SEC Form 10-Q filed by Continental Resources Inc.

 

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

________________________________________

FORM 10-Q

________________________________________

(Mark One)

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

For the quarterly period ended March 31, 2023

or

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

For the transition period from to

Commission File Number: 001-32886

____________________________________

 

CONTINENTAL RESOURCES, INC

(Exact name of registrant as specified in its charter)

____________________________________

Oklahoma						73-0767549
(State or other jurisdiction of incorporation or organization)						(I.R.S. Employer Identification No.)
		20 N. Broadway,	Oklahoma City,	Oklahoma	73102
		(Address of principal executive offices)			(Zip Code)

(405) 234-9000

(Registrant’s telephone number, including area code)

Not Applicable

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

Securities registered pursuant to Section 12(b) of the Act: None

____________________________________

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 ¨ No x

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

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

Large accelerated filer		☐		Accelerated filer		☐
Non-accelerated filer		x		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

As of March 31, 2023, there are no publicly traded common shares of Continental Resources, Inc.

 

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Table of Contents

PART I. Financial Information
Item 1.	Financial Statements	1
	Condensed Consolidated Balance Sheets	1
	Unaudited Condensed Consolidated Statements of Income	2
	Unaudited Condensed Consolidated Statements of Equity	3
	Unaudited Condensed Consolidated Statements of Cash Flows	4
	Notes to Unaudited Condensed Consolidated Financial Statements	5
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	16
Item 3.	Quantitative and Qualitative Disclosures About Market Risk	25
Item 4.	Controls and Procedures	26
PART II. Other Information
Item 1.	Legal Proceedings	27
Item 1A.	Risk Factors	27
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	27
Item 3.	Defaults Upon Senior Securities	27
Item 4.	Mine Safety Disclosures	27
Item 5.	Other Information	27
Item 6.	Exhibits	28
	Signature	29
When we refer to “us,” “we,” “our,” “Company,” or “Continental” we are describing Continental Resources, Inc. and our subsidiaries.

 

 

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Glossary of Crude Oil and Natural Gas Terms

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

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

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

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

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

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

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

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

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

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

“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 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.

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

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

“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.

“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.

“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.

 

 

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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:

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, 2022, and other announcements we make from time to time.

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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, 2022 occur, or should underlying assumptions prove incorrect, the Company’s actual results and plans could differ materially from those expressed in any forward-looking statements. All forward-looking statements are expressly qualified in their entirety by this cautionary statement.

Except as 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.

 

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PART I. Financial Information

ITEM 1. Financial Statements

 

Continental Resources, Inc. and Subsidiaries

Condensed Consolidated Balance Sheets

 

		March 31, 2023				December 31, 2022
In thousands, except par values and share data		(Unaudited)
Assets
Current assets:
Cash and cash equivalents		$	55,565			$	137,788
Receivables:
Crude oil, natural gas, and natural gas liquids sales			1,058,252				1,313,538
Joint interest and other			460,337				458,391
Allowance for credit losses			(5,285	)			(5,514	)
Receivables, net			1,513,304				1,766,415
Derivative assets			245,891				39,280
Inventories			192,933				173,264
Prepaid expenses and other			32,347				27,508
Total current assets			2,040,040				2,144,255
Net property and equipment, based on successful efforts method of accounting			19,120,782				18,471,914
Investment in unconsolidated affiliates			210,142				210,805
Operating lease right-of-use assets			25,318				25,158
Derivative assets, noncurrent			6,180				3,548
Other noncurrent assets			17,212				22,670
Total assets		$	21,419,674			$	20,878,350
Liabilities and equity
Current liabilities:
Accounts payable trade		$	1,026,928			$	850,547
Revenues and royalties payable			658,113				882,256
Accrued liabilities and other			274,175				343,777
Current portion of incentive compensation liability			80,966				125,653
Current portion of income tax liabilities			291,212				152,149
Derivative liabilities			—				88,136
Current portion of operating lease liabilities			4,806				4,086
Current portion of long-term debt			638,379				638,058
Total current liabilities			2,974,579				3,084,662
Long-term debt, net of current portion			7,373,823				7,571,582
Other noncurrent liabilities:
Deferred income tax liabilities, net			2,639,005				2,538,312
Incentive compensation liability, net of current portion			16,360				100,066
Asset retirement obligations, net of current portion			259,353				257,152
Derivative liabilities, noncurrent			99,653				133,363
Operating lease liabilities, net of current portion			19,454				20,055
Other noncurrent liabilities			29,475				43,550
Total other noncurrent liabilities			3,063,300				3,092,498
Commitments and contingencies (Note 9)
Equity:
Preferred stock, $0.01 par value; 25,000,000 shares authorized; no shares issued and outstanding			—				—
Common stock, $0.01 par value; 1,000,000,000 shares authorized
299,610,267 shares issued and outstanding at March 31, 2023;
299,610,267 shares issued and outstanding at December 31, 2022;			2,996				2,996
Retained earnings			7,639,087				6,754,174
Total shareholders’ equity attributable to Continental Resources			7,642,083				6,757,170
Noncontrolling interests			365,889				372,438
Total equity			8,007,972				7,129,608
Total liabilities and equity		$	21,419,674			$	20,878,350

 

 

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

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Continental Resources, Inc. and Subsidiaries

Unaudited Condensed Consolidated Statements of Income

		Three months ended March 31,
In thousands, except per share data		2023				2022
Revenues:
Crude oil, natural gas, and natural gas liquids sales		$	1,791,720			$	2,274,261
Gain (loss) on derivative instruments, net			382,779				(475,938	)
Crude oil and natural gas service operations			19,354				17,915
Total revenues			2,193,853				1,816,238
Operating costs and expenses:
Production expenses			181,986				137,280
Production and ad valorem taxes			136,175				158,365
Transportation, gathering, processing, and compression			77,869				74,849
Exploration expenses			3,378				13,017
Crude oil and natural gas service operations			17,832				8,561
Depreciation, depletion, amortization and accretion			476,454				459,029
Property impairments			13,074				24,248
General and administrative expenses			63,271				74,837
Net (gain) loss on sale of assets and other			(186	)			(165	)
Total operating costs and expenses			969,853				950,021
Income from operations			1,224,000				866,217
Other income (expense):
Interest expense			(99,681	)			(72,555	)
Other			1,754				(1,227	)
			(97,927	)			(73,782	)
Income before income taxes			1,126,073				792,435
Provision for income taxes			(239,756	)			(191,084	)
Income before equity in net loss of affiliate			886,317				601,351
Equity in net loss of affiliate			(663	)			—
Net income			885,654				601,351
Net income attributable to noncontrolling interests			1,357				3,594
Net income attributable to Continental Resources		$	884,297			$	597,757
Net income per share attributable to Continental Resources:
Basic		$	2.95			$	1.67
Diluted		$	2.95			$	1.65

 

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

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Continental Resources, Inc. and Subsidiaries

Unaudited Condensed Consolidated Statements of Equity

 

Three Months Ended March 31, 2023
		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, 2022			299,610,267			$	2,996			$	—			$	—			$	6,754,174			$	6,757,170			$	372,438			$	7,129,608
Net income			—				—				—				—				884,297				884,297				1,357				885,654
Change in dividends payable			—				—				—				—				616				616				—				616
Contributions from noncontrolling interests			—				—				—				—				—				—				2,526				2,526
Distributions to noncontrolling interests			—				—				—				—				—				—				(10,432	)			(10,432	)
Balance at March 31, 2023			299,610,267			$	2,996			$	—			$	—			$	7,639,087			$	7,642,083			$	365,889			$	8,007,972

 

 

Three Months Ended March 31, 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			—				—				—				—				597,757				597,757				3,594				601,351
Cash dividends declared			—				—				—				—				(83,766	)			(83,766	)			—				(83,766	)
Change in dividends payable			—				—				—				—				(19	)			(19	)			—				(19	)
Common stock repurchased			—				—				—				(99,855	)			—				(99,855	)			—				(99,855	)
Common stock retired			(1,842,422	)			(18	)			(99,837	)			99,855				—				—				—				—
Stock-based compensation			—				—				29,230				—				—				29,230				—				29,230
Restricted stock:
Granted			1,296,028				13				—				—				—				13				—				13
Repurchased and canceled			(481,024	)			(5	)			(26,018	)			—				—				(26,023	)			—				(26,023	)
Forfeited			(144,017	)			(2	)			—				—				—				(2	)			—				(2	)
Contributions from noncontrolling interests			—				—				—				—				—				—				1,803				1,803
Distributions to noncontrolling interests			—				—				—				—				—				—				(8,614	)			(8,614	)
Balance at March 31, 2022			363,126,085			$	3,631			$	1,034,977			$	—			$	6,854,183			$	7,892,791			$	377,652			$	8,270,443

 

 

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

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Continental Resources, Inc. and Subsidiaries

Unaudited Condensed Consolidated Statements of Cash Flows

 

		Three months ended March 31,
In thousands		2023				2022
Cash flows from operating activities
Net income		$	885,654			$	601,351
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, depletion, amortization and accretion			479,602				459,286
Property impairments			13,074				24,248
Non-cash (gain) loss on derivatives			(331,089	)			453,698
Stock/incentive-based compensation			968				29,257
Provision for deferred income taxes			100,693				94,982
Equity in net loss of affiliate			663				—
Dry hole costs			—				10,425
Net (gain) loss on sale of assets and other			(186	)			(165	)
Other, net			3,988				5,360
Changes in assets and liabilities:
Accounts receivable			253,744				(481,812	)
Inventories			(19,669	)			(49,737	)
Other current assets			(3,191	)			(6,626	)
Accounts payable trade			61,761				59,981
Revenues and royalties payable			(223,212	)			185,859
Accrued liabilities and other			(67,713	)			24,513
Current incentive compensation liability			(129,362	)			—
Current income taxes liability			139,063				95,957
Other noncurrent assets and liabilities			(14,950	)			(1,960	)
Net cash provided by operating activities			1,149,838				1,504,617
Cash flows from investing activities
Exploration and development			(863,989	)			(523,652	)
Purchase of producing crude oil and natural gas properties			(97,550	)			(441,929	)
Purchase of other property and equipment			(60,374	)			(11,069	)
Proceeds from sale of assets			1,223				584
Contributions to unconsolidated affiliates			—				(64,928	)
Net cash used in investing activities			(1,020,690	)			(1,040,994	)
Cash flows from financing activities
Credit facility borrowings			1,073,000				899,000
Repayment of credit facility			(1,272,000	)			(1,164,000	)
Repayment of other debt			(597	)			(576	)
Debt issuance costs			(241	)			(101	)
Contributions from noncontrolling interests			1,872				2,778
Distributions to noncontrolling interests			(11,354	)			(8,235	)
Repurchase of common stock prior to take-private transaction			—				(99,855	)
Repurchase of restricted stock for tax withholdings			—				(26,023	)
Dividends paid on common stock			(2,051	)			(83,235	)
Net cash used in financing activities			(211,371	)			(480,247	)
Net change in cash and cash equivalents			(82,223	)			(16,624	)
Cash and cash equivalents at beginning of period			137,788				20,868
Cash and cash equivalents at end of period		$	55,565			$	4,244

 

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

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Continental Resources, Inc. and Subsidiaries

Notes to Unaudited Condensed Consolidated Financial Statements

 

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Continental Resources, Inc. and Subsidiaries

Notes to Unaudited Condensed Consolidated Financial Statements

 

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Continental Resources, Inc. and Subsidiaries

Notes to Unaudited Condensed Consolidated Financial Statements

 

 

 

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

The following discussion and analysis should be read in conjunction with the unaudited condensed consolidated financial statements and notes thereto included elsewhere in this report and our historical consolidated financial statements and notes included in our Form 10-K for the year ended December 31, 2022.

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 Form 10-K for the year ended December 31, 2022, along with Cautionary Statement for the Purpose of the “Safe Harbor” Provisions of the Private Securities Litigation Reform Act of 1995 at the beginning of this report, for information about the risks and uncertainties that could cause our actual results to be materially different than our forward-looking statements.

Overview

We are an independent crude oil and natural gas company engaged in the exploration, development, management, and production of crude oil and natural gas and associated products with properties primarily located in four leading basins in the United States – the Bakken field of North Dakota and Montana, the Anadarko Basin of Oklahoma, the Permian Basin of Texas, and the Powder River Basin of Wyoming. Additionally, we pursue the acquisition and management of perpetually owned minerals located in certain of our key operating areas. We derive the majority of our operating income and cash flows from the sale of crude oil, natural gas, and natural gas liquids and expect this to continue in the future. Our corporate internet website is www.clr.com. As discussed in Note 1. Organization and Nature of Business—2022 Take-Private Transaction in Notes to Unaudited Condensed Consolidated Financial Statements, effective November 22, 2022 Continental Resources, Inc. became a privately held corporation and has no publicly available common shares outstanding.

First Quarter 2023 Financial and Operating Metrics

The following table contains financial and operating metrics for the first quarter periods of 2023 and 2022. Average net sales prices exclude any effect of derivative transactions. Per-unit expenses have been calculated using sales volumes.

 

		Three months ended March 31,
		2023				2022
Average daily production:
Crude oil (Bbl per day)			206,232				194,767
Natural gas (Mcf per day) (1)			1,205,772				1,074,255
Crude oil equivalents (Boe per day)			407,194				373,810
Average net sales prices (2):
Crude oil ($/Bbl)		$	72.32			$	90.83
Natural gas ($/Mcf) (1)		$	3.61			$	6.34
Crude oil net sales price discount to NYMEX ($/Bbl)		$	(3.74	)		$	(3.47	)
Natural gas net sales price premium to NYMEX ($/Mcf) (1)		$	0.17			$	1.43
Production expenses ($/Boe)		$	5.00			$	4.09
Production and ad valorem taxes (% of net crude oil and natural gas sales)			7.9	%			7.2	%
Depreciation, depletion, amortization and accretion ($/Boe)		$	13.10			$	13.67
Total general and administrative expenses ($/Boe)		$	1.74			$	2.23

 

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Three months ended March 31, 2023 compared to the three months ended March 31, 2022

Results of Operations

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

 

		Three months ended March 31,
In thousands		2023				2022
Crude oil, natural gas, and natural gas liquids sales		$	1,791,720			$	2,274,261
Gain (loss) on derivative instruments, net			382,779				(475,938	)
Crude oil and natural gas service operations			19,354				17,915
Total revenues			2,193,853				1,816,238
Operating costs and expenses			(969,853	)			(950,021	)
Other expenses, net			(97,927	)			(73,782	)
Income before income taxes			1,126,073				792,435
Provision for income taxes			(239,756	)			(191,084	)
Income before equity in net loss of affiliate			886,317				601,351
Equity in net loss of affiliate			(663	)			—
Net income			885,654				601,351
Net income attributable to noncontrolling interests			1,357				3,594
Net income attributable to Continental Resources		$	884,297			$	597,757
Production volumes:
Crude oil (MBbl)			18,561				17,529
Natural gas (MMcf)			108,519				96,683
Crude oil equivalents (MBoe)			36,647				33,643
Sales volumes:
Crude oil (MBbl)			18,286				17,461
Natural gas (MMcf)			108,519				96,683
Crude oil equivalents (MBoe)			36,372				33,575

 

Production

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

 

Boe production per day		1Q 2023				1Q 2022				% Change
Bakken			179,280				171,401				5	%
Anadarko Basin			152,554				143,963				6	%
Powder River Basin			23,333				11,653				100	%
Permian Basin			46,152				40,248				15	%
All other			5,875				6,545				(10	)%
Total			407,194				373,810				9	%

 

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

 

		Three months ended March 31,																				Volume
		2023								2022								Volume				percent
		Volume				Percent				Volume				Percent				increase				increase
Crude oil (MBbl)			18,561				51	%			17,529				52	%			1,032				6	%
Natural gas (MMcf)			108,519				49	%			96,683				48	%			11,836				12	%
Total (MBoe)			36,647				100	%			33,643				100	%			3,004				9	%

 

The 6% increase in crude oil production in the 2023 first quarter was primarily driven by our property acquisitions and subsequent new well completions in the Permian Basin and Powder River Basin over the past year, which contributed to an increase in our 2023 first quarter production by 950 MBbls compared to the 2022 first quarter. Additionally, our crude oil production in the Bakken field increased 461 MBbls, or 4%, in the 2023 first quarter due to new well completions over the past year. These increases were partially offset by a 327 MBbls, or 11%, decrease in crude oil production in the Anadarko Basin due to 2022 capital spending being allocated primarily to gas-weighted projects in the play.

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The 12% increase in natural gas production in the 2023 first quarter was due in part to the previously described property acquisitions over the past year. Properties acquired in the Permian Basin, Powder River Basin, and subsequent new well completions increased our 2023 first quarter production by 3,798 MMcf compared to the 2022 first quarter. Additionally, natural gas production in the Anadarko Basin increased 6,605 MMcf, or 11%, and Bakken natural gas production increased 1,489 MMcf, or 5%, over the 2022 first quarter due to new well completions over the past year.

Revenues

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

Net crude oil, natural gas, and natural gas liquids sales. Net sales totaled $1.71 billion for the first quarter of 2023, a 22% decrease compared to net sales of $2.20 billion for the 2022 first quarter due to decreases in net sales prices, partially offset by increases in sales volumes as discussed below.

Total sales volumes for the first quarter of 2023 increased 2,797 MBoe, or 8%, compared to the 2022 first quarter due to additional drilling and completion activities and new wells added from property acquisitions over the past year. For the first quarter of 2023, our crude oil sales volumes increased 5% and our natural gas sales volumes increased 12% compared to the 2022 first quarter.

Our crude oil net sales prices averaged $72.32 per barrel in the 2023 first quarter compared to $90.83 per barrel for the 2022 first quarter due to a significant decrease in market prices resulting from changes in various macroeconomic conditions between periods. The differential between NYMEX West Texas Intermediate calendar month prices and our realized crude oil net sales prices averaged $3.74 per barrel for the 2023 first quarter compared to $3.47 per barrel for the 2022 first quarter.

Our natural gas net sales prices averaged $3.61 per Mcf for the 2023 first quarter compared to $6.34 per Mcf for the 2022 first quarter due to a significant decrease in market prices and price realizations. The difference between our net sales prices and NYMEX Henry Hub calendar month natural gas prices was a premium of $0.17 per Mcf for the 2023 first quarter compared to a premium of $1.43 per Mcf for the 2022 first quarter. We sell the majority of our operated natural gas production to midstream customers at lease locations based on market prices in the field where the sales occur. The field markets are impacted by residue gas and natural gas liquids (“NGLs”) prices at secondary, downstream markets. NGL prices in 2023 have decreased from first quarter 2022 levels in conjunction with decreased crude oil prices and other factors, resulting in reduced price realizations for our natural gas sales stream relative to benchmark prices.

Derivatives. Reduced commodity prices during the first quarter of 2023 had a significant favorable impact on the fair value of our derivatives, which resulted in positive revenue adjustments totaling $382.8 million for the period, representing $51.7 million of cash gains and $331.1 million of unsettled non-cash gains, compared to negative revenue adjustments totaling $475.9 million in the first quarter of 2022.

Operating Costs and Expenses

Production Expenses. Production expenses increased $44.7 million, or 33%, to $182.0 million for the first quarter of 2023 compared to $137.3 million for the first quarter of 2022 due to an increase in the number of producing wells from drilling activities and property acquisitions, cost inflation for services and materials, costs associated with adverse winter weather conditions in the Bakken and Powder River Basin, and higher workover-related activities aimed at enhancing production from producing properties. Production expenses on a per-Boe basis averaged $5.00 per Boe for the 2023 first quarter compared to $4.09 per Boe for the 2022 first quarter, the increase of which primarily reflects higher workover-related activities, cost inflation, and an increase in oil-weighted production from 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.

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Production and Ad Valorem Taxes. Production and ad valorem taxes decreased $22.2 million, or 14%, to $136.2 million for the first quarter of 2023 compared to $158.4 million for the first quarter of 2022 due to the previously described decrease in crude oil and natural gas revenues. Our production taxes as a percentage of net sales averaged 7.9% for the first quarter of 2023, an increase compared to 7.2% for the first quarter of 2022. This increase was the result of changes in sales mix of crude oil and natural gas in the Company’s operating areas between periods.

Depreciation, Depletion, Amortization and Accretion. Total DD&A increased $17.5 million, or 4%, to $476.5 million for the first quarter of 2023 compared to $459.0 million for the first quarter of 2022 primarily due to the previously described 8% increase in total sales volumes largely offset by a decrease in our DD&A rate per Boe as further discussed below. The following table shows the components of our DD&A on a unit of sales basis for the periods presented.

 

		Three months ended March 31,
$/Boe		2023				2022
Crude oil and natural gas		$	12.57			$	13.37
Other equipment			0.43				0.21
Asset retirement obligation accretion			0.10				0.09
Depreciation, depletion, amortization and accretion		$	13.10			$	13.67

 

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

Our proved reserves have been revised upward over the past year prompted by significant increases in first-day-of-the-month commodity prices and other factors, which, when coupled with improvements in capital efficiency and strong well productivity, resulted in a decrease in our DD&A rate for crude oil and natural gas properties in the first quarter of 2023 compared to the first quarter of 2022 and helped offset the additional DD&A recognized in 2023 from increased sales volumes.

Property Impairments. Total property impairments decreased $11.1 million to $13.1 million for the first quarter of 2023 compared to $24.2 million for the first quarter of 2022. The decrease is primarily due to $11.8 million of proved property impairments recognized in the first quarter of 2022 with no proved property impairments recognized in the first quarter of 2023.

General and Administrative Expenses. Total G&A expenses decreased $11.5 million, or 15%, to $63.3 million for the first quarter of 2023 compared to $74.8 million for the first quarter of 2022.

Total G&A expenses include charges for incentive compensation/prior equity awards of $1.0 million and $29.3 million for the first quarters of 2023 and 2022, respectively. This decrease reflects the reversal of previously recognized expense associated with (i) incentive compensation awards that are no longer expected to vest and (ii) a decrease in estimated incentive compensation payment obligations arising from changes in the value of the Company, which resulted in an aggregate decrease in expense of $23.6 million ($0.65 per Boe) in the 2023 first quarter.

G&A expenses other than incentive compensation/prior equity awards totaled $62.3 million for the 2023 first quarter, an increase of $16.7 million compared to $45.5 million for the 2022 first quarter primarily due to the growth of our operations and increases in payroll costs and employee benefits, partially offset by higher overhead recoveries from joint interest owners driven by increased drilling, completion, and production activities compared to the 2022 first quarter.

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

 

		Three months ended March 31,
$/Boe		2023				2022
General and administrative expenses		$	1.71			$	1.36
Incentive compensation/prior equity awards			0.03				0.87
Total general and administrative expenses		$	1.74			$	2.23

 

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Interest Expense. Interest expense increased $27.1 million, or 37%, to $99.7 million for the first quarter of 2023 compared to $72.6 million for the first quarter of 2022 due to an increase in our weighted average outstanding debt balance from $6.8 billion for the first quarter of 2022 to $8.2 billion for the first quarter of 2023. This increase was driven by debt incurred in the fourth quarter of 2022 to fund a portion of the Hamm Family's November 2022 take-private transaction.

Income Taxes. For the first quarters of 2023 and 2022 we provided for income taxes at a combined federal and state tax rate of 23.5% and 24.5%, respectively, of our pre-tax income. We recorded an income tax provision of $239.8 million for the 2023 first quarter and an income tax provision of $191.1 million for the 2022 first quarter, which resulted in effective tax rates of 21.3% and 24.1%, respectively, after taking into account the application of statutory tax rates, permanent taxable differences, estimated tax credits, tax effects from equity/incentive compensation, and other items.

Liquidity and Capital Resources

Our primary sources of liquidity have historically been cash flows generated from operating activities, financing provided by our credit facility and the issuance of debt securities. Additionally, asset dispositions and joint development arrangements have provided a source of cash flow for use in reducing debt and enhancing liquidity.

As of March 31, 2023, we had $961 million of outstanding borrowings and $1.29 billion of borrowing availability under our credit facility. At April 30, 2023, we had $1.76 billion of outstanding borrowings and $493 million of borrowing availability under our credit facility. The increase in outstanding credit facility borrowings relative to March 31, 2023 resulted from borrowings incurred to fund the repayment of our 2023 Notes and cash tax payments in April 2023 as described in Note 11. Subsequent Events. Our credit facility, which is unsecured and has no borrowing base subject to redetermination, does not mature until October 2026. We remain committed to reducing debt and plan to continue prioritizing the repayment of credit facility borrowings over the next 12 months using available cash flows and expect our credit facility borrowing availability and liquidity to improve from current levels based on current market conditions. As discussed in Note 6. Derivative Instruments, we have hedged a significant portion of our forecasted future production to reduce exposure to adverse price volatility and help secure cash flows to support our capital program, debt reduction plans, and general corporate needs.

Based on our planned capital spending, our forecasted cash flows and projected levels of indebtedness, we expect to maintain compliance with the covenants under our credit facility, term loan, and senior note indentures. Further, based on current market indications, we expect to meet our contractual cash commitments to third parties as of March 31, 2023, including those subsequently described under the heading Future Capital Requirements, recognizing we may be required to meet such commitments even if our business plan assumptions were to change. We monitor our capital spending closely based on actual and projected cash flows and have the ability to reduce spending or dispose of assets if needed to preserve liquidity and financial flexibility to fund our operations.

Cash Flows

Cash flows from operating activities

Net cash provided by operating activities decreased $354.8 million, or 24%, to $1.15 billion for the first quarter of 2023 compared to $1.50 billion for the first quarter of 2022. The decrease was driven by a $482.5 million decrease in crude oil, natural gas, and NGL revenues due to the previously described decrease in commodity prices and increases in certain other cash operating expenses associated with increased sales volumes and the growth of our Company over the past year. Increased cash operating expenses included a $44.7 million increase in production expenses, a $3.0 million increase in transportation, gathering, processing, and compression expenses, a $28.1 million increase in cash paid for interest, and $129.4 million of cash payments for vested incentive compensation awards. These increases were partially offset by a $73.9 million increase in realized cash gains on matured commodity derivatives and a $22.2 million decrease in production and ad valorem taxes associated with lower revenues.

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Cash flows from investing activities

Net cash used in investing activities totaled $1.02 billion for the first quarter of 2023, consistent with $1.04 billion for the first quarter of 2022. Our investing cash flows for first quarter 2023 included $864.0 million of exploration and development costs compared to $523.7 million of exploration and development costs for first quarter 2022, reflecting a planned increase in budgeted spending. This increase in spending was partially offset by lower acquisitions of producing crude oil and natural gas properties, with $97.6 million acquired in first quarter of 2023 compared to $441.9 million acquired in first quarter of 2022.

Cash flows from financing activities

Net cash used in financing activities for the first quarter of 2023 totaled $211 million, primarily consisting of $199 million of net repayments on our credit facility and $11 million of cash distributed to noncontrolling interests.

Net cash used in financing activities for the first quarter of 2022 totaled $480 million, primarily consisting of $265 million of net repayments on our credit facility, $83 million of cash dividends paid on common stock, and $100 million of cash used to repurchase shares of our common stock.

Future Sources of Financing

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

Based on current market indications supported by cash flow protection provided by our hedge portfolio against commodity price declines, our budgeted capital spending plans for 2023 are expected to be funded from operating cash flows. Any deficiencies in operating cash flows relative to budgeted spending are expected to be funded by borrowings under our credit facility. If cash flows are materially impacted by declines in commodity prices, we have the ability to reduce our capital expenditures or utilize the availability of our credit facility if needed to fund our operations.

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

Credit facility

We have an unsecured credit facility, maturing in October 2026, with aggregate lender commitments totaling $2.255 billion. The commitments are from a syndicate of 13 banks and financial institutions. We believe each member of the current syndicate has the capability to fund its commitment.

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

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

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We were in compliance with our credit facility covenants at March 31, 2023 and expect to maintain such compliance. At March 31, 2023, our consolidated net debt to total capitalization ratio was 0.47. We do not believe the credit facility covenants are reasonably likely to limit our ability to undertake additional debt financing if needed to support our business.

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 March 31, 2023, 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 $5.7 billion at April 30, 2023, exclusive of interest payment obligations thereon. Our senior notes are not subject to any mandatory redemption or sinking fund requirements. The earliest scheduled senior note maturity is our $893 million of 2024 Notes due in June 2024. We expect to be able to generate or obtain sufficient funds necessary to fully redeem our 2024 Notes by the maturity date. For further information on the face values, maturity dates, semi-annual interest payment dates, optional redemption periods and covenant restrictions related to our senior notes, refer to Note 8. Debt in Notes to Unaudited Condensed Consolidated Financial Statements.

We were in compliance with our senior note covenants at March 31, 2023 and expect to maintain such compliance. We do not believe the senior note covenants will materially limit our ability to undertake additional debt financing. Downgrades or other negative rating actions with respect to the credit ratings assigned to our senior unsecured debt do not trigger additional senior note covenants.

Credit facility borrowings

As of April 30, 2023, we had $1.76 billion of outstanding borrowings on our credit facility. Our credit facility matures in October 2026.

Term loan

We have a $750 million term loan that matures in November 2025. The covenant requirements in the term loan are consistent with the covenants in our revolving credit facility, including the requirement that we maintain a consolidated net debt to total capitalization ratio of no greater than 0.65 to 1.0. We were in compliance with the term loan covenants at March 31, 2023 and expect to maintain compliance. Downgrades or other negative rating actions with respect to the credit ratings assigned to our senior unsecured debt do not trigger a security requirement or change in covenants for the term loan. Downgrades of our credit rating will, however, trigger an increase in our term loan's interest rate.

Transportation, gathering, and processing commitments

We have entered into transportation, gathering, and processing commitments to guarantee capacity on crude oil and natural gas pipelines and natural gas processing facilities that require us to pay per-unit charges regardless of the amount of capacity used. Future commitments remaining as of March 31, 2023 under the arrangements amount to approximately $1.06 billion. See Note 9. Commitments and Contingencies in Notes to Unaudited Condensed Consolidated Financial Statements for additional information.

Capital expenditures

Our capital expenditures budget for 2023 is expected to be $3.25 billion. Costs of acquisitions and investments are not budgeted, with the exception of planned levels of spending for mineral acquisitions.

For the three months ended March 31, 2023, we invested $898.7 million in our capital program excluding $240.7 million of unbudgeted acquisitions and $2.3 million of mineral acquisitions attributable to Franco-Nevada, and including $114.8 million of capital costs associated with increased accruals for capital expenditures as compared to December 31, 2022. Our 2023 first quarter capital expenditures were allocated as shown in the table below.

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In millions		1Q 2023
Exploration and development drilling		$	740.6
Land costs			42.5
Mineral acquisitions attributable to Continental			0.6
Capital facilities, workovers, water infrastructure, and other corporate assets			115.0
Capital expenditures attributable to Continental, excluding unbudgeted acquisitions			898.7
Unbudgeted acquisitions			240.7
Total capital expenditures attributable to Continental		$	1,139.4
Mineral acquisitions attributable to Franco-Nevada			2.3
Total capital expenditures		$	1,141.7

 

Our drilling and completion activities and the actual amount and timing of our capital expenditures may differ materially from our budget as a result of, among other things, available cash flows, unbudgeted acquisitions, actual drilling and completion results, operational process improvements, the availability of drilling and completion rigs and other services and equipment, cost inflation, the availability of transportation, gathering and processing capacity, changes in commodity prices, and regulatory, technological and competitive developments. We monitor our capital spending closely based on actual and projected cash flows and may adjust our spending should commodity prices materially change from current levels. We expect to continue participating as a buyer of properties when and if we have the ability to increase our position in strategic plays at attractive terms.

Cash payments for income taxes

On April 14, 2023, we made cash payments for federal and state income taxes totaling $230 million, representing payments associated with 2022 tax return filing extensions and estimated quarterly payments for 2023 federal and state income taxes based on estimates of taxable income for 2023. 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. If commodity prices remain at current levels, we expect to continue generating significant taxable income through at least year-end 2023, which would result in us continuing to make estimated tax payments on a quarterly basis in 2023. 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.

Long-term incentive compensation awards

As discussed in Note 10. Incentive Compensation in Notes to Unaudited Condensed Consolidated Financial Statements, at March 31, 2023 we have recognized a current liability of $81.0 million and a non-current liability of $16.4 million in the consolidated balance sheets associated with unvested incentive compensation awards granted to employees that are scheduled to vest in 2024, 2025, and 2026. We intend to settle these awards in cash at the time vesting occurs. Our recognized liabilities will be remeasured each reporting period leading up to the applicable award vesting dates to reflect additional services rendered by employees and to reflect changes in expected cash payments arising from underlying changes in the value of the Company based on independent third party appraisals.

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 $893 million of 2024 Notes is due in June 2024. We expect to be able to generate or obtain sufficient funds necessary to fully redeem our 2024 Notes by the maturity date.

Derivative Instruments

The fair value of our derivative instruments at March 31, 2023 was a net asset of $152.4 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 March 31, 2023. The estimated fair value of our derivatives is highly sensitive to

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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 March 31, 2023.

Critical Accounting Policies and Estimates

There have been no changes in our critical accounting policies and estimates from those disclosed in our 2022 Form 10-K.

Non-GAAP Financial Measures

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

Revenues and transportation expenses associated with production from our operated properties are reported separately. For non-operated properties, we receive a net payment from the operator for our share of sales proceeds which is net of costs incurred by the operator, if any. Such non-operated revenues are recognized at the net amount of proceeds received. As a result, the separate presentation of revenues and transportation expenses from our operated properties differs from the net presentation from non-operated properties. This impacts the comparability of certain operating metrics, such as per-unit sales prices, when such metrics are prepared in accordance with U.S. GAAP using gross presentation for some revenues and net presentation for others.

In order to provide metrics prepared in a manner consistent with how management assesses the Company's operating results and to achieve comparability between operated and non-operated revenues, we have presented crude oil, natural gas, and natural gas liquids sales net of transportation expenses in Management’s Discussion and Analysis of Financial Condition and Results of Operations, which we refer to as "net crude oil, natural gas, and natural gas liquids sales," a non-GAAP measure. Average sales prices calculated using net sales are referred to as "net sales prices," a non-GAAP measure, and are calculated by taking revenues less transportation expenses divided by sales volumes. Management believes presenting our revenues and sales prices net of transportation expenses is useful because it normalizes the presentation differences between operated and non-operated revenues and allows for a useful comparison of net realized prices to NYMEX benchmark prices on a Company-wide basis.

The following tables present a reconciliation of crude oil, natural gas, and natural gas liquids sales (GAAP) to net crude oil, natural gas, and natural gas liquids sales and related net sales prices (non-GAAP) for the three months ended March 31, 2023 and 2022.

 

		Three months ended March 31, 2023												Three months ended March 31, 2022
In thousands		Crude oil				Natural gas and NGLs				Total				Crude oil				Natural gas and NGLs				Total
Crude oil, natural gas, and NGL sales (GAAP)		$	1,385,436			$	406,284			$	1,791,720			$	1,643,847			$	630,414			$	2,274,261
Less: Transportation expenses			(62,976	)			(14,893	)			(77,869	)			(57,887	)			(16,962	)			(74,849	)
Net crude oil, natural gas, and NGL sales (non-GAAP)		$	1,322,460			$	391,391			$	1,713,851			$	1,585,960			$	613,452			$	2,199,412
Sales volumes (MBbl/MMcf/MBoe)			18,286				108,519				36,372				17,461				96,683				33,575
Net sales price (non-GAAP)		$	72.32			$	3.61			$	47.12			$	90.83			$	6.34			$	65.51

 

 

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ITEM 3. Quantitative and Qualitative Disclosures About Market Risk

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

Commodity Price Risk. Our primary market risk exposure is in the prices we receive from sales of crude oil, natural gas, and natural gas liquids. Realized pricing is primarily driven by the prevailing worldwide price for crude oil and spot market prices applicable to our natural gas and natural gas liquids production. Commodity prices have been volatile and unpredictable for several years, and we expect this volatility to continue in the future. The prices we receive for production depend on many factors outside of our control, including differences between product prices at sales points and the applicable index prices. Based on our average daily production for three months ended March 31, 2023, and excluding the effect of derivative instruments in place, our annual revenue would increase or decrease by approximately $753 million for each $10.00 per barrel change in crude oil prices at March 31, 2023 and $440 million for each $1.00 per Mcf change in natural gas prices at March 31, 2023.

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

The fair value of our derivative instruments at March 31, 2023 was a net asset of $152.4 million, which is comprised of a $60.0 million net asset associated with our natural gas derivatives and a $92.4 million net asset associated with our crude oil derivatives. The following table shows how a hypothetical +/- 10% change in the underlying forward prices used to calculate the fair value of our derivatives would impact the fair value estimates as of March 31, 2023.

 

				Hypothetical Fair Value
In thousands		Change in Forward Price		Asset (Liability)
Crude Oil		-10%		$	245,519
Crude Oil		+10%		$	(61,456	)
Natural Gas		-10%		$	274,856
Natural Gas		+10%		$	(210,306	)

 

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

Credit Risk. We monitor our risk of loss due to non-performance by counterparties of their contractual obligations. Our principal exposure to credit risk is through the sale of our production, which we market to energy marketing companies, crude oil refining companies, and natural gas gathering and processing companies ($1.1 billion in receivables at March 31, 2023), and our joint interest and other receivables ($460 million at March 31, 2023).

 

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

Joint interest receivables arise from billing the individuals and entities who own a partial interest in the wells we operate. These individuals and entities participate in our wells primarily based on their ownership in leases included in units on which we wish to drill. We can do very little to choose who participates in our wells. In order to minimize our exposure to this credit risk we generally request prepayment of drilling costs where it is allowed by contract or state law. For such prepayments, a liability is recorded and subsequently reduced as the associated work is performed. This liability was $25 million at March 31, 2023, which will be used to

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offset future capital costs when billed. In this manner, we reduce credit risk. We may have the right to place a lien on a co-owner's interest in the well, to net production proceeds against amounts owed in order to secure payment or, if necessary, foreclose on the interest. Historically, our credit losses on joint interest receivables have been immaterial.

Interest Rate Risk. Our exposure to changes in interest rates relates primarily to variable-rate borrowings we have outstanding from time to time under our credit facility and $750 million term loan. 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 $1.76 billion of variable rate borrowings outstanding on our credit facility and $750 million of variable rate borrowings on our term loan at April 30, 2023. The impact of a 0.25% increase in interest rates on this amount of debt would result in increased interest expense and reduced income before income taxes of approximately $6.3 million per year.

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

ITEM 4. Controls and Procedures

Evaluation of Disclosure Controls and Procedures

As of the end of the period covered by this report, an evaluation of the effectiveness of the design and operation of the Company’s disclosure controls and procedures (as defined in Rule 13a-15(e) under the Securities Exchange Act of 1934, as amended (the “Exchange Act”)) was performed under the supervision and with the participation of the Company’s management, including its Chief Executive Officer and Chief Financial Officer. Based on that evaluation, our Chief Executive Officer and Chief Financial Officer concluded the Company’s disclosure controls and procedures were effective as of March 31, 2023 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 March 31, 2023, 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.

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PART II. Other Information

ITEM 1. Legal Proceedings

We are involved in various 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, we do not expect them to have a material adverse effect on our financial condition, results of operations or cash flows.

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 2022 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 2022 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 material changes in our risk factors from those disclosed in our 2022 Form 10-K.

 

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

Not applicable.

 

ITEM 3. Defaults Upon Senior Securities

Not applicable.

 

ITEM 4. Mine Safety Disclosures

Not applicable.

 

ITEM 5. Other Information

Not applicable.

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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 Fifth Amended and Restated Certificate of Incorporation of Continental Resources, Inc. filed as Exhibit 3.1 to the Company's Form 10-K for the year ended December 31, 2022 (Commission File No. 001-32886) filed February 22, 2023 and incorporated herein by reference.
3.2		Fifth Amended and Restated Bylaws of Continental Resources, Inc. filed as Exhibit 3.2 to the Company’s Form 10-K for the year ended December 31, 2022 (Commission File No. 001-32886) filed February 22, 2023 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).
101.INS*		Inline XBRL Instance Document - the Inline XBRL Instance Document does not appear in the Interactive Data file because its XBRL tags are embedded within the Inline XBRL document
101.SCH*		Inline XBRL Taxonomy Extension Schema Document
101.CAL*		Inline XBRL Taxonomy Extension Calculation Linkbase Document
101.DEF*		Inline XBRL Taxonomy Extension Definition Linkbase Document
101.LAB*		Inline XBRL Taxonomy Extension Label Linkbase Document
101.PRE*		Inline XBRL Taxonomy Extension Presentation Linkbase Document
104		Cover Page Interactive Data File (formatted as Inline XBRL and contained in Exhibit 101)

* Filed herewith

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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:	May 8, 2023	By:		/s/ John D. Hart
				John D. Hart
				Chief Financial Officer and Executive Vice President of Strategic Planning (Duly Authorized Officer and Principal Financial Officer)

 

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