 ) $ (52,467 ) $ (427,348 )
Other comprehensive income, net of tax:
Foreign currency translation adjustments 202
418
529
869
Total other comprehensive income, net of tax 202
418
529
869
Comprehensive income (loss) $ 10,823
$ (109,203 ) $ (51,938 ) $ (426,479 )

Continental Resources, Inc. and Subsidiaries

Unaudited Condensed Consolidated ~~Statement~~Statements of ~~Shareholders’~~ 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)

In thousands, except share data Shares
outstanding Common
stock Additional
paid-in
capital Accumulated
other
comprehensive
income (loss) Retained
earnings Total
shareholders’
equity
Balance at December 31, 2016 374,492,357
$ 3,745
$ 1,375,290
$ (260 ) $ 2,923,221
$ 4,301,996
Cumulative effect adjustment from adoption of ASU 2016-09 (unaudited) (see Note 2) —
—
—
—
5,150
5,150
Net loss (unaudited) —
—
—
—
(52,467 ) (52,467 )
Other comprehensive income, net of tax (unaudited) —
—
—
529
—
529
Stock-based compensation (unaudited) —
—
32,547
—
—
32,547
Restricted stock:
Granted (unaudited) 1,518,824
15
—
—
—
15
Repurchased and canceled (unaudited) (241,060 ) (2 ) (10,983 ) —
—
(10,985 )
Forfeited (unaudited) (573,614 ) (6 ) —
—
—
(6 )
Balance at September 30, 2017 (unaudited) 375,196,507
$ 3,752
$ 1,396,854
$ 269
$ 2,875,904
$ 4,276,779


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.

Nine months ended September 30,
In thousands 2017 2016
Cash flows from operating activities
Net loss $ (52,467 ) $ (427,348 )
Adjustments to reconcile net loss to net cash provided by operating activities:
Depreciation, depletion, amortization and accretion 1,199,715
1,322,280
Property impairments 209,819
202,728
Non-cash (gain) loss on derivatives, net (65,481 ) 105,009
Stock-based compensation 32,490
34,274
Benefit for deferred income taxes (25,063 ) (259,256 )
Tax deficiency from stock-based compensation —
9,460
Dry hole costs 157
233
Gain on sale of assets, net (703 ) (103,174 )
Other, net 7,705
7,166
Changes in assets and liabilities:
Accounts receivable (154,790 ) (2,634 )
Inventories 6,736
1,257
Other current assets 729
390
Accounts payable trade 128,337
(43,131 )
Revenues and royalties payable 48,447
(11,102 )
Accrued liabilities and other 13,050
22,411
Other noncurrent assets and liabilities (700 ) 5,325
Net cash provided by operating activities 1,347,981
863,888

Cash flows from investing activities
Exploration and development (1,444,991 ) (878,928 )
Purchase of producing crude oil and natural gas properties (3,480 ) (29 )
Purchase of other property and equipment (10,508 ) (5,569 )
Proceeds from sale of assets 84,725
334,305
Net cash used in investing activities (1,374,254 ) (550,221 )

Cash flows from financing activities
Credit facility borrowings 985,000
915,000
Repayment of credit facility (952,000 ) (1,203,000 )
Repayment of other debt (1,654 ) (1,601 )
Debt issuance costs —
(40 )
Repurchase of restricted stock for tax withholdings (10,985 ) (6,540 )
Tax deficiency from stock-based compensation —
(9,460 )
Net cash provided by (used in) financing activities 20,361
(305,641 )
Effect of exchange rate changes on cash 34
7
Net change in cash and cash equivalents (5,878 ) 8,033
Cash and cash equivalents at beginning of period 16,643
11,463
Cash and cash equivalents at end of period $ 10,765
$ 19,496

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 ~~originally~~ formed in 1967 and is incorporated under the laws of the State of Oklahoma. The ~~Company's~~Company’s principal business is the exploration, development, management, and production of crude oil and natural gas ~~exploration, development~~ and ~~production~~associated products with properties primarily located in ~~the North, South, and East regions of~~four leading basins in the United States. The North region consists of properties north of Kansas and west of the Mississippi River and includes North Dakota Bakken, Montana Bakken and the Red River units. The South region includes all properties south of Nebraska and west of the Mississippi River including various plays in the SCOOP (South Central Oklahoma Oil Province) and STACK (Sooner Trend Anadarko Canadian Kingfisher) areas of Oklahoma. The East region is primarily comprised of undeveloped leasehold acreage east of the Mississippi River with no significant drilling or production operations.

A substantial portion of the Company’s operations are located in the North region, with that region comprising approximately 58% of the Company’s crude oil and natural gas production and approximately 67% of its crude oil and natural gas revenues for the nine months ended September 30, 2017. The Company's principal producing properties in the North region are located inStates – the Bakken field of North Dakota and ~~Montana. In recent years,~~Montana, the Anadarko Basin of Oklahoma, the Permian Basin of Texas, and the Powder River Basin of Wyoming. Additionally, the Company ~~has significantly expanded its operations~~pursues the acquisition and management of perpetually owned minerals located in ~~the South region with its increased activity in the SCOOP and STACK plays. The South region comprised approximately 42% of the Company's crude oil and natural gas production and approximately 33%~~certain of its ~~crude oil and natural gas revenues for~~key operating areas. For the ~~nine~~six months ended ~~September~~June 30, ~~2017.~~

~~For the nine months ended September 30, 2017,~~2022, crude oil accounted for ~~approximately 56%~~51% of the Company’s total production and ~~approximately 77%~~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 ~~its subsidiaries, all of~~entities in which ~~are 100% owned, after all significant intercompany~~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"~~10-Q”) together with the Company’s Annual Report on Form 10-K for the year ended December 31, ~~2016~~2021 (“~~2016~~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 ~~September~~June 30, ~~2017~~2022 and for the three and ~~nine~~six month periods ended ~~September~~June 30, ~~2017~~2022 and ~~2016~~2021 are unaudited. The condensed consolidated balance sheet as of December 31, ~~2016~~2021 was derived from the audited balance sheet included in the ~~2016~~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 ~~interim~~ 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 ~~(loss)~~ per share is computed by dividing net income ~~(loss)~~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

~~Continental Resources, Inc. and Subsidiaries~~

~~Notes to Unaudited Condensed Consolidated Financial Statements~~

presents the calculation of basic and diluted weighted average shares outstanding and net income ~~(loss)~~ per share attributable to the Company for the three and ~~nine~~six months ended ~~September~~June 30, ~~2017~~2022 and ~~2016.~~

2021.


	Three months ended September 30,					Nine months ended September 30,							Three months ended June 30,				Six months ended June 30,
In thousands, except per share data	2017		2016			2017			2016			In thousands, except per share data	2022		2021		2022		2021
Net income (loss) (numerator)	$	10,621	$	(109,621	)	$	(52,467	)	$	(427,348	)
Net income attributable to Continental Resources (numerator)												Net income attributable to Continental Resources (numerator)	$	1,208,747	$	289,325	$	1,806,504	$	548,967
Weighted average shares (denominator):												Weighted average shares (denominator):
Weighted average shares - basic	371,142		370,483			371,029			370,327			Weighted average shares - basic	357,575		361,347		357,871		361,069
Non-vested restricted stock (1)	1,873		—			—			—
Non-vested restricted stock												Non-vested restricted stock	3,618		2,873		4,154		2,961
Weighted average shares - diluted	373,015		370,483			371,029			370,327			Weighted average shares - diluted	361,193		364,220		362,025		364,030
Net income (loss) per share:
Net income per share attributable to Continental Resources:												Net income per share attributable to Continental Resources:
Basic	$	0.03	$	(0.30	)	$	(0.14	)	$	(1.15	)	Basic	$	3.38	$	0.80	$	5.05	$	1.52
Diluted	$	0.03	$	(0.30	)	$	(0.14	)	$	(1.15	)	Diluted	$	3.35	$	0.79	$	4.99	$	1.51

~~(1)~~

For the nine months ended September 30, 2017 the Company had a net loss and therefore the potential dilutive effect of approximately 2,558,900 weighted average non-vested restricted shares were not included in the calculation of diluted net loss per share because to do so would have been anti-dilutive to the computation. The Company also had net losses for the three and nine months ended September 30, 2016, and therefore approximately 2,176,500 and 2,083,000 weighted average non-vested restricted shares, respectively, were not included in the calculation of diluted net loss per share for those periods.

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 ~~market~~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 ~~September~~June 30, ~~2017~~2022 and December 31, ~~2016~~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

In thousands September 30, 2017 December 31, 2016
Tubular goods and equipment $ 16,709
$ 15,243
Crude oil 88,501
96,744
Total $ 105,210
$ 111,987

~~Adoption of new accounting pronouncements~~

~~Stock-based compensation –~~ ~~In March 2016, the Financial Accounting Standards Board ("FASB") issued Accounting Standards Update ("ASU") 2016-09,~~ ~~Compensation—Stock Compensation (Topic 718): Improvements to Employee Share-Based Payment Accounting~~, which changes how companies account for certain aspects of share-based payment awards, including the accounting for income taxes, forfeitures, and statutory tax withholding requirements, as well as classification in the statement of cash flows. The Company adopted the new standard on January 1, 2017 as required. The impact of adoption is described below.

ASU 2016-09 removes the requirement to delay recognition of an excess tax benefit until it reduces current taxes payable. An excess tax benefit (tax deficiency) arises when stock-based compensation expense recognized in an entity’s tax return exceeds (is less than) the expense recognized in an entity’s financial statements. Under the new standard, effective January 1, 2017 excess tax benefits are recorded when they arise. This change was required to be applied on a modified retrospective basis by recording a cumulative effect adjustment to opening retained earnings upon adoption to account for previously unrecognized excess tax benefits. The Company's cumulative effect adjustment recorded under the new standard resulted in a $5.2 million increase in retained earnings and corresponding decrease in deferred income tax liabilities at January 1, 2017.

Additionally, under ASU 2016-09 companies no longer record excess tax benefits and deficiencies in additional paid-in capital. Instead, excess tax benefits and deficiencies are recognized as income tax benefit or expense in the income statement, effective January 1, 2017 on a prospective basis. This is expected to result in increased volatility in income tax expense/benefit and corresponding variations in the relationship between income tax expense/benefit and pre-tax income/loss from period to period. The Company recognized $0.1 million ($0.00 per share) and $3.9 million ($0.01 per share) of tax deficiencies from stock-based compensation as income tax expense for the three and nine months ended September 30, 2017, respectively, under

Continental Resources, Inc. and Subsidiaries

Notes to Unaudited Condensed Consolidated Financial Statements

Note 3. Property Acquisitions

2022

On March 25, 2022, the ~~new standard, which are reflected in "(Provision) benefit for income taxes"~~Company acquired oil and gas properties in the ~~unaudited condensed consolidated statements~~Powder River Basin of ~~comprehensive income (loss).~~

~~ASU 2016-09 also removed~~Wyoming for cash consideration of $403 million, representing a $450 million purchase price less customary closing adjustments made pursuant to the requirement that entities present excess tax benefits and deficiencies as offsetting cash flows from financing and operating activities in the statement of cash flows. Instead, ASU 2016-09 requires cash flows related to excess tax benefits and deficiencies be classified as operating activities in the same manner as other cash flows related to income taxes.acquisition agreement. The Company has elected to apply this guidance on a prospective basis. Accordingly, the cash flow presentation of excess tax benefits and deficiencies in periods prior to January 1, 2017 has not been adjusted to conform to current period presentation.

The Company has elected to continue its historical accounting practice of estimating forfeitures in determining the amount of stock-based compensation expense to recognize. Therefore, the adoption of ASU 2016-09 does not have an impact on the amount of stock-based compensation expense to be recognized by the Company on non-vested restricted stock awards.

~~Business combinations~~ ~~– In January 2017, the FASB issued ASU 2017-01,~~ ~~Business Combinations (Topic 805): Clarifying the Definition of a Business~~, which changes the definition of a business to assist entities with evaluating when a set of transferred assets and activities is deemed to be a business. Determining whether a transferred set constitutes a business is important because the accounting for a business combination differs from that of an asset acquisition. The definition of a business also affects the accounting for dispositions. Under the new standard, when substantially all of the fair value of assets acquired is concentrated in a single asset, or a group of similar assets, the assets acquired would not represent a business and business combination accounting would not be required. The new standard may result in more transactions beingacquisition was accounted for as an asset ~~acquisitions rather than business combinations. The standard is effective for interim~~acquisition under ASC Topic 805 and ~~annual periods beginning after December 15, 2017~~included approximately 172,000 net leasehold acres and ~~shall be applied prospectively.~~producing properties with production totaling approximately 18,000 barrels of oil equivalent per day at the time of closing. The Company ~~early adopted ASU 2017-01~~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 ~~January 1, 2017, which had no significant impact on the Company's financial statements as of and for the three and nine months ended September 30, 2017.~~

~~New accounting pronouncements not yet adopted~~

~~Revenue recognition and presentation~~ ~~– In May 2014, the FASB issued ASU 2014-09,~~ ~~Revenue from Contracts~~undeveloped leasehold acreage with ~~Customers (Topic 606), which generally requires~~ an ~~entity to identify performance obligations in its contracts, estimate the~~immaterial amount of ~~consideration to be received~~production.

2021

In March 2021, the Company acquired oil and gas properties in the ~~transaction price, allocate~~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 ~~transaction price to each separate performance obligation,~~definitive purchase agreement and ~~recognize revenue~~a $185.1 million payment made at closing in March 2021. The acquisition was accounted for as ~~obligations are satisfied. Additionally,~~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 ~~standard requires expanded disclosures related to revenue recognition.~~

~~Subsequent to the issuance~~time of ASU 2014-09, the FASB issued various clarifications and interpretive guidance to assist entities with implementation efforts, including guidance pertaining to the presentation of revenues on a gross basis (revenues presented separately from associated expenses) versus a net basis. Under this guidance, an entity generally shall record revenue on a gross basis if it controls a promised good or service before transferring it to a customer, whereas an entity shall record revenue on a net basis if its role is to arrange for another entity to provide the goods or services to a customer. Significant judgment may be required in some circumstances to determine whether gross or net presentation is appropriate.

ASU 2014-09 and related interpretive guidance will be effective for interim and annual periods beginning after December 15, 2017 and allows for either full retrospective adoption, meaning the standard is applied to all periods presented in the financial statements, or modified retrospective adoption, meaning the standard is applied only to the most current period presented.closing. The Company ~~plans to adopt the standard on January 1, 2018 using the modified retrospective approach.~~

~~The Company is nearing completion~~recognized approximately $4.9 million of ~~its evaluation~~asset retirement obligations and $8.2 million of ~~the impact of the new standard~~right-of-use assets and related interpretive guidance on its financial statements, accounting policies, internal controls, and disclosures. Based on assessments performed to date, the standard is not expected to have a material effect on the timing of the Company's revenue recognition or its financial position, results of operations, net income, or cash flows, but is expected to have an impact on the Company's revenue-related disclosures and internal controls over financial reporting. Additionally, the standard is expected to impact the presentation of future revenues and expenses under the gross-versus-net presentation guidance. Historically, the Company has generally presented its revenues net of transportation costs. The new guidance is expected to result in future revenues andcorresponding lease liabilities associated transportation expenses for certain of the Company's operated properties being reported on a gross basis. The Company expects changes from net to gross presentation will result in an increase in revenues and a corresponding increase in separately reported transportation expenses, with no net effect on the Company's results of operations, net income, or cash flows. For the three and nine months ended September 30, 2017, the Company had approximately $50.3 million and $148.2 million, respectively, of transportation-related charges on operated properties included in "Crude oil and natural gas sales" on the unaudited condensed consolidated statements of comprehensive income (loss). These amounts are not necessarily indicative of amounts to be expected in future periods. The Company is not currently able to estimate the impact on the presentation of its future revenues and expenses under the new guidance due to uncertainties with respect to future sales volumes, service costs, locations of

~~Continental Resources, Inc. and Subsidiaries~~

~~Notes to Unaudited Condensed Consolidated Financial Statements~~

producing properties, sales destinations, transportation methods utilized, and changes in the nature, timing, and extent of its arrangements from period to period. Ongoing interpretive developments are being monitored which may impact the Company's financial statement presentation and disclosures.

~~Leases~~ ~~– In February 2016, the FASB issued ASU 2016-02,~~ ~~Leases (Topic 842)~~, which requires companies to recognize a right of use asset and related liability on the balance sheet for the rights and obligations arising from leases with durations greater than 12 months. The standard is effective for interim and annual reporting periods beginning after December 15, 2018 and requires adoption by application of a modified retrospective transition approach.

The Company continues to evaluate the impact of ASU 2016-02 on its financial statements, accounting policies and internal controls and is in the process of developing systems and processes to identify, classify, and account for leases within the scope of the new guidance and to comply with the related disclosure requirements. Standard setting guidance and interpretations continue to evolve and are being monitored for applicability and impact to the Company's business and industry. Based on an initial review of the new guidance and the Company’s current commitments, the Company anticipates it may be required to recognize lease assets and liabilities related to drilling rig commitments, certain equipment rentals and leases, certain future surface use agreements, and potentially certain firm transportation agreements, as well as other arrangements, the effect of which cannot be estimated at this time.acquired properties.

~~Credit losses~~ ~~– In June 2016, the FASB issued ASU 2016-13,~~ ~~Financial Instruments~~–~~Credit Losses (Topic 326): Measurement of Credit Losses on Financial Instruments~~. This standard changes how entities will measure credit losses for most financial assets and certain other instruments that are not measured at fair value through net income. The standard will replace the currently required incurred loss approach with an expected loss model for instruments measured at amortized cost. The standard is effective for interim and annual periods beginning after December 15, 2019 and shall be applied using a modified retrospective approach resulting in a cumulative effect adjustment to retained earnings upon adoption. The Company continues to evaluate the new standard and is unable to estimate its financial statement impact at this time. Historically, the Company's credit losses on crude oil and natural gas sales receivables and joint interest receivables have been immaterial.

Note 3.4. 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

Nine months ended September 30,
In thousands 2017 2016
Supplemental cash flow information:
Cash paid for interest $ 198,405
$ 213,969
Cash paid for income taxes 2
—
Cash received for income tax refunds 148
174
Non-cash investing activities:
Asset retirement obligation additions and revisions, net 5,111
1,645
(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 ~~September~~June 30, ~~2017~~2022 and December 31, ~~2016,~~2021, the Company ~~had $289.9~~had $293.2 million ~~and $223.6~~ and $242.9 million, respectively, of accrued capital expenditures included in ~~"Net~~“Net property and ~~equipment" and "Accounts~~equipment” with an offsetting amount in “Accounts payable ~~trade"~~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 4.6. Derivative Instruments

~~Crude oil and natural gas derivatives~~

~~The~~From time to time the Company ~~may utilize crude oil and natural gas swap and collar~~enters into derivative contracts to economically hedge against the variability in cash flows associated with future sales of ~~crude oil and natural gas~~ production. ~~While the use of these derivative instruments limits the downside risk of adverse price movements, their use also limits future revenues from upward price movements.~~

The Company recognizes all derivative instruments on the balance sheet as either assets or liabilities measured at fair value. The Company has not designated its crude oil and natural gas derivative instruments as hedges for accounting purposes and, as a result, marks such derivative instruments to fair value and recognizes the changes in fair value in the unaudited

~~Continental Resources, Inc. and Subsidiaries~~

~~Notes to Unaudited Condensed Consolidated Financial Statements~~

~~condensed consolidated statements of comprehensive income (loss) under the caption “Gain (loss) on crude oil and natural gas derivatives, net”.~~

The estimated fair value of derivative contracts is based upon various factors, including commodity exchange prices, over-the-counter quotations, and, in the case of collars and written call options, volatility, the risk-free interest rate, and the time to expiration. The calculation of the fair value of collars and written call options requires the use of an option-pricing model. See ~~Note 5. Fair Value Measurements~~.

With respect to a crude oil or natural gas fixed price swap contract, the counterparty is required to make a payment to the Company if the settlement price for any settlement period is less than the swap price, and the Company is required to make a payment to the counterparty if the settlement price for any settlement period is greater than the swap price. For a crude oil or natural gas collar contract, the counterparty is required to make a payment to the Company if the settlement price for any settlement period is below the floor price, and the Company is required to make a payment to the counterparty if the settlement price for any settlement period is above the ceiling price. Neither party is required to make a payment to the other party if the settlement price for any settlement period is between the floor price and the ceiling price.

At September 30, 2017, the Company had outstanding natural gas derivative contracts as set forth in the table below. The volumes reflected below represent an aggregation of multiple derivative contracts having similar remaining durations expected to be realized ratably over the respective 2017 and 2018 periods. At September 30, 2017 the Company had no outstanding crude oil derivative contracts.

Collars
Natural Gas - NYMEX Henry Hub Swaps Weighted Average Price Floors Ceilings
Weighted Average Price Weighted Average Price
Period and Type of Contract MMBtus Range Range
October 2017 - December 2017
Swaps - Henry Hub 33,120,000
$ 3.39

Collars - Henry Hub 16,560,000
$2.40 - $3.00 $ 2.47
$2.92 - $3.88 $ 3.08
January 2018 - March 2018
Swaps - Henry Hub 6,300,000
$ 3.28

~~Crude oil and natural gas derivative gains and losses~~

Cash receipts and payments in the following table reflect the gain or loss on derivative contracts which matured during the period, calculated as the difference between the contract price and the market settlement price of matured contracts. Non-cash gains and losses below represent the change in fair value of derivative instruments which continue to be held at period end and the reversal of previously recognized non-cash gains or losses on derivative contracts that matured during the period.

Three months ended September 30, Nine months ended September 30,
In thousands 2017 2016 2017 2016
Cash received (paid) on derivatives:
Natural gas fixed price swaps $ 12,893
$ 5,174
$ 25,080
$ 83,141
Natural gas collars (612 ) —
(10,068 ) —
Cash received on derivatives, net 12,281
5,174
15,012
83,141
Non-cash gain (loss) on derivatives:
Crude oil written call options —
—
—
38
Natural gas fixed price swaps (8,026 ) 5,298
27,390
(93,617 )
Natural gas collars 4,347
5,196
41,080
(14,039 )
Non-cash gain (loss) on derivatives, net (3,679 ) 10,494
68,470
(107,618 )
Gain (loss) on crude oil and natural gas derivatives, net $ 8,602
$ 15,668
$ 83,482
$ (24,477 )

~~Diesel fuel derivatives~~

The Company has entered into diesel fuel swap derivative contracts to economically hedge against the variability in cash flows associated with future purchases of diesel fuel for use in drilling activities. The Company has hedged approximately three million gallons of diesel fuel over the period from October 2017 to December 2017 at a weighted average price of $1.45

~~Continental Resources, Inc. and Subsidiaries~~

~~Notes to Unaudited Condensed Consolidated Financial Statements~~

per gallon. With respect to these diesel fuel swap contracts, the counterparty is required to make a payment to the Company if the settlement price for any settlement period is greater than the swap price, and the Company is required to make a payment to the counterparty if the settlement price for any settlement period is less than the swap price. The diesel fuel swap contracts are settled based upon reported NYMEX settlement prices for New York Harbor ultra-low sulfur diesel fuel.

The Company recognizes its ~~diesel fuel~~ 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 ~~Company has not designated its diesel fuel derivative instruments as hedges for accounting purposes and, as a result, marks~~calculation of the ~~derivative instruments to~~ fair value ~~and recognizes~~of collars requires the ~~changes in fair value~~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 ~~unaudited condensed consolidated statements of comprehensive income (loss) under the caption “Operating costs~~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 ~~expenses~~—~~Net (gain) loss on sale of assets~~losses

Cash receipts and ~~other.”~~

~~Cash receipts~~payments in the following table reflect the gains or losses on ~~diesel fuel derivatives~~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 ~~diesel fuel derivatives~~derivative instruments which ~~continue~~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 September 30, Nine months ended September 30,
In thousands 2017 2016 2017 2016
Cash received on diesel fuel derivatives $ 603
$ 100
$ 1,522
$ 100
Non-cash gain (loss) on diesel fuel derivatives 740
(531 ) (2,989 ) 2,609
Gain (loss) on diesel fuel derivatives, net $ 1,343
$ (431 ) $ (1,467 ) $ 2,709


	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”, “Noncurrent derivative assets”,~~assets,” “Derivative ~~liabilities”,~~assets, noncurrent,” “Derivative liabilities,” and ~~“Noncurrent derivative liabilities”,~~“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 ~~crude oil, natural gas, and diesel fuel~~ 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

In thousands September 30, 2017 December 31, 2016
Commodity derivative assets:
Gross amounts of recognized assets $ 12,229
$ 4,061
Gross amounts offset on balance sheet (1,032 ) —
Net amounts of assets on balance sheet 11,197
4,061
Commodity derivative liabilities:
Gross amounts of recognized liabilities (2,176 ) (59,489 )
Gross amounts offset on balance sheet 1,032
—
Net amounts of liabilities on balance sheet $ (1,144 ) $ (59,489 )

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

In thousands September 30, 2017 December 31, 2016
Derivative assets $ 11,197
$ 4,061
Noncurrent derivative assets —
—
Net amounts of assets on balance sheet 11,197
4,061
Derivative liabilities (1,144 ) (59,489 )
Noncurrent derivative liabilities —
—
Net amounts of liabilities on balance sheet (1,144 ) (59,489 )
Total derivative assets (liabilities), net $ 10,053
$ (55,428 )

~~Continental Resources, Inc. and Subsidiaries~~

~~Notes to Unaudited Condensed Consolidated Financial Statements~~

Note 5.7. 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. ~~The Company’s policy is to recognize transfers between the hierarchy levels as of the beginning of the reporting period in which the event or change in circumstances caused the transfer.~~

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 ~~financial~~derivative instruments by pricing levels that were accounted for at fair value on a recurring basis as of ~~September~~June 30, ~~2017~~2022 and December 31, ~~2016.~~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 September 30, 2017 using:											Fair value measurements at December 31, 2021 using:
In thousands	Level 1		Level 2			Level 3		Total			In thousands	Level 1		Level 2		Level 3		Total
Derivative assets (liabilities):											Derivative assets (liabilities):
Swaps	$	—	$	12,104		$	—	$	12,104
Collars	—		(2,051		)	—		(2,051		)
Natural gas fixed price swaps (HH)											Natural gas fixed price swaps (HH)	$	—	$	27,608	$	—	$	27,608
Natural gas basis swaps (NGPL TXOK)											Natural gas basis swaps (NGPL TXOK)	—		(177)		—		$	(177)
Natural gas collars (HH)											Natural gas collars (HH)	—		3,986		—		$	3,986
Natural gas 3-way collars (HH)											Natural gas 3-way collars (HH)	—		1,931		—		$	1,931
Crude oil NYMEX roll swaps											Crude oil NYMEX roll swaps	—		957		—		$	957
Total	$	—	$	10,053		$	—	$	10,053		Total	$	—	$	34,305	$	—	$	34,305

	Fair value measurements at December 31, 2016 using:
In thousands	Level 1		Level 2			Level 3		Total
Derivative liabilities:
Swaps	$	—	$	(12,297	)	$	—	$	(12,297	)
Collars	—		(43,131		)	—		(43,131		)
Total	$	—	$	(55,428	)	$	—	$	(55,428	)

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.

~~Continental Resources, Inc. and Subsidiaries~~

~~Notes to Unaudited Condensed Consolidated Financial Statements~~

Asset ~~Impairments~~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. ~~The~~Significant unobservable inputs (Level 3) utilized in the determination of discounted ~~cash flow method estimates~~ future net cash flows ~~based on the Company's estimates of~~include future ~~crude oil and natural gas production,~~ commodity prices ~~based on commodity futures price strips~~ adjusted for differentials, forecasted production based on decline curve analysis, estimated future operating and development costs, property ownership interests, and a ~~risk-adjusted~~10% discount rate. ~~The fair value of proved crude oil~~At June 30, 2022, the Company's commodity price assumptions were based on forward NYMEX strip prices through year-end 2026 and natural gas properties is calculated using significant unobservable inputs (Level 3). The following table sets forth quantitative information about the significant unobservable inputs used by the Company to calculate the fair value of proved crude oil and natural gas properties using a discounted cash flow method.



~~Unobservable Input~~		~~Assumption~~
~~Future production~~		~~Future production estimates for each property~~
~~Forward commodity prices~~		~~Forward NYMEX strip prices through 2021 (adjusted for differentials), escalating 3% per year thereafter~~
~~Operating costs~~		~~Estimated costs for the current year, escalating 3% per year thereafter~~
~~Productive life of field~~		~~Ranging from 0 to 39 years~~
~~Discount rate~~		~~10%~~

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 ~~assessment~~assessments are reviewed ~~quarterly~~ and ~~are~~ revised as warranted based on a number of factors, including reservoir performance, new drilling, ~~crude oil and natural gas~~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 ~~nine~~six months ended ~~September~~June 30, ~~2017 and 2016,~~2022, the Company determined the carrying ~~amounts~~amount of ~~certain proved properties were~~a property in an emerging play was not recoverable from future cash flows and therefore ~~were impaired. Impairments~~was impaired in the amount of ~~proved properties amounted to $82.3~~$11.8 million, ~~for the nine months ended September 30, 2017,~~ all of which ~~were~~was recognized ~~prior to~~in the ~~2017 third~~2022 first quarter. For the three and six months ended ~~September~~June 30, ~~2017,~~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~~Company's proved crude oil and natural gas properties for ~~that period. The 2017 year to date impairments reflect fair value adjustments primarily concentrated in~~ the Arkoma Woodford field ($81.2 million, all in the second quarter) and various non-core areas in the North and South regions ($1.1 million). The impaired properties were written down to their estimated fair value at the time of impairment of approximately $72 million.2021 periods.

Impairments of proved properties totaled $2.9 million for year to date 2016, all of which were recognized in the 2016 third quarter primarily for properties in a non-core area of the North region. The impaired properties were written down to their estimated fair value at the time of impairment of approximately $0.7 million.

Certain unproved crude oil and natural gas properties were impaired during the three and ~~nine~~six months ended ~~September~~June 30, ~~2017~~2022 and ~~2016,~~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 ~~comprehensive income (loss).~~

Three months ended September 30, Nine months ended September 30,
In thousands 2017 2016 2017 2016
Proved property impairments $ —
$ 2,895
$ 82,340
$ 2,895
Unproved property impairments 35,130
54,794
127,479
199,833
Total $ 35,130
$ 57,689
$ 209,819
$ 202,728

~~Continental Resources, Inc. and Subsidiaries~~

~~Notes to Unaudited Condensed Consolidated Financial Statements~~

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.


	September 30, 2017				December 31, 2016					June 30, 2022				December 31, 2021
In thousands	Carrying Amount		Estimated Fair Value		Carrying Amount		Estimated Fair Value		In thousands	Carrying Amount		Estimated Fair Value		Carrying Amount		Estimated Fair Value
Debt:									Debt:
Revolving credit facility	$	938,000	$	938,000	$	905,000	$	905,000
Term loan	499,329		500,000		498,865		500,000
Note payable	10,531		10,500		12,176		10,200
5% Senior Notes due 2022	1,997,476		2,030,700		1,997,188		2,020,400
Credit facility									Credit facility	$	—	$	—	$	500,000	$	500,000
Notes payable									Notes payable	21,207		19,800		22,356		22,000
4.5% Senior Notes due 2023	1,486,134		1,508,900		1,484,524		1,474,800		4.5% Senior Notes due 2023	635,056		636,900		648,078		670,200
3.8% Senior Notes due 2024	991,764		968,400		990,964		929,400		3.8% Senior Notes due 2024	890,819		885,300		908,061		950,000
2.268% Senior Notes due 2026									2.268% Senior Notes due 2026	793,337		708,500		792,621		795,200
4.375% Senior Notes due 2028									4.375% Senior Notes due 2028	992,471		939,900		991,880		1,082,100
5.75% Senior Notes due 2031									5.75% Senior Notes due 2031	1,483,070		1,447,300		1,482,319		1,769,600
2.875% Senior Notes due 2032									2.875% Senior Notes due 2032	791,876		627,900		791,521		780,500
4.9% Senior Notes due 2044	691,315		635,400		691,199		607,600		4.9% Senior Notes due 2044	692,155		555,200		692,056		781,500
Total debt	$	6,614,549	$	6,591,900	$	6,579,916	$	6,447,400	Total debt	$	6,299,991	$	5,820,800	$	6,828,892	$	7,351,100

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

The fair values of the ~~5% Senior Notes due 2022 (“2022 Notes”), the 4.5% Senior Notes due 2023 (“2023 Notes”), the 3.8% Senior Notes due 2024 (“2024 Notes”), and the 4.9% Senior Notes due 2044 (“2044 Notes”)~~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 ~~6. Long-Term~~8. Debt

~~Long-term~~The Company's debt, net of unamortized discounts, premiums, and debt issuance costs totaling ~~$34.0~~$50.4 millionand ~~$37.3~~$54.2 million at ~~September~~June 30, ~~2017~~2022 and December 31, ~~2016,~~2021, respectively, consists of the following.

In thousands September 30, 2017 December 31, 2016
Revolving credit facility $ 938,000
$ 905,000
Term loan 499,329
498,865
Note payable 10,531
12,176
5% Senior Notes due 2022 1,997,476
1,997,188
4.5% Senior Notes due 2023 1,486,134
1,484,524
3.8% Senior Notes due 2024 991,764
990,964
4.9% Senior Notes due 2044 691,315
691,199
Total debt $ 6,614,549
$ 6,579,916
Less: Current portion of long-term debt 2,268
2,219
Long-term debt, net of current portion $ 6,612,281
$ 6,577,697


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

~~Revolving~~ (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 ~~revolving~~ credit facility, maturing ~~on May 16, 2019,~~in October 2026, with aggregate lender commitments totaling ~~$2.75~~$2.0 billion, ~~at September 30, 2017,~~ 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.

~~Continental Resources, Inc. and Subsidiaries~~

~~Notes to Unaudited Condensed Consolidated Financial Statements~~

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 ~~weighted-average interest rate on outstanding credit facility borrowings at September 30, 2017 was 2.99%.~~

~~The~~ Company ~~had approximately $1.81 billion of borrowing availability on its revolving credit facility at September 30, 2017 and~~ incurs commitment fees based on currently assigned credit ratings of ~~0.30%~~0.20% per annum on the daily average amount of unused borrowing ~~availability under its revolving credit facility.~~availability.

The ~~revolving~~ 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 ~~revolving~~ credit facility covenants at ~~September~~June 30, ~~2017.~~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 ~~September~~June 30, ~~2017.~~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

2022 Notes (1) 2023 Notes 2024 Notes 2044 Notes
Face value (in thousands) $2,000,000 $1,500,000 $1,000,000 $700,000
Maturity date    Sep 15, 2022 April 15, 2023 June 1, 2024 June 1, 2044
Interest payment dates    March 15, Sep 15 April 15, Oct 15 June 1, Dec 1 June 1, Dec 1
Make-whole redemption period (2)    — Jan 15, 2023 Mar 1, 2024 Dec 1, 2043
(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.


~~(1)~~	The Company has the option to redeem all or a portion of its 2022 Notes at the decreasing redemption prices specified in the indenture related to the 2022 Notes plus any accrued and unpaid interest to the date of redemption.

~~(2)~~

At any time prior to these 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 prices or amounts specified in the respective senior note indentures plus any accrued and unpaid interest to the date of redemption. On or after these dates, the Company may redeem all or a portion of its senior notes at a redemption price 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~~Company’s senior notes contain covenants that, among other things, limit the ~~Company's~~Company’s ability to create liens securing certain indebtedness, enter into certain sale-leaseback transactions, or consolidate, merge or transfer certain assets. ~~The senior note~~These covenants are subject to a number of important exceptions and qualifications. The Company was in compliance with these covenants at ~~September~~June 30, ~~2017. Three~~2022.

The senior notes are obligations of Continental Resources, Inc. Additionally, certain of the Company’s wholly-owned subsidiaries ~~Banner~~(Banner Pipeline Company, L.L.C., CLR Asset Holdings, LLC, ~~and~~ The Mineral Resources Company, ~~which have no material assets or operations,~~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, ~~the value of~~ whose assets, equity, and results of operations attributable to the Company are ~~minor,~~not material, do not guarantee the senior notes.

~~Term Loan~~Retirement of Senior Notes

2022

In ~~November 2015,~~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 ~~$500~~an aggregate of $26.0 million under a three-year term loan agreement, the proceeds of which were used to repay a portion of the borrowings then outstanding on the Company's revolving credit facility. The term loan matures in full on November 4, 2018 and bears interest at a variable market-based interest rate 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 interest rate on the term loan at September 30, 2017 was 2.76%.

The term loan 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, consistent with the covenant requirement in the Company's revolving credit facility. The Company was in compliance with the term loan covenants at September 30, 2017.

~~Note Payable~~

~~In February 2012, 20 Broadway Associates LLC, a 100% owned subsidiary of the Company, borrowed $22 million under a~~two 10-year amortizing term ~~loan~~loans secured by the Company’s corporate office building and its interest in parking facilities in Oklahoma City, Oklahoma. The

~~Continental Resources, Inc.~~ loans mature in May 2030 and ~~Subsidiaries~~

~~Notes to Unaudited Condensed Consolidated Financial Statements~~

~~loan bears~~bear interest at a fixed rate of ~~3.14%~~3.50% per ~~annum.~~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 ~~loan’s~~ maturity date ~~of February 26, 2022. Accordingly, approximately $2.3~~and, accordingly, $2.4 million is ~~reflected~~included as a current liability ~~under~~in the caption “Current portion of long-term debt” in the condensed consolidated balance sheets as of ~~September~~June 30, ~~2017.~~2022 associated with the loans.

Note 7.9. Commitments and Contingencies

Included below is a discussion of various future commitments of the Company as of September 30, 2017. The commitments under these arrangements are not recorded in the accompanying condensed consolidated balance sheets.

~~Drilling commitments –~~ As of September 30, 2017, the Company has drilling rig contracts with various terms extending to February 2020 to ensure rig availability in its key operating areas. Future commitments as of September 30, 2017 total approximately $117 million, of which $26 million is expected to be incurred in the remainder of 2017, $61 million in 2018, $29 million in 2019, and $1 million in 2020.

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. ~~The~~Certain of the commitments, which have varying terms extending as far as ~~2028,~~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 ~~September~~June 30, ~~2017~~2022 under the arrangements amount to approximately ~~$1.2~~$1.19 billion, of which ~~$57~~$142 million is expected to be incurred in the remainder of ~~2017, $249~~2022, $273 million in ~~2018, $234~~2023, $255 million in ~~2019, $101~~2024, $164 million in ~~2020, $89~~2025, $139 million in ~~2021,~~2026, and ~~$424~~$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.

~~Litigation~~– ~~In November 2010, a putative class action was filed in the District Court of Blaine County, Oklahoma by Billy J. Strack~~ These commitments do not qualify as leases under ASC Topic 842 and Daniela A. Renner as trustees of certain named trusts and on behalf of other similarly situated parties against the Company. The Petition alleged the Company improperly deducted post-production costs from royalties paid to plaintiffs and other royalty interest owners from crude oil and natural gas wells located in Oklahoma. The plaintiffs alleged a number of claims, including breach of contract, fraud, breach of fiduciary duty, unjust enrichment, and other claims and seek recovery of compensatory damages, interest, punitive damages and attorney fees on behalf of the proposed class. On November 3, 2014, plaintiffs filed an Amended Petition that didare not add any substantive claims, but sought a “hybrid class action” in which they sought certification of certain claims for injunctive relief, reserving the right to seek a further class certification on money damages in the future. Plaintiffs filed an Amended Motion for Class Certification on January 9, 2015, that modified the proposed class to royalty owners in Oklahoma production from July 1, 1993, to the present (instead of 1980 to the present) and sought certification of over 45 separate “issues” for injunctive or declaratory relief, again, reserving the right to seek a further class certification of money damages in the future. The Company responded to the petition, its amendment, and the motions for class certification denying the allegations and raising a number of affirmative defenses and legal arguments to each of the claims and filings. Certain discovery was undertaken and the “hybrid” motion was briefed by plaintiffs and the Company. A hearingrecognized on the “hybrid” class certification was held on June 1 and 2, 2015. On June 11, 2015, the trial court certified a “hybrid” class as requested by plaintiffs. The Company appealed the trial court’s class certification order. On February 8, 2017, the Oklahoma Court of Civil Appeals reversed the trial court’s ruling on certification and remanded the case for further proceedings. The plaintiffs filed a Petition for Rehearing which was denied by the Oklahoma Court of Civil Appeals. Plaintiffs then filed a Petition for Writ of Certiorari on May 23, 2017, to the Oklahoma Supreme Court, which was denied on October 2, 2017. On October 10, 2017, Plaintiffs filed with the trial court a “Second Amended and Renewed Motion for Class Action Certification and Request that the Court to Set a Briefing Schedule Related to Class Certification.” The case remains stayed and briefing on the Second Amended motion is not anticipated in the immediate future. The Company is not currently able to estimate a reasonably possible loss or range of loss or what impact, if any, the ultimate resolution of the action will have on its financial condition, results of operations or cash flows due to the preliminary status of the matter, the complexity and number of legal and factual issues presented by the matter and uncertainties with respect to, among other things, the nature of the claims and defenses, the existence and the potential size of the class, the scope and types of the properties and agreements involved, the production years involved, and the ultimate potential outcome of the matter. It is reasonably possible one or more events may occur in the near term that could impact the Company’s ability to estimate the potential effect this matter could have, if any, on its financial condition, results of operations or cash flows. Plaintiffs have alleged underpayments in excess of $200 million that they may claim as damages, which may increase with the passage of time, a majority of which would be comprised of interest. The Company disputes plaintiffs’ claims, disputes the case meets the requirements for a class action and continues to vigorously defend the case. An unsuccessful mediation was conducted on December 7, 2015. The parties continue to negotiate a possible resolution to the case. However, it is unclear and unforeseeable whether the parties' efforts will result in settlement and the Company will continue to defend the case on all merits and certification issues and, absent settlement, intends to defend the case to a final judgment.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 ~~September~~June 30, ~~2017~~2022, and December 31, ~~2016,~~2021, the Company had ~~recorded~~recognized a liability ~~in the condensed consolidated balance sheets under the caption~~within “Other noncurrent liabilities” of ~~$6.8~~$10.0 million and ~~$6.5~~$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.~~claims.

Note 8.10. Stock-Based Compensation

~~On January 1, 2017, the Company adopted ASU 2016-09,~~ ~~Compensation—Stock Compensation (Topic 718): Improvements to Employee Share-Based Payment Accounting. See~~ ~~Note 2. Basis of Presentation and Significant Accounting Policies—Adoption of new accounting pronouncements~~ ~~for a discussion of the impact of adoption.~~

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") ~~as discussed below.~~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 ~~comprehensive income (loss),~~operations, was ~~$11.9~~$14.8 million and ~~$13.2~~$13.6 million for the three months ended ~~September~~June 30, ~~2017~~2022 and ~~2016,~~2021, respectively, and ~~$32.5~~$44.1 million and ~~$34.3~~$30.5 million for the ~~nine~~six months ended ~~September~~June 30, ~~2017~~2022 and ~~2016,~~2021, respectively.

In May ~~2013,~~2022, the Company adopted the ~~2013~~2022 Plan and reserved ~~19,680,072~~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 ~~September~~June 30, ~~2017,~~2022, the Company had ~~14,561,802~~15,762,789 shares of common stock available for long-term incentive awards to employees and directors under the ~~2013~~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 ~~one~~1 to ~~three~~3 years.

A summary of changes in non-vested restricted shares outstanding for the ~~nine~~six months ended ~~September~~June 30, ~~2017~~2022 is presented ~~below.~~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

Number of
non-vested
shares Weighted average
grant-date
fair value
Non-vested restricted shares outstanding at December 31, 2016 3,913,634
$ 37.12
Granted 1,518,824
44.66
Vested (816,408 ) 58.17
Forfeited (573,614 ) 37.36
Non-vested restricted shares outstanding at September 30, 2017 4,042,436
$ 35.67

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 ~~nine~~six months ended ~~September~~June 30, ~~2017~~2022 was approximately ~~$37.2~~$91 million. As of ~~September~~June 30, ~~2017,~~2022, there was approximately ~~$68~~$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 ~~1.4~~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 ~~9. Accumulated Other Comprehensive Income (Loss)~~13. Equity Investment

~~Adjustments resulting~~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 ~~process~~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 ~~translating foreign functional currency financial statements into U.S. dollars are~~2022 toward its $250 million commitment to Summit, which is included in ~~"Accumulated other comprehensive income (loss)" within shareholders’ equity~~the caption “Investment in ~~the condensed consolidated balance sheets and "Other comprehensive income, net of tax"~~unconsolidated affiliates” in the unaudited condensed consolidated ~~statements~~balance sheet. Upon completion of ~~comprehensive income (loss).~~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 ~~following table summarizes~~Company accounts for its investment in Summit under the ~~change in accumulated other comprehensive income (loss)~~equity method of accounting. The Company’s share of earnings/losses from its investment was immaterial for the three and ~~nine~~six months ended ~~September~~June 30, ~~2017 and 2016:~~2022.

Three months ended September 30, Nine months ended September 30,
In thousands 2017 2016 2017 2016
Beginning accumulated other comprehensive income (loss), net of tax $ 67
$ (2,903 ) $ (260 ) $ (3,354 )
Foreign currency translation adjustments 202
418
529
869
Income taxes (1) —
—
—
—
Other comprehensive income, net of tax 202
418
529
869
Ending accumulated other comprehensive income (loss), net of tax $ 269
$ (2,485 ) $ 269
$ (2,485 )


~~(1)~~	A valuation allowance has been recognized against all deferred tax assets associated with losses generated by the Company's Canadian operations, thereby resulting in no income taxes on other comprehensive income.

~~Note 10. Income Taxes~~

Income taxes are accounted for using the liability method under which deferred income taxes are recognized for the future tax effects of temporary differences between financial statement carrying amounts and the tax basis of existing assets and liabilities using the enacted statutory tax rates in effect at period-end. The effect on deferred taxes for a change in tax rates is recognized in income in the period that includes the enactment date. The Company’s policy is to recognize penalties and interest related to unrecognized tax benefits, if any, in income tax expense. A valuation allowance for deferred tax assets is recorded when it is more likely than not that the benefit from the deferred tax asset will not be realized.

The Company's (provision) benefit for income taxes totaled ($6.8) million and $25.1 million for the three and nine months ended September 30, 2017, respectively. The Company's benefit for income taxes totaled $65.3 million and $259.3 million for the three and nine months ended September 30, 2016, respectively. These amounts differ from the amounts computed by applying the United States statutory federal income tax rate to net income (loss) before income taxes. The sources and tax effects of the differences are reflected in the table below:

Three months ended September 30, Nine months ended September 30,
$ in thousands 2017 Tax rate % 2016 Tax rate % 2017 Tax rate % 2016 Tax rate %
Expected income tax (provision) benefit based on US statutory tax rate of 35% $ (6,087 ) 35.0 % $ 61,214
35.0 % $ 27,136
35.0 % $ 240,311
35.0 %
State income taxes, net of federal benefit (522 ) 3.0 % 5,247
3.0 % 2,326
3.0 % 20,598
3.0 %
Tax deficiency from stock-based compensation (1) (134 ) 0.8 % —
— % (3,907 ) (5.0 %) —
— %
Canadian valuation allowance (2) (68 ) 0.4 % (665 ) (0.4 %) (325 ) (0.4 %) (959 ) (0.1 %)
Effect of differing statutory tax rate in Canada (34 ) 0.1 % (313 ) (0.2 %) (156 ) (0.3 %) (437 ) (0.1 %)
Other, net 75
(0.4 %) (207 ) (0.1 %) (11 ) — % (259 ) — %
(Provision) benefit for income taxes $ (6,770 ) 38.9 % $ 65,276
37.3 % $ 25,063
32.3 % $ 259,254
37.8 %


~~(1)~~	The Company recognized $0.1 million and $3.9 million of tax deficiencies from stock-based compensation as income tax expense for the three and nine months ended September 30, 2017, respectively, in accordance with ASU 2016-09 as discussed in ~~Note 2. Basis of Presentation and Significant Accounting Policies–Adoption of new accounting pronouncements~~.


~~(2)~~	Represents valuation allowances recognized against all deferred tax assets associated with operating loss carryforwards generated by the Company's Canadian operations during the respective periods for which the Company does not expect to realize a benefit.

~~Continental Resources, Inc. and Subsidiaries~~

~~Notes to Unaudited Condensed Consolidated Financial Statements~~

~~Note 11. Property Dispositions~~

~~2017~~

In September 2017 the Company sold non-strategic properties in the Arkoma Woodford area to a third party for cash proceeds of $65.3 million. The sale included approximately 26,000 net acres of leasehold in Atoka, Coal, Hughes, and Pittsburg Counties of Oklahoma and producing properties with production totaling approximately 1,700 barrels of oil equivalent per day. In connection with the transaction, the Company recognized a pre-tax loss of $3.8 million. The disposed properties represented an immaterial portion of the Company’s proved reserves.

In September 2017 the Company reached an agreement to sell non-core leasehold in the STACK play in Blaine County, Oklahoma to a third party for cash proceeds totaling $63.5 million. A portion of the transaction closed in September 2017, resulting in the receipt of proceeds amounting to $3.6 million and the recognition of a $3.3 million pre-tax gain on sale in the 2017 third quarter. The remainder of the transaction was completed in October 2017 at which time the Company received the remaining $59.9 million of proceeds. In connection with the completion of the transaction in October 2017, the Company expects to recognize an additional pre-tax gain of approximately $52 million, which will be reflected in fourth quarter 2017 results. The disposed properties represented an immaterial portion of the Company’s production and proved reserves.

~~Additionally, in September 2017 the Company sold certain oil-loading facilities in Oklahoma for $7.2 million and recognized a $4.5 million pre-tax gain associated with the transaction.~~

~~2016~~

In September 2016 the Company sold non-strategic properties in North Dakota and Montana to a third party for cash proceeds of $214.8 million, with no gain or loss recognized. The sale included approximately 68,000 net acres of leasehold primarily in western Williams County, North Dakota, and approximately 12,000 net acres of leasehold in Roosevelt County, Montana. The sale also included producing properties with production totaling approximately 2,700 barrels of oil equivalent per day. The disposed properties represented an immaterial portion of the Company’s proved reserves.

In April 2016 the Company sold approximately 132,000 net acres of undeveloped leasehold acreage located in Wyoming to a third party for cash proceeds of $110.0 million. In connection with the transaction, the Company recognized a pre-tax gain of $96.9 million. The disposed properties had no production or proved reserves.


~~ITEM 2.~~	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 ~~Annual Report on~~ Form 10-K for the year ended December 31, ~~2016. Our operating results for the periods discussed below may not be indicative of future performance.~~ 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 ~~if any,~~ and in our ~~Annual Report on~~ Form 10-K for the year ended December 31, ~~2016,~~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.~~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 ~~operations~~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 ~~primarily focused on exploration and development activities~~summarized below.

•Generated $1.74 billion in operating cash flows in the ~~Bakken field~~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 ~~North Dakota~~$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 ~~Montana~~$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 ~~SCOOP~~ongoing rebalancing of crude oil and ~~STACK areas~~natural gas supply and demand fundamentals coupled with the disruption of ~~Oklahoma.~~

~~Business Environment~~global hydrocarbon markets prompted by the outbreak of military conflict between Russia and ~~Outlook~~

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 ~~due to domestic~~ and ~~global supply and demand factors. In light of the challenges facing~~ our industry, our primary business strategies for 2017 focus on: (1) high-grading investments based on rates of return and opportunities to convert undeveloped acreage to acreage held by production, (2) improving cash flows through operating efficiencies, cost reductions, and optimized completions, (3) managing capital spending to minimize the incurrence of new incremental debt and maintain ample liquidity and financial flexibility, and (4) pursuing opportunities to further reduce debt using proceeds from potential sales of non-strategic assets.

~~2017 Highlights~~

~~Production~~

~~Crude oil and natural gas production~~results for the ~~third quarter~~first half of ~~2017 averaged 242,788 Boe per day, an increase~~2022 may not be indicative of ~~7% from~~future results. Given the ~~second quarter of 2017~~uncertainty surrounding the Russia/Ukraine conflict and ~~17% higher than the third quarter of 2016. Year to date production averaged 227,692 Boe per day, a 4% increase from the comparable 2016 period.~~

~~Average daily crude oil production increased 21%~~ongoing volatility in the third quarter of 2017 compared to the third quarter of 2016, while average daily natural gas production increased 12%. Third quarter 2017 average daily crude oil production increased 12% compared to the second quarter of 2017 reflecting increased well completion activities in North Dakota Bakken, while average daily natural gas production increased 1%.

~~Crude oil represented 58% of our production for the 2017 third quarter compared to 55% for the 2017 second quarter and 56% for the 2016 third quarter.~~

~~The following table summarizes the changes in our average daily Boe production by major operating area.~~

Boe production per day 3Q 2017 2Q 2017 % Change from 2Q 2017 3Q 2016 % Change from 3Q 2016
Bakken 136,851
119,861
14 % 107,929
27 %
SCOOP 57,283
61,107
(6 %) 67,462
(15 %)
STACK 35,619
31,934
12 % 17,680
101 %
All other 13,035
13,311
(2 %) 14,769
(12 %)
Total 242,788
226,213
7 % 207,840
17 %

~~Revenues~~

~~Crude oil and natural gas revenues for the 2017 third quarter increased 39% compared to the 2016 third quarter driven by a 21% increase in realized~~ commodity prices, ~~coupled with a 16% increase in total sales volumes.~~

~~Year~~we are unable to ~~date crude oil and natural gas revenues increased 37% from~~predict the ~~comparable 2016 period driven by a 32% increase in realized commodity prices coupled with a 3% increase in total sales volumes.~~

~~Average crude oil sales prices for~~extent to which the ~~third quarter and year to date periods of 2017 increased 15% and 29%, respectively, from~~conflict or other factors will have on the ~~comparable 2016 periods.~~

~~Crude oil sales volumes for~~Company’s performance during the ~~third quarter and year to date periods of 2017 increased 19% and decreased 3%, respectively, from the comparable 2016 periods.~~

~~Average natural gas sales prices for the third quarter and year to date periods of 2017 increased 36% and 77%, respectively, from the comparable 2016 periods.~~

~~Natural gas sales volumes for the third quarter and year to date periods of 2017 increased 12% and 13%, respectively, from the comparable 2016 periods.~~

~~Operating cash flows~~

Cash flows from operating activities totaled $431.4 million for the third quarter of 2017, 3% lower than operating cash flows of $446.4 million for the 2017 second quarter and 18% higher than 2016 third quarter operating cash flows of $366.2 million.

~~Capital expenditures and drilling activity~~

Non-acquisition capital expenditures totaled $520.6 million for the third quarter of 2017 bringing year to date 2017 non-acquisition capital expenditures to $1,499.5 million compared to $768.0 million for year to date 2016.

For the third quarter of 2017 we participated in the drilling and completion of 184 gross (80 net) wells, bringing our 2017 year to date total to 425 gross (163 net) wells compared to 256 gross (64 net) wells for year to date 2016.

~~Property dispositions~~

In September 2017 we sold non-strategic properties in the Arkoma Woodford area of Oklahoma to a third party for cash proceeds of $65.3 million. The sale included approximately 26,000 net acres of leasehold and producing properties with production totaling approximately 1,700 barrels of oil equivalent per day. In connection with the transaction, we recognized a pre-tax loss of $3.8 million.

In September 2017 we reached an agreement to sell non-core leasehold in the STACK play in Blaine County, Oklahoma to a third party for cash proceeds totaling $63.5 million. A portion of the transaction closed in September 2017, resulting in the receipt of proceeds amounting to $3.6 million and the recognition of a $3.3 million pre-tax gain on sale in the 2017 third quarter. The remainder of the transaction was completed in October 2017 at which time we received the remaining $59.9 million of proceeds. In connection with the completion of the transaction in October 2017, we expect to recognize an additional pre-tax gain of approximately $52 million, which will be reflected in fourth quarter 2017 results.2022 and beyond.

~~In September 2017 we sold certain oil-loading facilities in Oklahoma for $7.2 million and recognized a $4.5 million pre-tax gain associated with the transaction.~~

~~Credit facility and liquidity~~

~~At September 30, 2017, we had$10.8 million~~of cash and cash equivalents and $1.81 billion of borrowing availability on our credit facility after considering outstanding borrowings and letters of credit. We had $938 million of outstanding borrowings on our credit facility at September 30, 2017 compared to $880 million at June 30, 2017 and $905 million at December 31, 2016.~~At October 31, 2017, outstanding credit facility borrowings totaled $895 million, leaving approximately $1.85 billion of borrowing availability at that date.~~

~~Financial and operating highlights~~

~~We use a variety of financial and operating measures to assess our performance. Among these measures are:~~

~~Volumes of crude oil and natural gas produced;~~

~~Crude oil and natural gas prices realized; and~~

~~Per unit operating and administrative costs.~~

The following table contains financial and operating ~~highlights~~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 September 30, Nine months ended September 30,
2017 2016 2017 2016
Average daily production:

Crude oil (Bbl per day) 140,611
116,277
128,476
131,873
Natural gas (Mcf per day) 613,060
549,374
595,294
524,441
Crude oil equivalents (Boe per day) 242,788
207,840
227,692
219,280
Average sales prices:

Crude oil ($/Bbl) $ 43.27
$ 37.66
$ 43.26
$ 33.51
Natural gas ($/Mcf) $ 2.74
$ 2.02
$ 2.78
$ 1.57
Crude oil equivalents ($/Boe) $ 31.86
$ 26.42
$ 31.67
$ 23.91
Crude oil sales price discount to NYMEX ($/Bbl) $ (4.98 ) $ (7.27 ) $ (6.07 ) $ (7.44 )
Natural gas sales price discount to NYMEX ($/Mcf) $ (0.26 ) $ (0.80 ) $ (0.37 ) $ (0.73 )
Production expenses ($/Boe) $ 3.82
$ 3.50
$ 3.86
$ 3.66
Production taxes (% of oil and gas revenues) 7.3 % 6.8 % 6.8 % 7.3 %
DD&A ($/Boe) $ 19.00
$ 21.66
$ 19.31
$ 22.00
Total general and administrative expenses ($/Boe) (1) $ 1.99
$ 2.32
$ 2.10
$ 1.88
Net income (loss) (in thousands) $ 10,621
$ (109,621 ) $ (52,467 ) $ (427,348 )
Diluted net income (loss) per share $ 0.03
$ (0.30 ) $ (0.14 ) $ (1.15 )


~~(1)~~	~~Represents cash general and administrative expenses per Boe and non-cash equity compensation expenses per Boe. See~~ ~~Operating Costs and Expenses—General and Administrative Expenses~~ ~~below for additional discussion of these components.~~


	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 ~~September~~June 30, ~~2017~~2022 compared to the three months ended ~~September~~June 30, ~~2016~~2021

Results of Operations

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


								Three months ended June 30,
	Three months ended September 30,
In thousands, except sales price data	2017			2016
Crude oil and natural gas sales	$	704,818		$	505,892
Gain on crude oil and natural gas derivatives, net	8,602			15,668
In thousands							In thousands	2022		2021
Crude oil, natural gas, and natural gas liquids sales							Crude oil, natural gas, and natural gas liquids sales	$	2,829,173	$	1,282,914
Loss on derivative instruments, net							Loss on derivative instruments, net	(195,744)		(62,178)
Crude oil and natural gas service operations	13,323			4,639			Crude oil and natural gas service operations	17,045		14,389
Total revenues	726,743			526,199			Total revenues	2,650,474		1,235,125
Operating costs and expenses	(634,990		)	(619,382		)	Operating costs and expenses	(973,957)		(789,957)
Other expenses, net	(74,362		)	(81,714		)	Other expenses, net	(71,399)		(60,747)
Income (loss) before income taxes	17,391			(174,897		)
(Provision) benefit for income taxes	(6,770		)	65,276
Net income (loss)	$	10,621		$	(109,621	)
Income before income taxes							Income before income taxes	1,605,118		384,421
Provision for income taxes							Provision for income taxes	(389,271)		(94,947)
Income before equity in net loss of affiliate							Income before equity in net loss of affiliate	1,215,847		289,474
Equity in net loss of affiliate							Equity in net loss of affiliate	(76)		—
Net income							Net income	1,215,771		289,474
Net income attributable to noncontrolling interests							Net income attributable to noncontrolling interests	7,024		149
Net income attributable to Continental Resources							Net income attributable to Continental Resources	$	1,208,747	$	289,325
Production volumes:							Production volumes:
Crude oil (MBbl)	12,936			10,698			Crude oil (MBbl)	18,047		15,176
Natural gas (MMcf)	56,401			50,542			Natural gas (MMcf)	110,212		93,876
Crude oil equivalents (MBoe)	22,337			19,121			Crude oil equivalents (MBoe)	36,415		30,822
Sales volumes:							Sales volumes:
Crude oil (MBbl)	12,722			10,724			Crude oil (MBbl)	17,844		15,127
Natural gas (MMcf)	56,401			50,542			Natural gas (MMcf)	110,212		93,876
Crude oil equivalents (MBoe)	22,123			19,148			Crude oil equivalents (MBoe)	36,213		30,773
Average sales prices:
Crude oil ($/Bbl)	$	43.27		$	37.66
Natural gas ($/Mcf)	2.74			2.02
Crude oil equivalents ($/Boe)	31.86			26.42

Production

The following ~~tables reflect~~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 ~~and region~~ for the ~~periods presented.~~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	%

Three months ended September 30, Volume
increase Volume
percent
increase
2017 2016
Volume Percent Volume Percent
Crude oil (MBbl) 12,936
58 % 10,698
56 % 2,238
21 %
Natural gas (MMcf) 56,401
42 % 50,542
44 % 5,859
12 %
Total (MBoe) 22,337
100 % 19,121
100 % 3,216
17 %

Three months ended September 30, Volume
increase Volume
percent
increase
2017 2016
MBoe Percent MBoe Percent
North Region 13,509
60 % 11,003
58 % 2,506
23 %
South Region 8,828
40 % 8,118
42 % 710
9 %
Total 22,337
100 % 19,121
100 % 3,216
17 %

The ~~21%~~19% increase in crude oil production ~~for~~in the ~~third~~2022 second quarter was primarily driven by increased production from properties in North Dakota Bakken due to an increase in well completion activities and the timing of production commencing from new pad development projects, along with strong initial production results being achieved on new wells resulting from optimized completion technologies. Crude oil production in North Dakota Bakken increased 2,260 MBbls, or 32%, from the prior year third quarter. Additionally, production from our ~~South region properties~~property acquisitions in the ~~STACK play increased 393 MBbls, or 108%, from the prior year third quarter due to additional wells being completed~~Permian Basin and producing as a result of an increase in our drilling and completion activities in that area. These increases were partially offset by decreased production from our North region properties in Montana Bakken and the RedPowder River ~~units due to natural declines in production coupled with reduced drilling~~

~~activities~~Basin over the past year, ~~in response~~which increased our 2022 second quarter production by 3,066 MBbls and 1,115 MBbls, respectively, compared to ~~low crude oil prices. Montana Bakken production decreased 135 MBbls, or 20%, while crude oil production in~~ the Red River units decreased 82 MBbls, or 9%, from the prior year third quarter. Additionally, crude oil production in SCOOP decreased 198 MBbls, or 12%, due to natural declines in production and reduced drilling activities.

The 12% increase in natural gas production for the third quarter was driven by increased production from our properties in the STACK play due to additional wells being completed and producing subsequent to September 30, 2016.Natural gas production in STACK increased 7,544 MMcf, or 100%, over the prior year third quarter. Additionally, natural gas production in North Dakota Bakken increased 3,180 MMcf, or 26%, in conjunction with the aforementioned increase in crude oil production over the prior year third2021 second quarter. These increases were partially offset by ~~reduced~~an 827 MBbls, or 8%, decrease in Bakken crude oil production ~~from~~due to the effects of severe winter weather in April 2022 that resulted in the curtailment of a portion of our ~~SCOOP properties, which~~production, delays in drilling and completion of wells, and other operational constraints. Additionally, crude oil production in the Anadarko Basin decreased ~~4,431 MMcf,~~456 MBbls, or ~~16%~~13%, ~~along with various other areas in our North and South regions~~ due to ~~natural declines~~a change in ~~production and reduced drilling activities~~allocation of capital from oil-weighted projects to gas-weighted projects in the play over the past ~~year.~~year and the timing of well completions.

~~In September 2017 we sold substantially all of our producing properties~~

The 17% increase in natural gas production in the ~~Arkoma Woodford area~~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 ~~Oklahoma. The sold properties comprised approximately 940 MMcf~~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 ~~production for the three months ended September 30, 2017.~~

The increase in crude oil production as a percentage of our total production from 56% in the third quarter of 2016 to 58% in the third quarter of 2017 resulted from the significant increase in North Dakota Bakken production in recent months fromsales volumes increased ~~well completion activities, which contributed to a 12% increase in our average daily crude oil production for the 2017 third quarter~~17% compared to the ~~2017~~2021 second quarter. ~~Our properties in North Dakota Bakken typically produce a higher concentration of crude oil compared to our Oklahoma properties.~~

Our crude oil ~~production is expected to continue growing in relative significance for the remainder of 2017 based on our planned well completion activities in North Dakota Bakken in the 2017 fourth quarter.~~

~~Revenues~~

Our revenues consist of sales of crude oil and natural gas, gains and losses resulting from changes in the fair value of our crude oil and natural gas derivative instruments, and revenues associated with crude oil and natural gas service operations.

~~Crude Oil and Natural Gas Sales.~~ Crude oil and natural gas sales for the third quarter of 2017 were $704.8 million, a 39% increase from sales of $505.9 million for the 2016 third quarter due to increases in commodity prices and total sales volumes. If commodity prices remain at current levels, we expect our 2017 crude oil and natural gas revenues will continue to be higher than 2016 levels, the extent of which is uncertain due to the unpredictable nature of commodity prices.

~~Our crude oil~~net sales prices averaged ~~$43.27~~ $106.41per barrel in the ~~2017 third~~2022 second quarter ~~an increase of 15%~~ compared to ~~$37.66~~$62.37 per barrel for the ~~2016 third~~2021 second quarter due to ~~higher crude oil~~the previously described increase in market prices ~~and~~along with improved price ~~realizations.~~differentials. The differential between NYMEX West Texas Intermediate ~~(“WTI”)~~ calendar month ~~crude oil~~ prices and our realized crude oil net sales prices ~~averaged $4.98~~improved to an average of $2.30 per barrel for the ~~2017 third~~2022 second quarter compared to ~~$7.27~~$3.83 per barrel for the ~~2016 third quarter. The improved differential was primarily due to improved~~2021 second quarter, reflecting strong price realizations ~~resulting from new pipeline takeaway capacity and additional markets becoming available in 2017 for Bakken production, along with the growth in~~across our South region production which typically has lower transportation costs compared to the Bakken due to its relatively close proximity to regional refineries and the crude oil trading hub in Cushing, Oklahoma.assets.

Our natural gas net sales prices averaged ~~$2.74~~$7.75 per Mcf for the ~~2017 third~~2022 second quarter ~~a 36% increase~~ compared to ~~$2.02~~$3.06 per Mcf for the ~~2016 third~~2021 second quarter due to ~~higher~~the previously described increase in market prices ~~for natural gas and natural gas liquids (“NGLs”) and~~along with improved price ~~realizations.~~differentials. The ~~discount~~difference between our ~~realized natural gas~~net sales prices and NYMEX Henry Hub calendar month natural gas prices improved ~~from $0.80~~to a premium of $0.52 per Mcf for the ~~2016 third~~2022 second quarter compared to ~~$0.26~~a premium of $0.23 per Mcf for the ~~2017 third quarter. The majority of our natural gas production is sold at our lease locations to midstream purchasers with~~2021 second quarter, again reflecting strong price realizations ~~impacted by the volume and value of NGLs that purchasers extract from~~across our ~~sales stream. NGL prices have increased over prior year levels~~assets.

Derivatives. The continued improvement in ~~conjunction with increased crude oil prices and other factors, resulting in improved price realizations for our natural gas sales stream compared to the prior year third quarter.~~

Total sales volumes for the third quarter of 2017 increased 2,975 MBoe, or 16%, compared to the 2016 third quarter, reflecting an increase in our pace of drilling and completion activities in 2017. For the third quarter of 2017, our crude oil sales volumes increased 19% from the comparable 2016 period, while our natural gas sales volumes increased 12%.

~~At various times we have stored crude oil due to pipeline line fill requirements, low~~ commodity prices, or marketing disruptions or we have sold crude oil from inventory. These actions result in differences between produced and sold crude oil volumes and caused crude oil sales volumes to be lower than crude oil production by 214 MBbls for the third quarter of 2017.

~~Derivatives.~~ ~~Changes in natural gas~~ prices during the ~~third~~second quarter of ~~2017~~2022 had a ~~favorable~~significant unfavorable impact on the fair value of our ~~natural gas~~ derivatives, which resulted in ~~positive~~negative revenue adjustments ~~of $8.6~~totaling $195.7 million for the period, representing ~~$12.3~~

$155.3 million of cash ~~gains partially offset by $3.7~~losses and $40.4 million of unsettled non-cash ~~losses. Our revenues for the remainder of 2017 may continue~~losses, compared to ~~be significantly impacted, either positively or negatively, by changes~~negative revenue adjustments totaling $62.2 million in the ~~fair value of our derivative instruments as a result of volatility in natural gas prices.~~

~~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 and the treatment and sale of lower quality reclaimed crude oil. Revenues associated with such activities increased $8.7 million from $4.6 million for the thirdsecond quarter of 2016 to $13.3 million for the third quarter of 2017 due to an increase in industry production activities and changes in the nature, timing and extent of handling and treatment activities between periods.2021.

Operating Costs and Expenses

Production Expenses. Production expenses increased ~~$17.5~~$56.7 million, or ~~26%~~59%, ~~from $67.0~~to $153.2 million for the ~~third~~second quarter of ~~2016~~2022 compared to ~~$84.5~~$96.5 million for the ~~third~~second quarter of ~~2017. Production expenses on a per-Boe basis increased~~2021 due to ~~$3.82 for the 2017 third quarter compared to $3.50 for the 2016 third quarter. These increases resulted from~~ an increase in the number of producing wells ~~an increase in~~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 ~~a higher portion~~the addition of ~~our~~oil-weighted production ~~coming from wells~~acquired in ~~North Dakota Bakken~~the Permian and Powder River basins over the past year which typically have higher per-unit operating costs compared to ~~wells~~gas-weighted properties in ~~Oklahoma.~~the Anadarko Basin.

Production and Ad Valorem Taxes. Production and ad valorem taxes increased ~~$16.7~~$109.9 million, or ~~48%~~117%, to ~~$51.3~~$204.2 million for the ~~third~~second quarter of ~~2017~~2022 compared to ~~$34.6~~$94.3 million for the ~~third~~second quarter of ~~2016 primarily~~2021 due to ~~higher crude oil and natural gas revenues resulting from increases~~the previously described increase in ~~commodity prices and total sales volumes over the prior year period. Production taxes are generally based on the wellhead values of~~sales. Our production ~~and vary by state. Production~~ taxes as a percentage of ~~crude oil and natural gas revenues were 7.3%~~net sales averaged 7.4% for the ~~third~~second quarter of ~~2017~~2022 compared to ~~6.8%~~7.7% for the ~~third~~second quarter of 2016, the increase of which primarily resulted from a significant increase in production and revenues being generated in North Dakota in recent months which has higher production tax rates compared to Oklahoma. The production tax rate on new wells in North Dakota is currently 10% of crude oil revenues. The production tax rate on Oklahoma wells that commenced production after July 1, 2015 is currently 2% of crude oil and natural gas revenues for the first 36 months of production and 7% thereafter. Additionally, in May 2017 new legislation was enacted in Oklahoma that increased the production tax rate from 1% to 4% on wells that began producing between July 1, 2011 and July 1, 2015. The new 4% tax rate on these wells went into effect on July 1, 2017 and contributed to the increase in our average production tax rate for the third quarter of 2017.2021.

~~Exploration Expenses~~. Exploration expenses consist primarily of dry hole costs and exploratory geological and geophysical costs that are expensed as incurred. The following table shows the components of exploration expenses for the periods presented.

Three months ended September 30,
In thousands
2017
2016
Geological and geophysical costs $ 1,389
$ 3,960
Exploratory dry hole costs —
27
Exploration expenses $ 1,389
$ 3,987

~~The decrease in geological and geophysical expenses in 2017 was due to changes in the timing and amount of costs incurred by the Company and billed to joint interest owners between periods.~~

Depreciation, Depletion, Amortization and ~~Accretion (“DD&A”).~~Accretion. Total DD&A ~~increased $5.5~~decreased $25.3 million, or 1%5%, to ~~$420.2~~$446.6 million for the ~~third~~second quarter of ~~2017~~2022 compared to ~~$414.7~~$471.9 million for the ~~third~~second quarter of ~~2016~~2021 primarily due to ana decrease in our DD&A rate per Boe as further discussed below, partially offset by the previously described 18% increase in total sales ~~volumes which was offset by the impact from an increase in the volume of proved reserves over which costs are depleted as further discussed below.~~volumes. The following table shows the components of our DD&A on a unit of sales basis for the periods presented.


	Three months ended September 30,					Three months ended June 30,
$/Boe	2017		2016		$/Boe	2022		2021
Crude oil and natural gas	$	18.70	$	21.20	Crude oil and natural gas	$	12.04	$	15.03
Other equipment	0.23		0.38		Other equipment	0.20		0.21
Asset retirement obligation accretion	0.07		0.08		Asset retirement obligation accretion	0.09		0.09
Depreciation, depletion, amortization and accretion	$	19.00	$	21.66	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. ~~Upward revisions to~~

Our proved reserves in

~~2017 due~~have been revised upward over the past year prompted by significant increases in ~~part to an improvement in~~first-day-of-the-month commodity prices ~~contributed to~~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 ~~third~~second quarter of ~~2017~~2022 compared to the ~~third~~second quarter of ~~2016. Additionally, improvements~~2021 and helped offset the additional DD&A recognized in drilling efficiencies and optimized completion technologies over the past year have resulted in a significant improvement in the quantity of proved reserves found and developed per dollar invested, which also contributed to the reduction in our DD&A rate in the current period.2022 from increased sales volumes.

Property Impairments. Total property impairments ~~decreased $22.6~~increased $4.2 million ~~or 39%,~~ to ~~$35.1~~$15.8 million for the ~~2017 third~~second quarter of 2022 compared to ~~$57.7~~$11.6 million for the ~~2016 third~~second quarter ~~primarily due to a decrease~~of 2021, reflecting an increase in ~~non-producing property impairments.~~

~~Impairments of non-producing properties decreased $19.7 million, or 36%, to $35.1 million for~~ the 2017 third quarter compared to $54.8 million for the 2016 third quarter. The decrease was due to a lower balance of unamortized leasehold costs in the current year due to property dispositions and reduced land capital expenditures in recent years, along with changes in the timing and magnitude of amortization of undeveloped leasehold costs ~~between periods~~driven by an increase in our balance of unproved properties resulting from ~~changes in~~property acquisitions over the ~~Company's estimates of undeveloped properties not expected to be developed before lease expiration.~~

past year. There were no proved property impairments recognized in the ~~2017 third~~second quarter ~~compared to $2.9 million~~periods of ~~such impairments for the third quarter of 2016.~~2022 and 2021.

General and Administrative ~~(“G&A”)~~ Expenses. Total G&A expenses ~~decreased $0.4~~increased $7.0 million, or 1%13%, ~~from $44.4~~to $62.6 million for the ~~third~~second quarter of ~~2016~~2022 compared to ~~$44.0~~$55.6 million for the ~~third~~second quarter of ~~2017.~~ 2021.

Total G&A expenses include non-cash charges for equity compensation of ~~$11.9~~$14.8 million and ~~$13.2~~$13.6 million for the ~~third~~second quarters of ~~2017~~2022 and ~~2016,~~2021, respectively. G&A expenses other than equity compensation ~~included in the total G&A expense figure above~~ totaled ~~$32.1~~$47.8 million for the ~~2017 third~~2022 second quarter, an increase of ~~$0.9~~$5.8 million ~~or 3%,~~ compared to ~~$31.2~~$42.0 million for the ~~2016 third quarter. This increase resulted from an increase in employee compensation and benefits in 2017 in response~~2021 second quarter primarily due to the ~~stabilization~~growth of our operations and ~~improvement~~increases in ~~commodity prices in late 2016,~~payroll costs and employee benefits, partially offset by higher overhead recoveries from joint interest owners driven by increased drilling, completion, and production activities ~~over~~compared to the ~~prior period.~~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

Three months ended September 30,
$/Boe
2017 2016
General and administrative expenses $ 1.45
$ 1.63
Non-cash equity compensation 0.54
0.69
Total general and administrative expenses $ 1.99
$ 2.32

The decrease in G&A expenses other than equity compensation on a per-Boe basis was driven by a 16% increase in total sales volumes from new well completions with no comparable increase in G&A expenses.

The decrease in equity compensation expense on a per-Boe basis resulted from changes in the timing and magnitude of forfeitures of unvested restricted stock between periods, coupled with the increase in sales volumes from new well completions with no comparable increase in equity compensation expense.

Interest Expense. Interest expense ~~decreased $7.3~~increased $11.3 million, or 9%19%, to ~~$74.8~~$72.2 million for the ~~third~~second quarter of ~~2017~~2022 compared to ~~$82.1~~$61.0 million for the ~~third~~second quarter of ~~2016 due to a decrease in outstanding debt primarily as a result of the November 2016 redemptions of our $200 million of 2020 Notes and $400 million of~~ 2021 Notes. Our weighted average outstanding long-term debt balance for the 2017 third quarter was approximately $6.7 billion with a weighted average interest rate of 4.1%, compared to averages of $7.1 billion and 4.4% for the 2016 third quarter. The lower interest expense associated with reduced debt was partially offset by higher interest expense being incurred on our variable-rate credit facility and term loan borrowings due to an increase in ~~market interest rates in 2017.~~

~~Income Taxes.~~ ~~We recorded income tax expense~~our weighted average outstanding debt balance from $4.9 billion for the ~~third~~second quarter of ~~2017 of $6.8 million compared~~2021 to ~~an income tax benefit of $65.3 million~~$6.6 billion for the ~~third~~second quarter of ~~2016, resulting~~2022. This increase was driven by debt incurred in ~~effective tax rates~~the fourth quarter of ~~approximately 39% and 37%, respectively, after taking into account permanent taxable differences, valuation allowances, and other items.~~2021 to fund a portion of our December 2021 acquisition of properties in the Permian Basin.

Income Taxes. For the ~~third~~second quarters of ~~2017~~2022 and ~~2016,~~2021 we provided for income taxes at a combined federal and state tax rate of ~~38%~~24.5% of our pre-tax income. We recorded an income ~~(loss) generated by our operations~~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 ~~the United States~~effective tax rates of 24.3% and ~~25% of pre-tax losses generated by our operations~~24.7%, respectively, after taking into account statutory tax rates, permanent taxable differences, tax effects from equity compensation, changes in ~~Canada.~~valuation allowances, and other items. See Notes to Unaudited Condensed Consolidated Financial Statements–Note ~~10.~~12. Income Taxes for a summary of the sources and tax effects of items comprising our effective tax ~~rate for the third quarters of 2017 and 2016.~~

rates.

~~Nine~~

Six months ended ~~September~~June 30, ~~2017~~2022 compared to the ~~nine~~six months ended ~~September~~June 30, ~~2016~~2021

Results of Operations

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

Nine months ended September 30,
In thousands, except sales price data 2017 2016
Crude oil and natural gas sales $ 1,965,216
$ 1,435,194
Gain (loss) on crude oil and natural gas derivatives, net 83,482
(24,477 )
Crude oil and natural gas service operations 24,959
19,867
Total revenues 2,073,657
1,430,584
Operating costs and expenses (1) (1,933,724 ) (1,873,415 )
Other expenses, net (217,463 ) (243,771 )
Loss before income taxes (77,530 ) (686,602 )
Benefit for income taxes 25,063
259,254
Net loss $ (52,467 ) $ (427,348 )
Production volumes:
Crude oil (MBbl) 35,074
36,133
Natural gas (MMcf) 162,515
143,697
Crude oil equivalents (MBoe) 62,160
60,083
Sales volumes:
Crude oil (MBbl) 34,975
36,080
Natural gas (MMcf) 162,515
143,697
Crude oil equivalents (MBoe) 62,061
60,029
Average sales prices:
Crude oil ($/Bbl) $ 43.26
$ 33.51
Natural gas ($/Mcf) 2.78
1.57
Crude oil equivalents ($/Boe) 31.67
23.91

~~(1) Net of gain on sale of assets of $103.2 million for the nine months ended September 30, 2016.~~


	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 ~~tables reflect~~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 ~~and region~~ for the ~~periods presented.~~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	%

Nine months ended September 30, Volume
increase (decrease) Volume
percent
increase (decrease)
2017 2016
Volume Percent Volume Percent
Crude oil (MBbl) 35,074
56 % 36,133
60 % (1,059 ) (3 %)
Natural gas (MMcf) 162,515
44 % 143,697
40 % 18,818
13 %
Total (MBoe) 62,160
100 % 60,083
100 % 2,077
3 %

Nine months ended September 30, Volume
increase (decrease) Volume
percent
increase (decrease)
2017 2016
MBoe Percent MBoe Percent
North Region 36,106
58 % 37,243
62 % (1,137 ) (3 %)
South Region 26,054
42 % 22,840
38 % 3,214
14 %
Total 62,160
100 % 60,083
100 % 2,077
3 %

The ~~3% decrease~~23% increase in crude oil production for year to date ~~2017~~2022 compared to year to date 2021 was primarily driven ~~primarily~~ by ~~decreased production from~~ our North region properties in North Dakota Bakken, Montana Bakken and the Red River units due to natural declines in production coupled with delayed completion activities in response to low crude oil prices. North Dakota Bakken crude oil production decreased 324 MBbls, or 1%, and Montana Bakken production decreased 567 MBbls, or 25%, while productionproperty acquisitions in the ~~Red~~Permian Basin and Powder River ~~units decreased 293~~Basin over the past year, which increased our year to date 2022 production by 5,874 MBbls or 10%, from the prior year period. The decreased crude oil production in North Dakota Bakken was mitigated by new well production generated in recent months from increased well completion activities in

~~2017, which resulted in a 19% sequential increase in crude oil production in that play for the 2017 third quarter~~and 1,772 MBbls, respectively, compared to ~~the 2017 second quarter. Additionally, crude oil production in SCOOP decreased 824 MBbls, or 16%, due~~year to ~~natural declines in production and reduced drilling activities.~~date 2021. These ~~decreases~~increases were partially offset by ~~an increase of 972~~a 630 MBbls, or ~~105%~~9%, decrease in Anadarko Basin crude oil production ~~from our STACK properties~~ due to ~~additional wells being completed~~a change in allocation of capital from oil-weighted projects to gas-weighted projects in the play over the past year and ~~producing as a result~~the timing of ~~an increase in our drilling and completion activities in that area.~~well completions.

The ~~13%~~16% increase in natural gas production for year to date ~~2017~~2022 compared to year to date 2021 was ~~primarily driven by increased production from our properties~~due in part to the previously described property acquisitions over the past year. Properties acquired in the ~~STACK play due~~Permian Basin increased our year to ~~additional wells being completed and producing subsequent~~date 2022 production by 10,258 MMcf while properties acquired in the Powder River Basin increased our production by 5,912 MMcf compared to ~~September 30, 2016. Natural gas production in STACK increased 23,231 MMcf, or 127%, over the prior~~ year ~~period.~~to date 2021. Additionally, natural gas production in ~~North Dakota Bakken~~the Anadarko Basin increased ~~1,528~~11,579 MMcf, or 4%10%, ~~over the prior~~compared to year period in conjunction with higher crude oil production in recent months arising from increased well completion activities. These increases were partially offset by reduced production from our SCOOP properties, which decreased 4,327 MMcf, or 6%, along with various other areas in our North and South regionsto date 2021 due to ~~natural declines in production and reduced drilling activities~~new well completions over the past year.

Revenues

~~In September 2017 we sold substantially all of our producing properties in the Arkoma Woodford area of Oklahoma. The sold properties comprised approximately 2,850 MMcf of our~~Net crude oil, natural gas, ~~production for the nine months ended September 30, 2017.~~

In conjunction with our increase in capital spending in 2017 relative to 2016, we expect our production will average between 238,000 and 242,000 Boe per day for the full year of 2017 compared to average daily production of 216,912 Boe per day for 2016.

~~Revenues~~

~~Crude Oil and Natural Gas Sales.~~ ~~Crude oil~~ 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 for year to date ~~2017 were $1.97~~2022 totaled $4.95 billion, ~~a 37%~~an increase ~~from~~of 104% compared to net sales of ~~$1.44~~$2.43 billion for the ~~same~~comparable 2021 period ~~in 2016~~ due to ~~a 32% increase~~significant increases in ~~realized commodity~~net sales prices ~~coupled with a 3% increase in total~~and sales ~~volumes.~~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 ~~$43.26~~$98.70 per barrel for year to date ~~2017, an increase of 29%~~2022 compared to ~~$33.51~~$57.95 per barrel for year to date ~~2016~~2021 due to ~~higher crude oil~~the previously described increase in market prices ~~and~~along with improved price ~~realizations.~~differentials. The differential between NYMEX WTI calendar month ~~average crude oil~~ prices and our realized crude oil ~~price~~net sales prices improved to an average of $2.88 per barrel for year to date ~~2017 was $6.07~~2022 compared to $4.16 per barrel ~~compared to $7.44~~ for year to date ~~2016. The improved differential was primarily due to improved~~2021, reflecting strong price realizations ~~resulting from new pipeline takeaway capacity and additional markets becoming available in 2017 for Bakken production, along with the growth in~~across our South region production which typically has lower transportation costs compared to the Bakken due to its relatively close proximity to regional refineries and the crude oil trading hub in Cushing, Oklahoma.assets.

Our natural gas net sales prices averaged ~~$2.78~~$7.09 per Mcf for year to date ~~2017, a 77% increase~~2022 compared to ~~$1.57~~$4.24 per Mcf for year to date ~~2016~~2021 due to ~~higher~~the previously described increase in market ~~prices for natural gas and NGLs and improved price realizations.~~prices. The ~~discount~~difference between our ~~realized natural gas~~net sales prices and NYMEX Henry Hub calendar month natural gas prices ~~improved from $0.73~~was a premium of $0.95 per Mcf for year to date ~~2016~~2022 compared to ~~$0.37~~a premium of $1.48 per Mcf for year to date ~~2017.~~2021. The ~~majority of our natural gas production is sold at our lease locations~~decrease in premium was driven by price volatility and significant improvement in Henry Hub prices as compared to ~~midstream purchasers with price realizations impacted by the volume and value of NGLs that purchasers extract from our sales stream.~~increases in NGL prices ~~have increased over prior year levels~~during the 2022 second quarter, causing the uplift in ~~conjunction with increased crude oil prices and other factors, resulting in improved~~ price realizations for our ~~natural~~full gas ~~sales~~ stream ~~compared~~relative to ~~the prior year.~~

~~Total sales volumes for year~~Henry Hub benchmark prices to date 2017 increased 2,032 MBoe, or 3%, compared to year to date 2016. For year to date 2017, our crude oil sales volumes decreased 3% from the comparable 2016 period, while our natural gas sales volumes increased 13%, reflecting an increase over the past yearbe less significant in the ~~proportion of capital spending allocated to areas~~current period.

Derivatives. The significant improvement in ~~Oklahoma which typically have higher concentrations of natural gas compared to oil-weighted properties in North Dakota Bakken.~~

~~Derivatives.~~ ~~Changes in natural gas~~commodity prices during the ~~nine~~six months ended ~~September~~June 30, ~~2017~~2022 had a ~~favorable~~significant unfavorable impact on the fair value of our ~~natural gas~~ derivatives, which resulted in ~~positive~~negative revenue adjustments ~~of $83.5~~totaling $671.7 million for the period, representing ~~$68.5 million of non-cash gains and $15.0~~$177.5 million of cash ~~gains.~~ 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 ~~$20.1~~$100.9 million, or 9%53%, ~~from $219.7~~to $290.5 million for year to date ~~2016~~2022 compared to ~~$239.8~~$189.6 million for year to date ~~2017. Production expenses on a per-Boe basis increased~~2021 due to ~~$3.86 for year to date 2017 compared to $3.66 for the comparable 2016 period. These increases resulted from~~ an increase in the number of producing wells ~~higher costs incurred in the 2017 first quarter~~ from ~~severe weather conditions encountered in the North region that created a challenging operating environment,~~drilling activities and ~~an increase in~~property acquisitions, cost inflation for services and materials, and higher workover-related activities aimed at enhancing production from producing ~~properties.~~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 ~~$30.3~~$184.3 million, or ~~29%~~103%, to ~~$134.5~~$362.6 million for year to date ~~2017~~2022 compared to ~~$104.2~~$178.3 million for year to date ~~2016~~2021 due to ~~higher crude oil and natural gas revenues resulting primarily from increases~~the previously described increase in ~~commodity prices over the prior year period.~~

~~Production~~sales. Our production taxes as a percentage of ~~crude oil and natural gas revenues were 6.8% for year to date 2017 compared to~~net sales averaged 7.3% for year to date ~~2016, the decrease~~2022, consistent with 7.3% for year to date 2021.

Exploration expenses. Exploration expenses, which consist primarily of ~~which resulted from significant growth over the past~~exploratory geological and geophysical costs and dry hole costs that are expensed as incurred, increased $10.7 million to $17.7 million for year ~~in our STACK operations and resulting increase in revenues coming from Oklahoma, which has lower production tax rates~~to date 2022 compared to ~~North Dakota.~~$6.9 million for year to date 2021. The ~~decrease in our year-to-date average production tax rate was partially offset by higher production taxes arising~~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 2017 third quarter as a result of increased production and revenues being generated in North Dakota in recent months from increased well completion activities, along with the enactment of new legislation in Oklahoma that increased the production tax rate, effective July 1, 2017, from 1%year to 4% on wells that began producing between July 1, 2011 and July 1, 2015. These factors contributed to a sequential increase in our average production tax rate from 6.7% in the 2017 second quarter to 7.3% in the 2017 third quarter.date 2021 period.

~~Exploration Expenses. The following table shows the components of exploration expenses for the periods presented.~~

Nine months ended September 30,
In thousands 2017 2016
Geological and geophysical costs $ 9,434
$ 8,493
Exploratory dry hole costs 157
233
Exploration expenses $ 9,591
$ 8,726

Depreciation, Depletion, Amortization and Accretion. Total DD&A decreased ~~$122.3~~$75.8 million, or 9%8%, to ~~$1.20 billion~~$905.7 million for year to date ~~2017~~2022 compared to ~~$1.32 billion~~$981.5 million for the comparable 2021 period ~~in 2016 primarily~~ due to ~~an increase~~the previously described decrease in ~~the volume of proved reserves over which costs are depleted as further discussed below, the impact of which was~~our DD&A rate per Boe in 2022 partially offset by anthe 19% increase in ~~DD&A resulting from higher~~our total sales ~~volumes in the current year.~~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

Nine months ended September 30,
$/Boe 2017 2016
Crude oil and natural gas $ 18.95
$ 21.55
Other equipment 0.29
0.37
Asset retirement obligation accretion 0.07
0.08
Depreciation, depletion, amortization and accretion $ 19.31
$ 22.00

Upward revisions to proved reserves over the past year due in part to an improvement in commodity prices contributed to a decrease in our DD&A rate for crude oil and natural gas properties in 2017 compared to 2016. Additionally, improvements in drilling efficiencies and optimized completion technologies over the past year have resulted in a significant improvement in the quantity of proved reserves found and developed per dollar invested, which also contributed to the reduction in our DD&A rate in the current period.

Property Impairments.Total property impairments increased ~~$7.1~~$17.0 million ~~or 3%,~~ to ~~$209.8~~$40.1 million for the year to date period of 2022 compared to $23.0 million for year to date ~~2017 compared to $202.7~~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 ~~2016 primarily due~~2022 compared to year to date 2021, reflecting an increase in ~~proved~~the amortization of undeveloped leasehold costs driven by an increase in our balance of unproved properties resulting from property ~~impairments partially offset by lower non-producing property impairments as discussed below.~~acquisitions over the past year.

~~Proved property impairments totaled $82.3~~General and Administrative Expenses. Total G&A expenses increased $29.0 million, or 27%, to $137.4 million for year to date ~~2017~~2022 compared to ~~$2.9~~$108.4 million for year to date 2016. The proved property impairments recognized for year to date 2017, nearly all of which were recognized in the second quarter, were primarily concentrated in the Arkoma Woodford field for which we determined the carrying amount of the field was not recoverable from future cash flows, and therefore, was impaired at June 30, 2017. There were no proved property impairments recognized in the 2017 third quarter.2021.

Impairments of non-producing properties decreased $72.3 million, or 36%, to $127.5 million for year to date 2017 compared to $199.8 million for year to date 2016. The decrease was due to a lower balance of unamortized leasehold costs in the current year due to property dispositions and reduced land capital expenditures in recent years, along with changes in the timing and magnitude of amortization of undeveloped leasehold costs between periods resulting from changes in the Company's estimates of undeveloped properties not expected to be developed before lease expiration.

~~General and Administrative Expenses.~~ ~~Total G&A expenses increased $17.4 million, or 15%, from $113.0 million for year to date 2016 to $130.4 million for year to date 2017.~~ Total G&A expenses include non-cash charges for equity compensation of ~~$32.5~~$44.1 million and ~~$34.3~~$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 ~~2017 and year to date 2016, respectively. G&A expenses other~~

~~than equity compensation included in the total G&A expense figure above totaled $97.9 million for year to date 2017,~~2022, an increase of ~~$19.2~~$15.4 million ~~or 24%,~~ compared to ~~$78.7~~$77.9 million for the comparable ~~2016~~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

Nine months ended September 30,
$/Boe 2017 2016
General and administrative expenses $ 1.58
$ 1.31
Non-cash equity compensation 0.52
0.57
Total general and administrative expenses $ 2.10
$ 1.88

~~The increase in G&A expenses other than equity compensation was primarily~~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 employee compensation and benefits in 2017 in response to the stabilization and improvement in commodity prices in late 2016, partially offset by higher overhead recoveries from joint interest owners driven by increased completion activities over the prior period.

~~Interest Expense.~~ Year to date interest expense decreased $26.2 million, or 11%, to $218.7 million compared to $244.9 million for the comparable 2016 period due to a decrease in outstanding debt primarily as a result of the November 2016 redemptions of our ~~$200 million of 2020 Notes and $400 million of 2021 Notes. Our~~ weighted average outstanding ~~long-term~~ debt balance from $5.3 billion for year to date ~~2017 was approximately~~2021 to $6.7 billion ~~with~~for year to date 2022. This increase was driven by debt incurred in the fourth quarter of 2021 to fund a ~~weighted average interest~~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 ~~4.2% compared to averages~~24.5% of ~~$7.2 billion and 4.3% for the comparable period in 2016. The lower interest expense associated with reduced debt was partially offset by higher interest expense being incurred on~~ our ~~variable-rate credit facility and term loan borrowings due to an increase in market interest rates in 2017.~~

~~Income Taxes.~~pre-tax income. We recorded an income tax ~~benefit for the nine months ended September 30, 2017~~provision of ~~$25.1 million compared to a benefit of $259.3~~$580.4 million for the ~~prior~~ year to date period ~~resulting~~of 2022 and an income tax provision of $175.5 million for year to date 2021, which resulted in effective tax rates of ~~approximately 32%~~24.2% and ~~38%~~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 ~~10.~~12. Income Taxes for a summary of the sources and tax effects of items comprising our effective tax ~~rate for the 2017 and 2016 periods.~~rates.

Liquidity and Capital Resources

Our primary sources of liquidity have historically been cash flows generated from operating activities, financing provided by our ~~revolving~~ credit facility and the issuance of debt ~~and equity~~ securities. Additionally, ~~non-strategic~~ asset dispositions and joint development arrangements have provided a ~~significant~~ source of cash flow for use in reducing debt and enhancing liquidity. We ~~intend~~are committed to ~~continue pursuing opportunities~~operating in a responsible manner to ~~reduce~~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 ~~debt~~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 ~~proceeds from additional potential sales of non-strategic assets or through joint development arrangements; however,~~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 ~~transactions will occur.~~

~~At September 30, 2017, we had $10.8 million~~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 ~~and cash equivalents and approximately $1.81 billion~~on hand, utilization of ~~borrowing availability on our revolving~~ credit facility ~~after considering outstanding borrowings~~borrowing capacity, bank term loan facilities, and/or the issuance of $938 million and letters of credit. At October 31, 2017, outstanding borrowings decreased to $895 million, leaving approximately $1.85 billion of borrowing availability on our credit facility at that date. We expect to maintain a disciplined spending approach and plan to manage the level of our capital spending in order to minimize new incremental borrowings and maintain ample liquidity.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 ~~revolving~~ credit facility ~~three-year term loan,~~ and senior note indentures, ~~for at least~~including additional debt that may be incurred to fund the ~~next 12 months.~~potential take-private transaction described above. Further, based on current market indications, we expect to meet ~~in the ordinary course of business other~~our contractual cash commitments to third parties as of ~~September~~June 30, ~~2017,~~2022, including those subsequently described in ~~Note 7. Commitments and Contingencies~~ in ~~Notes to Unaudited Condensed Consolidated Financial Statements~~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 ~~if needed~~ to fund our operations.

Cash Flows

Cash flows from operating activities

~~Our net~~Net cash provided by operating activities ~~totaled $1,348.0 million and $863.9 million~~increased $1.53 billion, or 89%, to $3.24 billion for ~~the nine months ended September 30, 2017 and 2016, respectively. The~~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 ~~cash flows was~~expenses primarily due to an increase in ~~crude oil and natural gas revenues driven by higher realized commodity prices and total~~ sales volumes ~~in 2017 coupled with lower interest~~and growth of our Company over the past year. Increased cash operating expenses ~~the effects of which were partially offset by increases~~included a $101 million increase in production expenses ~~production taxes, and general and administrative expenses~~ and a ~~decrease~~$49 million increase in ~~cash gains on matured natural gas derivatives.~~

transportation, gathering, processing, and compression expenses.

Cash flows ~~used in~~from investing activities

~~During the nine months ended September 30, 2017 and 2016, we had~~Net cash ~~flows~~ used in investing activities of $1,374.3 million and $550.2 million, respectively. These totals include capital spending of $1,459.0 million and $884.5 million, respectively, inclusive of exploration and development drilling, property acquisitions, and dry hole costs. Property acquisitions totaled $28.7 million and $22.6increased $1.08 billion to $1.85 billionfor year to date 2022 compared to $771 million for ~~the nine months ended September 30, 2017 and 2016, respectively. The~~year to date 2021, reflecting our planned increase in ~~capital~~budgeted spending ~~was driven by~~and an increase in ~~our~~the magnitude of year to date property acquisitions. Non-acquisition capital ~~budget~~expenditures attributable to us for full year 2022 are budgeted to be between $2.6 billion and ~~related drilling and completion activities for 2017. We expect our~~$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 ~~remainder of 2017 will continue~~Powder River Basin and $197 million paid to ~~be higher than 2016 levels.~~

~~The use of cash for capital expenditures~~acquire properties in ~~2017 and 2016 was partially offset by proceeds received from asset dispositions, which totaled $84.7~~the Permian Basin as discussed in Note 3. Property Acquisitions as well as $63 million ~~and $334.3 million~~paid for the ~~nine months ended September 30, 2017 and 2016, respectively. See~~ new strategic investment in an affiliate of Summit Carbon Solutions described in Note ~~11. Property Dispositions~~13. Equity Investment in Notes to Unaudited Condensed Consolidated Financial Statements for further discussion of notable dispositions, including a discussion of sales proceeds totaling $59.9 million received by the Company subsequent to September 30, 2017 in conjunction with the consummation of a property disposition in October 2017, which will be reflected in 2017 fourth quarter cash flows from investing activities..

Cash flows from financing activities

Net cash ~~provided by~~used in financing activities for ~~the nine months ended September 30, 2017~~year to date 2022 totaled ~~$20.4~~$862 million, primarily ~~resulting from $33~~consisting of $500 million of net ~~borrowings~~repayments on our ~~revolving~~ credit facility, ~~during the period~~$184 million of cash dividends paid on common stock, $100 million of cash used to ~~fund operations.~~repurchase shares of our common stock, and $32 million of cash used to repurchase senior notes.

Net cash used in financing activities for ~~the nine months ended September 30, 2016~~year to date 2021 totaled ~~$305.6~~$839 million, primarily ~~resulting from~~consisting of $631 million of cash used to redeem senior notes, $160 million of net repayments ~~of $288 million~~ on our ~~revolving~~ credit facility, ~~during the period. The net repayments resulted from the reduction~~and $40 million of ~~credit facility debt using proceeds totaling $334.3 million from 2016 asset dispositions completed through September 30, 2016, partially offset by borrowings incurred to fund operations.~~cash dividends paid on common stock.

~~We plan to manage our level of capital spending for the remainder of 2017 in order to minimize the incurrence of new incremental debt.~~

Future Sources of Financing

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

~~Our planned~~Based on current market indications, our budgeted capital spending ~~has been established based on an expectation of available~~plans for 2022 are expected to be funded from operating cash flows. Any deficiencies in operating cash flows ~~with any cash flow deficiencies~~relative to budgeted spending are expected to be funded by borrowings under our ~~revolving~~ credit ~~facility or proceeds from asset sales.~~

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 ~~revolving~~ credit facility if needed to fund our ~~operations.~~ operations and business plans.

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

We currently anticipate we will be able to generate or obtain funds sufficient to meet our short-term and long-term cash requirements. We intend to fund future capital expenditures primarily through cash flows from operations and through borrowings under our revolving credit facility, but we may also issue debt or equity securities, sell additional assets, or enter into joint development arrangements. The issuance of additional debt requires a portion of our cash flows from operations be used for the payment of interest and principal on our debt, thereby reducing our ability to use cash flows to fund working capital, capital expenditures and acquisitions. The issuance of additional equity securities could have a dilutive effect on the value of our common stock.

~~Revolving credit~~Credit facility

We have an unsecured credit facility, maturing ~~on May 16, 2019,~~in October 2026, with aggregate lender commitments totaling ~~$2.75~~$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 1712 banks and financial institutions. We believe each member of the current syndicate has the capability to fund its commitment.

As of ~~October 31, 2017,~~July 28, 2022, we had ~~approximately $1.85~~no outstanding borrowings and $2.0 billion of borrowing availability on our credit facility after considering outstanding borrowings and letters of credit. Credit facility 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.facility.

The commitments under our ~~revolving~~ 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 ~~would~~do not trigger a reduction in our current credit facility commitments, nor ~~would~~do such actions trigger a security requirement or change in covenants. ~~The weighted-average interest rate on~~Downgrades of our credit ~~facility borrowings was 2.99% at September 30, 2017~~rating will, however, trigger increases in our credit facility's interest rates and ~~we incur~~ commitment fees ~~of 0.30% per annum~~paid on ~~the daily average amount of~~ unused borrowing ~~availability.~~availability under certain circumstances.

Our ~~revolving~~ 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. ~~This~~See Notes to Unaudited Condensed Consolidated Financial Statements–Note 8. Debt for a discussion of how this ratio ~~represents the ratio of net debt (calculated as total face value of debt plus outstanding letters of~~is calculated pursuant to our 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.agreement.

We were in compliance with our ~~revolving~~ credit facility covenants at ~~September~~June 30, ~~2017~~2022 and expect to maintain ~~compliance for at least the next 12 months.~~such compliance. At ~~September~~June 30, ~~2017,~~2022, our consolidated net debt to total capitalization ratio ~~as defined in our revolving credit facility as amended,~~ was ~~0.56 to 1.00.~~0.36. We do not believe the ~~revolving~~ credit facility covenants are reasonably likely to limit our ability to undertake additional debt financing ~~to a material extent~~ 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 ~~September~~June 30, ~~2017,~~2022, our total debt would have needed to independently increase by approximately ~~$2.9~~$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 ~~$1.6~~$7.4 billion (excluding the after-tax impact of any non-cash impairment charges) below the existing level at ~~September~~June 30, ~~2017~~2022 to reach the maximum covenant ratio. These independent point-in-time sensitivities do not take into account other factors that could arise to mitigate the impact of changes in debt and equity on our consolidated net debt to total capitalization ratio, such as disposing of assets or exploring alternative sources of capitalization.

~~Joint development agreement funding~~

In September 2014, we entered into an agreement with a U.S. subsidiary of SK E&S Co. Ltd ("SK") of South Korea to jointly develop a portion of the Company's STACK properties. Pursuant to the agreement SK will fund, or carry, 50% of our drilling and completion costs attributable to an area of mutual interest targeting the Woodford formation in the STACK play until approximately $270 million has been expended by SK on our behalf. As of September 30, 2017, approximately $112 million of the carry had yet to be realized and is expected to be realized through mid-2019.

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 ~~$5.2~~$6.33 billion at ~~September~~June 30, ~~2017. We have no near-term senior note maturities, with our earliest scheduled senior note maturity being our $2.0 billion~~2022, exclusive of ~~2022 Notes due in September 2022.~~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 ~~6. Long-Term~~8. Debtin Notes to Unaudited Condensed Consolidated Financial Statements.

We were in compliance with our senior note covenants at ~~September~~June 30, ~~2017~~2022 and expect to maintain ~~compliance for at least the next 12 months.~~such compliance. We do not believe the senior note covenants will materially limit our ability to undertake additional debt ~~financing.~~ 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 ~~would~~do not trigger additional senior note covenants.

Transportation, gathering, and processing commitments

Three of our subsidiaries, Banner Pipeline Company, L.L.C., CLR Asset Holdings, LLC, and The Mineral Resources Company, which have no material assets or operations, fully and unconditionally guarantee the senior notes on a joint and several basis. Our other subsidiaries, the value of whose assets and operations are minor, do not guarantee the senior notes as of September 30, 2017.

~~Term loan~~

We have ~~a $500 million unsecured term loan that matures in full in November 2018~~entered into transportation, gathering, and ~~bears interest at variable market-based interest rates plus a margin based~~processing commitments to guarantee capacity on the terms of the borrowing and the credit ratings assigned to the Company's senior, unsecured, long-term indebtedness. Downgrades or other negative rating actions with respect to our credit rating would not trigger a security requirement or change in covenants for the term loan. The interest rate on the term loan was 2.76% at September 30, 2017.

~~Capital expenditures~~

~~We evaluate opportunities to purchase or sell~~ crude oil and natural gas ~~properties~~pipelines and ~~expect~~natural gas processing facilities that require us to ~~participate~~pay per-unit charges regardless of the amount of capacity used. Future commitments remaining as ~~a buyer or seller~~ of ~~properties at various times. We seek acquisitions that utilize our technical expertise or offer opportunities~~June 30, 2022 under the arrangements amount to ~~expand our existing core areas. Acquisition~~approximately $1.19 billion. See Note 9. Commitments and Contingencies in Notes to Unaudited Condensed Consolidated Financial Statements for additional information.

Capital expenditures ~~are not budgeted.~~

Our capital expenditures budget for ~~2017 is $1.95 billion excluding acquisitions, which~~2022 is expected to be ~~allocated~~$2.6 billion to $2.7 billion. Costs of acquisitions and investments, such as ~~follows:~~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.

In millions Amount
Exploration and development drilling $ 1,720
Land costs 115
Capital facilities, workovers and other corporate assets 105
Seismic 10
Total 2017 capital budget, excluding acquisitions $ 1,950

For the ~~nine~~six months ended ~~September~~June 30, ~~2017,~~2022, we invested ~~approximately $1,499.5 million~~$1.17 billion in our capital program excluding ~~$28.7~~$662.3 million of unbudgeted acquisitions, excluding $3.7 million of mineral acquisitions attributable to Franco-Nevada, and including ~~$66.3~~$50.3 million of capital costs associated with increased accruals for capital expenditures ~~and including $2.8 million of seismic costs.~~as compared to December 31, 2021. Our ~~2017~~2022 year to date capital expenditures were allocated as ~~follows by quarter:~~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

In millions 1Q 2017 2Q 2017 3Q 2017 YTD 2017
Exploration and development drilling $ 329.8
$ 471.0
$ 444.7
$ 1,245.5
Land costs 68.8
49.8
47.7
166.3
Capital facilities, workovers and other corporate assets 27.4
29.3
28.2
84.9
Seismic 1.0
1.8
—
2.8
Capital expenditures, excluding acquisitions 427.0
551.9
520.6
1,499.5
Acquisitions of producing properties 0.1
0.7
2.7
3.5
Acquisitions of non-producing properties 13.3
5.1
6.8
25.2
Total acquisitions 13.4
5.8
9.5
28.7
Total capital expenditures $ 440.4
$ 557.7
$ 530.1
$ 1,528.2

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, ~~access to capital,~~ 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 ~~scale back~~adjust our ~~capital~~ spending ~~plans~~ should commodity prices ~~decrease~~materially change from current levels. ~~Conversely, an increase in commodity prices from current levels could result in increased capital expenditures.~~ 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 ~~competitive~~attractive terms.

~~Commitments~~Strategic Investment

~~Refer to~~ See Note ~~7. Commitments and Contingencies~~ 13. Equity Investment in Notes to Unaudited Condensed Consolidated Financial Statementsfor 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 ~~future commitments~~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 ~~Company~~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 ~~September 30, 2017. We believe our~~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

~~flows from operations, our remaining cash balance, and amounts available under our revolving credit facility will be sufficient to satisfy our commitments.~~

~~Off-balance sheet arrangements~~

~~Currently, we do not have any off-balance sheet arrangements with unconsolidated entities to enhance liquidity and capital resources.~~

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 ~~2016~~2021 Form 10-K.

~~New Accounting Pronouncements~~

~~See~~

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 ~~2. Basis~~5. Revenues. For non-operated properties, we receive a net payment from the operator for our share of ~~Presentation~~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 ~~Significant Accounting Policies~~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 ~~discussion~~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 ~~impact upon adoption of new accounting pronouncements in 2017 along with a discussion of accounting pronouncements not yet adopted.~~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~~

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 ~~our~~ crude oil, natural gas, and natural gas ~~production.~~liquids. Realized pricing is primarily driven by the prevailing worldwide price for crude oil and spot market prices applicable to our natural gas ~~production. Pricing for crude oil~~ and natural gas ~~has~~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 ~~volatility in the~~ differences between product prices at sales points and the applicable index prices. Based on our average daily production for the ~~nine~~six months ended ~~September~~June 30, ~~2017,~~2022, and excluding ~~any~~the effect of ~~our~~ derivative instruments in place, our annual revenue would increase or decrease by approximately ~~$469~~$717 million for each $10.00 per barrel change in crude oil prices at ~~September~~June 30, ~~2017~~2022 and ~~$217~~$417 million for each $1.00 per Mcf change in natural gas prices at ~~September~~June 30, ~~2017.~~2022.

To reduce price risk caused by market fluctuations in ~~crude oil and natural gas~~commodity prices, from time to time we may economically hedge a portion of our anticipated ~~crude oil and natural gas~~ 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.~~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 ~~liquidate~~settle existing derivative positions prior to the expiration of their contractual ~~maturities in order to monetize gain positions for the purpose of funding our capital program.~~maturities. While hedging, if utilized, limits the downside risk of adverse price movements, it also limits future revenues from upward price movements. ~~We have hedged a portion~~

The fair value of our ~~future~~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 ~~production through March 2018. Our future~~derivatives and a $15.2 million net liability associated with our crude oil ~~production, and future natural gas production beyond March 2018, is currently unhedged and directly exposed~~derivatives. The following table shows how a hypothetical +/- 10% change in the underlying forward prices used to ~~continued volatility in market prices, whether favorable or unfavorable.~~

~~Changes in natural gas prices during the nine months ended September 30, 2017 had an overall favorable impact on~~calculate the fair value of our ~~derivative instruments. For~~derivatives would impact the ~~nine months ended September 30, 2017, we recognized cash gains on natural gas derivatives of $15.0 million and non-cash mark-to-market gains on natural gas derivatives of $68.5 million.~~

~~The~~ fair value estimates as of ~~our natural gas derivative instruments at September~~June 30, 2017 was a net asset of $9.0 million. An assumed increase in the forward prices used in the September 30, 2017 valuation of our natural gas derivatives of $1.00 per MMBtu would change our natural gas derivative valuation to a net liability of approximately $29 million at September 30, 2017. Conversely, an assumed decrease in forward prices of $1.00 per MMBtu would increase our natural gas derivative asset to approximately $43 million at September 30, 2017. 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 ~~natural gas~~ 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 ~~crude oil and natural gas~~ production, which we market to energy marketing companies, crude oil refining companies, and natural gas gathering and processing companies ($~~472 million~~1.8 billion in receivables at ~~September~~June 30, ~~2017);~~2022), and our joint interest and other receivables ($~~452~~336 million at ~~September~~June 30, ~~2017); and counterparty credit risk associated with our derivative instrument receivables ($11 million at September 30, 2017)~~2022).

We monitor our exposure to counterparties on ~~crude oil and natural gas~~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 ~~crude oil and natural gas~~commodity sales receivables owed to us. Historically, our credit losses on ~~crude oil and natural gas~~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 ~~$55~~$19 million at ~~September~~June 30, ~~2017,~~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 ~~redirect~~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.

Our use of derivative instruments involves the risk that our counterparties will be unable to meet their commitments under the arrangements. We manage this risk by using multiple counterparties who we consider to be financially strong in order to minimize our exposure to credit risk with any individual counterparty.

Interest Rate Risk. Our exposure to changes in interest rates relates primarily to ~~any~~ variable-rate borrowings we may have outstanding from time to time under our ~~revolving~~ credit ~~facility and three-year term loan.~~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.

We had an aggregate of approximately $1.40 billion of variable rate borrowings outstanding on our revolving credit facility and three-year term loan at October 31, 2017. The impact of a 0.25% increase in interest rates on this amount of debt would result in increased interest expense of approximately $3.5 million per year and a $2.2 million decrease in net income per year.

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 ~~September~~June 30, ~~2017~~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 ~~September~~June 30, ~~2017,~~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~~

ITEM 1. Legal Proceedings

See Note 7.9. Commitments and ~~Contingencies–Litigation~~ Contingencies in ~~Part I, Item I. Financial Statements–~~Notes to Unaudited Condensed Consolidated Financial Statements for a ~~discussion~~case filed in the Northern District of ~~the legal matter involving the Company, Billy J. Strack~~California and ~~Daniela A. Renner,~~a case filed in Oklahoma state court, which isare incorporated herein by reference.

We have received Notices of Violation from the North Dakota Department of Health ("NDDH") alleging violations of the state’s air quality and water pollution control laws and rules. We exchanged information and engaged in discussions with NDDH aimed at resolving the allegations in August and October 2017, and anticipate further such discussions and exchanges. Resolution of the allegations~~may result in monetary sanctions of more than $100,000.~~


~~ITEM 1A.~~	~~Risk Factors~~

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 ~~2016~~2021 Form 10-K, which could materially affect our business, financial condition or future results. The risks described in this Form 10-Q ~~if any,~~ and in our ~~2016~~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.

~~There have been no~~A discussion of material changes in our risk factors from those disclosed in our ~~2016~~2021 Form ~~10-K.~~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~~

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.~~

(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 ~~following~~ table below provides information about purchases of shares of our common stock during the three months ended ~~September~~June 30, ~~2017:~~

Period Total number of shares purchased (1) Average price paid per share (2) Total number of shares purchased as part of publicly announced plans or programs Maximum number of shares that may yet be purchased under the plans or programs
July 1, 2017 to July 31, 2017 —
—
—
—
August 1, 2017 to August 31, 2017 8,629
$ 33.14
—
—
September 1, 2017 to September 30, 2017 2,054
$ 38.68
—
—
Total 10,683
$ 34.21
—
—


~~(1)~~	In connection with restricted stock grants under the Company's 2013 Long-Term Incentive Plan, we adopted a policy that enables employees to surrender shares to cover their tax liability. Shares indicated as having been purchased in the table above represent shares surrendered by employees to cover tax liabilities. We paid the associated taxes to the applicable taxing authorities.


~~(2)~~	~~The price paid per share was the closing price of our common stock on the date the restrictions lapsed on such shares.~~

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~~

ITEM 3. Defaults Upon Senior Securities

Not applicable.


~~ITEM 4.~~	~~Mine Safety Disclosures~~

ITEM 4. Mine Safety Disclosures

Not applicable.

ITEM 5. Other Information

Not applicable.


~~ITEM 6.~~	~~Exhibits~~

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 ~~amendment~~amendments filed on June 15, 2015 and May 21, 2020 filed as Exhibit 3.1 to the ~~Company’s~~Company's Form 10-Q for the quarterly period ended June 30, ~~2015~~2020 (Commission File No. 001-32886) filed August ~~5, 2015~~3, 2020 and incorporated herein by reference.

3.2						Third Amended and Restated Bylaws of Continental Resources, Inc. filed as Exhibit ~~3.1~~ 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 ~~November 6, 2012~~May 19, 2022 and incorporated herein by reference.

31.1*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			~~Filed herewith~~			Cover Page Interactive Data File (formatted as Inline XBRL and contained in Exhibit 101)


**	~~Furnished herewith~~

* 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

~~CONTINENTAL RESOURCES, INC.~~

By:

~~Date:~~

~~November 7, 2017~~

~~By:~~

/s/ John D. Hart

John D. Hart

~~Sr. Vice President,~~ Chief Financial Officer and ~~Treasurer~~
Executive Vice President of Strategic Planning
(Duly Authorized Officer and Principal Financial Officer)

3840



				Collars
Natural Gas - NYMEX Henry Hub		Swaps Weighted Average Price		Floors			Ceilings
					Weighted Average Price			Weighted Average Price
Period and Type of Contract	MMBtus			Range	Weighted Average Price		Range	Weighted Average Price
October 2017 - December 2017
Swaps - Henry Hub	33,120,000	$	3.39
Collars - Henry Hub	16,560,000			$2.40 - $3.00	$	2.47	$2.92 - $3.88	$	3.08
January 2018 - March 2018
Swaps - Henry Hub	6,300,000	$	3.28



	2022 Notes (1)	2023 Notes	2024 Notes	2044 Notes
Face value (in thousands)	$2,000,000	$1,500,000	$1,000,000	$700,000
Maturity date	Sep 15, 2022	April 15, 2023	June 1, 2024	June 1, 2044
Interest payment dates	March 15, Sep 15	April 15, Oct 15	June 1, Dec 1	June 1, Dec 1
Make-whole redemption period (2)	—	Jan 15, 2023	Mar 1, 2024	Dec 1, 2043



	Three months ended September 30,										Nine months ended September 30,
$ in thousands	2017			Tax rate %		2016			Tax rate %		2017			Tax rate %		2016			Tax rate %
Expected income tax (provision) benefit based on US statutory tax rate of 35%	$	(6,087	)	35.0	%	$	61,214		35.0	%	$	27,136		35.0	%	$	240,311		35.0	%
State income taxes, net of federal benefit	(522		)	3.0	%	5,247			3.0	%	2,326			3.0	%	20,598			3.0	%
Tax deficiency from stock-based compensation (1)	(134		)	0.8	%	—			—	%	(3,907		)	(5.0	%)	—			—	%
Canadian valuation allowance (2)	(68		)	0.4	%	(665		)	(0.4	%)	(325		)	(0.4	%)	(959		)	(0.1	%)
Effect of differing statutory tax rate in Canada	(34		)	0.1	%	(313		)	(0.2	%)	(156		)	(0.3	%)	(437		)	(0.1	%)
Other, net	75			(0.4	%)	(207		)	(0.1	%)	(11		)	—	%	(259		)	—	%
(Provision) benefit for income taxes	$	(6,770	)	38.9	%	$	65,276		37.3	%	$	25,063		32.3	%	$	259,254		37.8	%



Boe production per day	3Q 2017	2Q 2017	% Change from 2Q 2017		3Q 2016	% Change from 3Q 2016
Bakken	136,851	119,861	14	%	107,929	27	%
SCOOP	57,283	61,107	(6	%)	67,462	(15	%)
STACK	35,619	31,934	12	%	17,680	101	%
All other	13,035	13,311	(2	%)	14,769	(12	%)
Total	242,788	226,213	7	%	207,840	17	%



	Nine months ended September 30,						Volume increase (decrease)		Volume percent increase (decrease)
	2017			2016
	Volume	Percent		Volume	Percent
Crude oil (MBbl)	35,074	56	%	36,133	60	%	(1,059	)	(3	%)
Natural gas (MMcf)	162,515	44	%	143,697	40	%	18,818		13	%
Total (MBoe)	62,160	100	%	60,083	100	%	2,077		3	%

	Nine months ended September 30,						Volume increase (decrease)		Volume percent increase (decrease)
	2017			2016
	MBoe	Percent		MBoe	Percent
North Region	36,106	58	%	37,243	62	%	(1,137	)	(3	%)
South Region	26,054	42	%	22,840	38	%	3,214		14	%
Total	62,160	100	%	60,083	100	%	2,077		3	%



In millions	Amount
Exploration and development drilling	$	1,720
Land costs	115
Capital facilities, workovers and other corporate assets	105
Seismic	10
Total 2017 capital budget, excluding acquisitions	$	1,950



In millions	1Q 2017		2Q 2017		3Q 2017		YTD 2017
Exploration and development drilling	$	329.8	$	471.0	$	444.7	$	1,245.5
Land costs	68.8		49.8		47.7		166.3
Capital facilities, workovers and other corporate assets	27.4		29.3		28.2		84.9
Seismic	1.0		1.8		—		2.8
Capital expenditures, excluding acquisitions	427.0		551.9		520.6		1,499.5
Acquisitions of producing properties	0.1		0.7		2.7		3.5
Acquisitions of non-producing properties	13.3		5.1		6.8		25.2
Total acquisitions	13.4		5.8		9.5		28.7
Total capital expenditures	$	440.4	$	557.7	$	530.1	$	1,528.2



Period	Total number of shares purchased (1)	Average price paid per share (2)		Total number of shares purchased as part of publicly announced plans or programs	Maximum number of shares that may yet be purchased under the plans or programs
July 1, 2017 to July 31, 2017	—	—		—	—
August 1, 2017 to August 31, 2017	8,629	$	33.14	—	—
September 1, 2017 to September 30, 2017	2,054	$	38.68	—	—
Total	10,683	$	34.21	—	—