UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

 

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

For the quarterly period ended March 31, 2024

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: 1-34776

Chord Energy Corporation

(Exact name of registrant as specified in its charter)

 

Delaware	80-0554627
(State or other jurisdiction of incorporation or organization)	(I.R.S. Employer Identification No.)
1001 Fannin Street, Suite 1500
Houston, Texas	77002
(Address of principal executive offices)	(Zip Code)

(281) 404-9500

(Registrant’s telephone number, including area code)

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	CHRD	The Nasdaq Stock Market LLC

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 ☐

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 ☒  No ☐

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

Large accelerated filer	☒	Accelerated filer	☐
Non-accelerated filer	☐	Smaller reporting company	☐
		Emerging growth company	☐

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

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

Indicate by check mark whether the registrant has filed all documents and reports required to be filed by Section 12, 13 or 15(d) of the Securities Exchange Act of 1934 subsequent to the distribution of securities under a plan confirmed by a court. Yes  ý   No  ¨

Number of shares of the registrant’s common stock outstanding at May 2, 2024: 41,693,424 shares.

TABLE OF CONTENTS

	Page
Glossary of Terms	1
PART I — FINANCIAL INFORMATION	3
Item 1. — Financial Statements (Unaudited)	4
Condensed Consolidated Balance Sheets at March 31, 2024 and December 31, 2023	4
Condensed Consolidated Statements of Operations for the Three Months Ended March 31, 2024 and 2023	6
Condensed Consolidated Statements of Changes in Stockholders’ Equity for the Three Months Ended March 31, 2024 and 2023	7
Condensed Consolidated Statements of Cash Flows for the Three Months Ended March 31, 2024 and 2023	8
Notes to Condensed Consolidated Financial Statements	9
1. Organization and Summary of Significant Accounting Policies	9
2. Revenue Recognition	10
3. Inventory	11
4. Additional Balance Sheet Information	11
5. Fair Value Measurements	11
6. Derivative Instruments	14
7. Property, Plant and Equipment	17
8. Acquisitions	17
9. Divestitures and Assets Held for Sale	18
10. Investment in Unconsolidated Affiliate	18
11. Long-Term Debt	19
12. Asset Retirement Obligations	19
13. Income Taxes	20
14. Equity-Based Compensation	20
15. Stockholders’ Equity	21
16. Earnings Per Share	22
17. Commitments and Contingencies	22
18. Leases	23
Item 2. — Management’s Discussion and Analysis of Financial Condition and Results of Operations	24
Overview and Recent Developments	27
Results of Operations	27
Liquidity and Capital Resources	33
Fair Value of Financial Instruments	36
Critical Accounting Policies and Estimates	36
Item 3. — Quantitative and Qualitative Disclosures About Market Risk	37
Item 4. — Controls and Procedures	38
PART II — OTHER INFORMATION	39
Item 1. — Legal Proceedings	39
Item 1A. — Risk Factors	39
Item 2. — Unregistered Sales of Equity Securities and Use of Proceeds	40
Item 5.— Other Information	40
Item 6. — Exhibits	40
SIGNATURES	42

GLOSSARY OF TERMS

The terms defined in this section are used throughout this Quarterly Report on Form 10-Q:

“Basin.” A large natural depression on the earth’s surface in which sediments generally brought by water accumulate.

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

“Boe.” Barrels of oil equivalent, with 6,000 cubic feet of natural gas being equivalent to one barrel of crude oil.

“Boepd.” Barrels of oil equivalent per day.

“British thermal unit.” The heat required to raise the temperature of a one-pound mass of water from 58.5 to 59.5 degrees Fahrenheit.

“Completion.” The process of treating a drilled well followed by the installation of permanent equipment for the production of natural gas or oil, or in the case of a dry hole, the reporting of abandonment to the appropriate agency.

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

“Economically producible.” A resource that generates revenue that exceeds, or is reasonably expected to exceed, the costs of the operation.

“ESG.” Environmental, social and governance.

“Exploratory well.” A well drilled to find a new field or to find a new reservoir in a field previously found to be productive of oil or natural gas in another reservoir.

“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 differ from nearby rock.

“GAAP.” Generally accepted accounting principles in the United States.

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

“MBoe.” One thousand barrels of oil equivalent.

“Mcf.” One thousand cubic feet of natural gas.

“MMBtu.” One million British thermal units.

“MMcf.” One million cubic feet of natural gas.

“Net acres.” The percentage of total acres an owner has out of a particular number of acres, or a specified tract. An owner who has 50% interest in 100 acres owns 50 net acres.

“NGL.” Natural gas liquids.

“NYMEX.” The New York Mercantile Exchange.

“OPEC+.” The Organization of Petroleum Exporting Countries and other oil exporting nations.

“Plug.” A down-hole packer assembly used in a well to seal off or isolate a particular formation for testing, acidizing, cementing, etc.; also a type of plug used to seal off a well temporarily while the wellhead is removed.

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

1

“Proved reserves.” Those quantities of oil and 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 that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. The project to extract the hydrocarbons must have commenced or the operator must be reasonably certain that it will commence the project within a reasonable time. The area of the reservoir considered as proved includes (i) the area identified by drilling and limited by fluid contacts, if any, and (ii) adjacent undrilled portions of the reservoir that can, with reasonable certainty, be judged to be continuous with it and to contain economically producible crude oil or gas on the basis of available geoscience and engineering data. In the absence of data on fluid contacts, proved quantities in a reservoir are limited by the lowest known hydrocarbons, as seen in a well penetration unless geoscience, engineering, or performance data and reliable technology establishes a lower contact with reasonable certainty. Where direct observation from well penetrations has defined a highest known oil, elevation and the potential exists for an associated gas cap, proved oil reserves may be assigned in the structurally higher portions of the reservoir only if geoscience, engineering, or performance data and reliable technology establish the higher contact with reasonable certainty. Reserves which can be produced economically through application of improved recovery techniques (including, but not limited to, fluid injection) are included in the proved classification when (i) successful testing by a pilot project in an area of the reservoir with properties no more favorable than in the reservoir as a whole, the operation of an installed program in the reservoir or an analogous reservoir, or other evidence using reliable technology establishes the reasonable certainty of the engineering analysis on which the project or program was based; and (ii) the project has been approved for development by all necessary parties and entities, including governmental entities. Existing economic conditions include prices and costs at which economic producibility from a reservoir is to be determined. The price shall be the average price during the 12-month period prior to the ending date of the period covered by the report, determined as an unweighted arithmetic average of the first-day-of-the-month price for each month within such period, unless prices are defined by contractual arrangements, excluding escalations based upon future conditions.

“Reasonable certainty.” If deterministic methods are used, reasonable certainty means a high degree of confidence that the quantities will be recovered. If probabilistic methods are used, there should be at least a 90 percent probability that the quantities actually recovered will equal or exceed the estimate. A high degree of confidence exists if the quantity is much more likely to be achieved than not, and, as changes due to increased availability of geoscience (geological, geophysical and geochemical) engineering, and economic data are made to estimated ultimate recovery with time, reasonably certain estimated ultimate recovery is much more likely to increase or remain constant than to decrease.

“Reserves.” Estimated remaining quantities of crude oil and natural gas and related substances anticipated to be economically producible as of a given date by application of development prospects to known accumulations.

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

“SEC.” The U.S. Securities and Exchange Commission.

“Turn-in-line” or “TIL.” To turn a drilled and completed well online to begin sales.

“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.

“Wellbore.” The hole drilled by the bit that is equipped for crude oil or gas production on a completed well. Also called well or borehole.

“Workover.” The repair or stimulation of an existing productive well for the purpose of restoring, prolonging or enhancing the production of hydrocarbons.

2

PART I — FINANCIAL INFORMATION

Item 1. — Financial Statements (Unaudited)

Chord Energy Corporation

Condensed Consolidated Balance Sheets (Unaudited)

	March 31, 2024		December 31, 2023
	(In thousands, except share data)
ASSETS
Current assets
Cash and cash equivalents	$	296,354	$	317,998
Accounts receivable, net	982,062		943,114
Inventory	78,118		72,565
Prepaid expenses	30,135		42,450
Derivative instruments	26,540		37,369
Other current assets	2,033		11,055
Total current assets	1,415,242		1,424,551
Property, plant and equipment
Oil and gas properties (successful efforts method)	6,575,306		6,320,243
Other property and equipment	49,087		49,051
Less: accumulated depreciation, depletion and amortization	(1,218,284)		(1,054,616)
Total property, plant and equipment, net	5,406,109		5,314,678
Derivative instruments	22,231		22,526
Investment in unconsolidated affiliate	114,181		100,172
Long-term inventory	28,360		22,936
Operating right-of-use assets	19,218		21,343
Other assets	20,173		19,944
Total assets	$	7,025,514	$	6,926,150
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities
Accounts payable	$	39,511	$	34,453
Revenues and production taxes payable	592,888		604,704
Accrued liabilities	545,820		493,381
Accrued interest payable	8,532		2,157
Derivative instruments	19,523		14,209
Advances from joint interest partners	2,484		2,381
Current operating lease liabilities	13,691		13,258
Other current liabilities	22,671		916
Total current liabilities	1,245,120		1,165,459
Long-term debt	396,324		395,902
Deferred tax liabilities	122,288		95,322
Asset retirement obligations	155,696		155,040
Derivative instruments	3,022		717
Operating lease liabilities	15,993		18,667
Other liabilities	11,893		18,419
Total liabilities	1,950,336		1,849,526
Commitments and contingencies (Note 17)

3

	March 31, 2024		December 31, 2023
	(In thousands, except share data)
Stockholders’ equity
Common stock, $0.01 par value: 120,000,000 shares authorized, 45,527,230 shares issued and 41,551,082 shares outstanding at March 31, 2024; and 120,000,000 shares authorized, 45,032,537 shares issued and 41,249,658 shares outstanding at December 31, 2023	459		456
Treasury stock, at cost: 3,976,148 shares at March 31, 2024 and 3,782,879 shares at December 31, 2023	(523,288)		(493,289)
Additional paid-in capital	3,575,557		3,608,819
Retained earnings	2,022,450		1,960,638
Total stockholders’ equity	5,075,178		5,076,624
Total liabilities and stockholders’ equity	$	7,025,514	$	6,926,150

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

5

Chord Energy Corporation

Condensed Consolidated Statements of Operations (Unaudited)

	Three Months Ended March 31,
	2024		2023
	(In thousands, except per share data)
Revenues
Oil, NGL and gas revenues	$	748,162	$	766,200
Purchased oil and gas sales	337,098		130,317
Total revenues	1,085,260		896,517
Operating expenses
Lease operating expenses	159,206		153,408
Gathering, processing and transportation expenses	53,984		37,015
Purchased oil and gas expenses	335,762		129,593
Production taxes	63,911		60,517
Depreciation, depletion and amortization	168,894		133,791
General and administrative expenses	25,712		32,484
Exploration and impairment	6,154		24,864
Total operating expenses	813,623		571,672
Gain on sale of assets, net	1,302		1,227
Operating income	272,939		326,072
Other income (expense)
Net gain (loss) on derivative instruments	(27,577)		66,934
Net gain (loss) from investment in unconsolidated affiliate	16,296		(2,216)
Interest expense, net of capitalized interest	(7,592)		(7,135)
Other income	2,826		5,193
Total other income (expense), net	(16,047)		62,776
Income before income taxes	256,892		388,848
Income tax expense	(57,539)		(91,849)
Net income	$	199,353	$	296,999
Earnings per share:
Basic (Note 16)	$	4.79	$	7.13
Diluted (Note 16)	$	4.65	$	6.87
Weighted average shares outstanding:
Basic (Note 16)	41,468		41,568
Diluted (Note 16)	42,747		43,149

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

6

Chord Energy Corporation

Condensed Consolidated Statements of Changes in Stockholders’ Equity (Unaudited)

	Common Stock			Treasury Stock			Additional Paid-in Capital		Retained Earnings		Total Stockholders’ Equity
	Shares	Amount		Shares	Amount
	(In thousands)
Balance as of December 31, 2023	41,250	$	456	3,783	$	(493,289)	$	3,608,819	$	1,960,638	$	5,076,624
Equity-based compensation and vestings	599	4		—	—		4,771		—		4,775
Tax withholdings on settlement of equity-based awards	(280)	(3)		—	—		(46,048)		—		(46,051)
Dividends	—	—		—	—		—		(137,541)		(137,541)
Share repurchases	(193)	—		193	(29,999)		—		—		(29,999)
Warrants exercised	175	2		—	—		8,015		—		8,017
Net income	—	—		—	—		—		199,353		199,353
Balance as of March 31, 2024	41,551	$	459	3,976	$	(523,288)	$	3,575,557	$	2,022,450	$	5,075,178

	Common Stock			Treasury Stock			Additional Paid-in Capital		Retained Earnings		Total Stockholders’ Equity
	Shares	Amount		Shares	Amount
	(In thousands)
Balance as of December 31, 2022	41,477	$	438	2,249	$	(251,950)	$	3,485,819	$	1,445,491	$	4,679,798
Equity-based compensation and vestings	210	2		—	—		11,852		—		11,854
Tax withholdings on settlement of equity-based awards	(77)	(1)		—	—		(10,299)		—		(10,300)
Dividends	—	—		—	—		—		(204,884)		(204,884)
Share repurchases	(111)	—		111	(15,003)		—		—		(15,003)
Warrants exercised	39	—		—	—		276		—		276
Net income	—	—		—	—		—		296,999		296,999
Balance as of March 31, 2023	41,538	$	439	2,360	$	(266,953)	$	3,487,648	$	1,537,606	$	4,758,740

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

7

Chord Energy Corporation

Condensed Consolidated Statements of Cash Flows (Unaudited)

	Three Months Ended March 31,
	2024		2023
	(In thousands)
Cash flows from operating activities:
Net income	$	199,353	$	296,999
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, depletion and amortization	168,894		133,791
Gain on sale of assets	(1,302)		(1,227)
Impairment	3,919		23,304
Deferred income taxes	26,966		73,923
Net (gain) loss on derivative instruments	27,577		(66,934)
Net (gain) loss from investment in unconsolidated affiliate	(16,296)		2,216
Equity-based compensation expenses	4,771		11,854
Deferred financing costs amortization and other	2,663		(3,791)
Working capital and other changes:
Change in accounts receivable, net	(62,081)		(14,657)
Change in inventory	(9,471)		(12,753)
Change in prepaid expenses	(291)		1,211
Change in accounts payable, interest payable and accrued liabilities	29,147		8,176
Change in other assets and liabilities, net	32,849		16,699
Net cash provided by operating activities	406,698		468,811
Cash flows from investing activities:
Capital expenditures	(222,149)		(172,328)
Acquisitions, net of cash acquired	(334)		—
Proceeds from divestitures, net of cash divested	2,371		7,034
Derivative settlements	(12,062)		(91,656)
Proceeds from sale of investment in unconsolidated affiliate	—		12,347
Contingent consideration received	25,000		—
Distributions from investment in unconsolidated affiliate	2,287		3,015
Net cash used in investing activities	(204,887)		(241,588)
Cash flows from financing activities:
Repurchases of common stock	(31,999)		(15,003)
Tax withholding on vesting of equity-based awards	(46,051)		(10,300)
Dividends paid	(152,389)		(202,473)
Payments on finance lease liabilities	(386)		(388)
Proceeds from warrants exercised	7,370		90
Net cash used in financing activities	(223,455)		(228,074)
Decrease in cash and cash equivalents	(21,644)		(851)
Cash and cash equivalents:
Beginning of period	317,998		593,151
End of period	$	296,354	$	592,300
Supplemental non-cash transactions:
Change in accrued capital expenditures	$	25,312	$	46,097
Change in asset retirement obligations	973		234
Dividends payable	17,587		15,798

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

8

Chord Energy Corporation

Notes to Condensed Consolidated Financial Statements (Unaudited)

1. Organization and Summary of Significant Accounting Policies

Chord Energy Corporation (together with its consolidated subsidiaries, the “Company” or “Chord”) is an independent exploration and production company with quality and sustainable long-lived assets in the Williston Basin.

Basis of Presentation

The accompanying unaudited condensed consolidated financial statements of the Company have not been audited by the Company’s independent registered public accounting firm, except that the Condensed Consolidated Balance Sheet at December 31, 2023 is derived from audited financial statements. In the opinion of management, all adjustments, consisting of normal recurring adjustments necessary for the fair statement of the Company’s financial position, have been included. Management has made certain estimates and assumptions that affect reported amounts in the unaudited condensed consolidated financial statements and disclosures of contingencies. Actual results may differ from those estimates. The results for interim periods are not necessarily indicative of annual results.

These interim financial statements have been prepared pursuant to the rules and regulations of the SEC regarding interim financial reporting. Certain disclosures have been condensed or omitted from these financial statements. Accordingly, they do not include all of the information and notes required by GAAP for complete consolidated financial statements and should be read in conjunction with the Company’s audited consolidated financial statements and notes thereto included in the Company’s Annual Report on Form 10-K for the year ended December 31, 2023 (“2023 Annual Report”).

Pending Acquisition

On February 21, 2024, the Company entered into an arrangement agreement (the “Arrangement Agreement”) with Enerplus Corporation, a corporation existing under the laws of the Province of Alberta, Canada (“Enerplus”), and Spark Acquisition ULC, an unlimited liability company organized and existing under the laws of the Province of Alberta, Canada and a wholly-owned subsidiary of the Company, pursuant to which, among other things, the Company has agreed to acquire Enerplus in a stock-and-cash transaction (such transaction, the “Arrangement”), subject to satisfaction of certain closing conditions. The transaction will be effected by way of a plan of arrangement under the Business Corporations Act (Alberta) (the “Plan of Arrangement”).

Enerplus is an independent North American oil and gas exploration and production company. Under the terms of the Arrangement Agreement, Enerplus shareholders will receive 0.10125 shares of Chord common stock and $1.84 in cash in exchange for each common share of Enerplus they own at closing. The transaction is expected to close in the second quarter of 2024.

Risks and Uncertainties

As a producer of crude oil, NGLs and natural gas, the Company’s revenue, profitability and future growth are substantially dependent upon the prevailing and future prices for crude oil, NGLs and natural gas, which are dependent upon numerous factors beyond its control such as economic, geopolitical, political and regulatory developments and competition from other energy sources. The energy markets have historically been very volatile, and there can be no assurance that the prices for crude oil, NGLs or natural gas will not be subject to wide fluctuations in the future. A substantial or extended decline in prices for crude oil and, to a lesser extent, NGLs and natural gas, could have a material adverse effect on the Company’s financial position, results of operations, cash flows, the quantities of crude oil, NGL and natural gas reserves that may be economically produced and the Company’s access to capital.

9

Significant Accounting Policies

There have been no material changes to the Company’s significant accounting policies and estimates from those disclosed in the 2023 Annual Report.

Recent Accounting Pronouncements

In November 2023, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) No. 2023-07, “Segment Reporting (Topic 280): Improvements to Reportable Segment Disclosures” (“ASU 2023-07”). This standard clarifies that single reportable segment entities are subject to the disclosure requirements under Topic 280 in its entirety. This ASU is effective for fiscal years beginning after December 15, 2023 and interim periods within those fiscal years beginning after December 15, 2024. The Company is currently evaluating this ASU to determine its impact on the Company’s annual financial statement disclosures.

In December 2023, the FASB issued ASU 2023-09 “Income Taxes (Topic 740): Improvements to Income Tax Disclosures” to expand the disclosure requirements for income taxes, specifically relating to the effective tax rate reconciliation and additional disclosures on income taxes paid. The Company expects to adopt this ASU effective January 1, 2025, and the adoption is not expected to affect the Company’s financial position or results of operations, but will result in additional disclosures.

In March 2024, the SEC released its final rule on climate-related disclosures, requiring the disclosure of certain climate-related risks, management and governance practices, and financial impacts, as well as greenhouse gas emissions. Large accelerated filers will be required to incorporate the applicable climate-related disclosures into their filings for annual reporting periods beginning in fiscal year 2025, with additional requirements relating to greenhouse gas emissions effective for annual reporting periods beginning in fiscal year 2026. In April 2024, the SEC paused implementation of the final rule pending the resolution of consolidated legal challenges that are currently proceeding before the U.S. Court of Appeals for the Eighth Circuit. The Company is currently evaluating the impact of this rule on its financial statements and related disclosures.

2. Revenue Recognition

Revenues from contracts with customers were as follows for the periods presented:

	Three Months Ended March 31,
	2024		2023
	(In thousands)
Crude oil revenues	$	678,851	$	650,908
Purchased crude oil sales	326,647		109,265
NGL and natural gas revenues	69,311		115,292
Purchased NGL and natural gas sales	10,451		21,052
Total revenues	$	1,085,260	$	896,517

The Company records revenue when the performance obligations under the terms of its customer contracts are satisfied. For sales of commodities, the Company records revenue in the month the production or purchased product is delivered to the purchaser. However, settlement statements and payments are typically not received for 20 to 90 days after the date production is delivered, and as a result, the Company is required to estimate the amount of production that was delivered to the purchaser and the price that will be received for the sale of the product. The Company uses knowledge of its properties, its properties’ historical performance, spot market prices and other factors as the basis for these estimates. The Company records the differences between estimates and the actual amounts received for product sales once payment is received from the purchaser. In certain cases, the Company is required to estimate these volumes during a reporting period and record any differences between the estimated volumes and actual volumes in the following reporting period. Differences between estimated and actual revenues have historically not been significant. For the three months ended March 31, 2024 and 2023, revenue recognized related to performance obligations satisfied in prior reporting periods was not material.

10

3. Inventory

The following table sets forth the Company’s inventory balances for the periods presented:

	March 31, 2024		December 31, 2023
	(In thousands)
Inventory
Equipment and materials	$	34,535	$	30,201
Crude oil inventory	43,583		42,364
Total inventory	78,118		72,565
Long-term inventory
Linefill in third-party pipelines	28,360		22,936
Total long-term inventory	28,360		22,936
Total	$	106,478	$	95,501

4. Additional Balance Sheet Information

The following table sets forth certain balance sheet amounts comprised of the following:

	March 31, 2024		December 31, 2023
	(In thousands)
Accounts receivable, net
Trade and other accounts	$	795,285	$	749,356
Joint interest accounts	198,930		207,571
Total accounts receivable	994,215		956,927
Less: allowance for credit losses	(12,153)		(13,813)
Total accounts receivable, net	$	982,062	$	943,114
Revenues and production taxes payable
Royalties payable	$	287,704	$	297,531
Revenue suspense	262,372		266,704
Production taxes payable	42,812		40,469
Total revenue and production taxes payable	$	592,888	$	604,704
Accrued liabilities
Accrued oil and gas marketing	$	212,700	$	165,141
Accrued capital costs	147,572		122,260
Accrued lease operating expenses	109,446		107,606
Accrued general and administrative expenses	19,592		37,882
Current portion of asset retirement obligations	15,053		10,507
Accrued dividends	17,573		25,167
Other accrued liabilities	23,884		24,818
Total accrued liabilities	$	545,820	$	493,381

5. Fair Value Measurements

In accordance with the FASB’s authoritative guidance on fair value measurements, certain of the Company’s financial assets and liabilities are measured at fair value on a recurring basis. The Company’s financial instruments, including certain cash and cash equivalents, accounts receivable, accounts payable and other payables, are carried at cost, which approximates their respective fair market values due to their short-term maturities. The Company recognizes its non-financial assets and liabilities, such as asset retirement obligations (“ARO”) and properties acquired in a business combination or upon impairment, at fair value on a non-recurring basis.

11

Financial Assets and Liabilities

Financial assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. The Company’s assessment of the significance of a particular input requires judgment and may affect the valuation of fair value assets and liabilities and their placement within the fair value hierarchy levels.

The following tables set forth by level, within the fair value hierarchy, the Company’s financial assets and liabilities that were accounted for at fair value on a recurring basis:

	Fair value at March 31, 2024
	Level 1		Level 2		Level 3		Total
	(In thousands)
Assets:
Commodity derivative contracts (see Note 6)	$	—	$	44	$	2,647	$	2,691
Contingent consideration (see Note 6)	—		46,080		—		46,080
Investment in unconsolidated affiliate (see Note 10)	114,181		—		—		114,181
Total assets	$	114,181	$	46,124	$	2,647	$	162,952
Liabilities:
Commodity derivative contracts (see Note 6)	$	—	$	22,545	$	—	$	22,545
Total liabilities	$	—	$	22,545	$	—	$	22,545

	Fair value at December 31, 2023
	Level 1		Level 2		Level 3		Total
	(In thousands)
Assets:
Commodity derivative contracts (see Note 6)	$	—	$	11,312	$	5,877	$	17,189
Contingent consideration (see Note 6)	—		42,706		—		42,706
Investment in unconsolidated affiliate (see Note 10)	100,172		—		—		100,172
Total assets	$	100,172	$	54,018	$	5,877	$	160,067
Liabilities:
Commodity derivative contracts (see Note 6)	$	—	$	14,926	$	—	$	14,926
Total liabilities	$	—	$	14,926	$	—	$	14,926

Commodity derivative contracts. The Company enters into commodity derivative contracts to manage risks related to changes in crude oil, NGL and natural gas prices. The Company’s swaps, collars and basis swaps are valued by a third-party preparer based on an income approach. The significant inputs used are commodity prices, discount rate and the contract terms of the derivative instruments. These assumptions are observable in the marketplace throughout the full term of the contract, can be derived from observable data or are supported by observable levels at which transactions are executed in the marketplace and are therefore designated as Level 2 within the fair value hierarchy. The Company recorded a credit risk adjustment to reduce the fair value of its net derivative liability for these contracts by $0.3 million and $0.5 million at March 31, 2024 and December 31, 2023, respectively. See Note 6—Derivative Instruments for additional information.

Transportation derivative contracts. The Company has buy/sell transportation contracts that are derivative contracts for which the Company has not elected the “normal purchase normal sale” exclusion under FASB Accounting Standards Codification (“ASC”) 815, Derivatives and Hedging. These transportation derivative contracts are valued by a third-party preparer based on an income approach. The significant inputs used are quoted forward prices for commodities, market differentials for crude oil and either the Company’s or the counterparty’s nonperformance risk, as appropriate. The assumptions used in the valuation of these contracts include certain market differential metrics that are unobservable during the term of the contracts. Such unobservable inputs are significant to the contract valuation methodology, and the contracts’ fair values are therefore designated as Level 3 within the fair value hierarchy. See Note 6—Derivative Instruments for additional information.

12

Contingent consideration. In June 2021, the Company completed the divestiture of oil and gas properties in the Texas region of the Permian Basin. In connection with the divestiture, the Company is entitled to receive up to three earn-out payments of $25.0 million per year for each of 2023, 2024 and 2025 if the average daily settlement price of NYMEX West Texas Intermediate crude oil price index (“NYMEX WTI”) exceeds $60 per barrel for such year (the “Permian Basin Sale Contingent Consideration”). If NYMEX WTI for calendar year 2023 or 2024 is less than $45 per barrel, then each calendar year thereafter the buyer’s obligation to make any remaining earn-out payments is terminated. The fair value of the Permian Basin Sale Contingent Consideration is determined by a third-party preparer using a Monte Carlo simulation model and Ornstein-Uhlenbeck pricing process. The significant inputs used are NYMEX WTI forward price curve, volatility, mean reversion rate and counterparty credit risk adjustment. The Company determined these were Level 2 fair value inputs that are substantially observable in active markets or can be derived from observable data. During the three months ended March 31, 2024, the Company received $25.0 million related to the 2023 earn-out payment. See Note 6—Derivative Instruments for additional information.

Investment in unconsolidated affiliate. The Company owns common units in Energy Transfer LP (“Energy Transfer”) which are accounted for using the fair value option under FASB ASC 825-10, Financial Instruments. The fair value of the Company’s investment in Energy Transfer was determined using Level 1 inputs based upon the quoted market price of Energy Transfer’s publicly traded common units at March 31, 2024 and December 31, 2023. See Note 10—Investment in Unconsolidated Affiliate for additional information.

Non-Financial Assets and Liabilities

The fair value of the Company’s non-financial assets and liabilities measured on a non-recurring basis are determined using valuation techniques that include Level 3 inputs.

Asset retirement obligations. The initial measurement of ARO at fair value is recorded in the period in which the liability is incurred. Fair value is determined by calculating the present value of estimated future cash flows related to the liability. Estimating the future ARO requires management to make estimates and judgments regarding the timing and existence of a liability, as well as what constitutes adequate restoration when considering current regulatory requirements. Inherent in the fair value calculation are numerous assumptions and judgments, including the ultimate costs, inflation factors, credit-adjusted discount rates, timing of settlement and changes in the legal, environmental and regulatory environments.

Oil and gas and other properties. The Company records its properties at fair value when acquired in a business combination or upon impairment for proved oil and gas properties and other properties. Fair value is determined using a discounted cash flow model. The inputs used are subject to management’s judgment and expertise and include, but are not limited to, future production volumes based upon estimates of proved reserves, future commodity prices (adjusted for basis differentials), estimates of future operating and development costs and a risk-adjusted discount rate. These inputs are classified as Level 3 inputs, except the underlying commodity price assumptions are based on NYMEX forward strip prices (Level 1) and adjusted for price differentials.

2023 Williston Basin Acquisition. On June 30, 2023, the Company completed the 2023 Williston Basin Acquisition (defined in Note 8—Acquisitions). The assets acquired and liabilities assumed were recorded at fair value as of June 30, 2023. The fair value of the oil and gas properties acquired was calculated using an income approach based on the net discounted future cash flows from the oil and gas properties. The inputs utilized in the valuation of the oil and gas properties acquired included mostly unobservable inputs which fall within Level 3 of the fair value hierarchy. Such inputs included estimates of future oil and gas production from the properties’ reserve reports, commodity prices based on forward strip price curves (adjusted for basis differentials), operating and development costs, expected future development plans for the properties and the utilization of a discount rate based on a market-based weighted-average cost of capital. The Company also recorded the ARO assumed from the 2023 Williston Basin Acquisition at fair value. The inputs utilized in valuing the ARO were mostly Level 3 unobservable inputs, including estimated economic lives of oil and natural gas wells as of June 30, 2023, anticipated future plugging and abandonment costs and an appropriate credit-adjusted risk-free rate to discount such costs. See Note 8—Acquisitions for additional information.

13

6. Derivative Instruments

Commodity derivative contracts. The Company utilizes derivative financial instruments to manage risks related to changes in commodity prices. The Company’s crude oil contracts settle monthly based on the average NYMEX WTI crude index price and its natural gas contracts settle monthly based on the average NYMEX Henry Hub natural gas index price.

The Company utilizes derivative financial instruments including fixed-price swaps and two-way and three-way collars to manage risks related to changes in commodity prices. The Company’s fixed-price swaps are designed to establish a fixed price for the volumes under contract. Two-way collars are designed to establish a minimum price (floor) and a maximum price (ceiling) for the volumes under contract. Three-way collars are designed to establish a minimum price (floor), unless the market price falls below the sold put (sub-floor), at which point the minimum price would be the index price plus the difference between the purchased put and the sold put strike price. The sold call establishes a maximum price (ceiling) for the volumes under contract. The Company may, from time to time, restructure existing derivative contracts or enter into new transactions to effectively modify the terms of current contracts in order to improve the pricing parameters in existing contracts.

At March 31, 2024, the Company had the following outstanding commodity derivative contracts:

Commodity	Settlement Period	Derivative Instrument	Volumes		Weighted Average Prices
					Fixed-Price Swaps		Sub-Floor		Floor		Ceiling
Crude oil	2024	Two-way collars	4,395,000	Bbls					$	65.30	$	82.62
Crude oil	2024	Three-way collars	736,000	Bbls			$	55.00	$	71.25	$	92.14
Crude oil	2024	Fixed-price swaps	639,000	Bbls	$	74.89
Crude oil	2025	Two-way collars	1,181,000	Bbls					$	60.00	$	79.05
Crude oil	2025	Three-way collars	2,371,000	Bbls			$	52.69	$	67.69	$	82.14
Crude oil	2026	Three-way collars	270,000	Bbls			$	50.00	$	65.00	$	83.70
Natural gas	2025	Fixed-price swaps	651,600	MMBtu	$	3.93

Subsequent to March 31, 2024, the Company entered into the following commodity derivative contracts:

					Weighted Average Prices
Commodity	Settlement Period	Derivative Instrument	Volumes		Fixed-Price Swaps		Floor		Ceiling
Crude oil	2024	Two-way collars	736,000	Bbls			$	75.00	$	88.15
Crude oil	2024	Fixed-price swaps	550,000	Bbls	$	80.01

Transportation derivative contracts. The Company has contracts that provide for the transportation of crude oil through a buy/sell structure from North Dakota to either Cushing, Oklahoma or Guernsey, Wyoming. The Company determined that these contracts qualified as derivatives and did not elect the “normal purchase normal sale” exclusion. As of December 31, 2023, the term of one of these contracts expired. The remaining contract requires the purchase and sale of fixed volumes of crude oil through July 2024 as specified in the agreement. As of March 31, 2024 and December 31, 2023, the estimated fair value of the remaining contract was a $2.6 million asset and a $5.9 million asset, respectively, which was classified as a current derivative asset on the Company’s Condensed Consolidated Balance Sheet. The Company records the changes in fair value of these contracts to gathering, processing and transportation (“GPT”) expenses on the Company’s Condensed Consolidated Statement of Operations. Settlements on these contracts are reflected as operating activities on the Company’s Condensed Consolidated Statements of Cash Flows and represent cash payments to the counterparties for transportation of crude oil or the net settlement of contract liabilities if the transportation was not utilized, as applicable. See Note 5—Fair Value Measurements for additional information.

Contingent consideration. The Company bifurcated the Permian Basin Sale Contingent Consideration from the host contract and accounted for it separately at fair value. The Permian Basin Sale Contingent Consideration is marked-to-market each reporting period, with changes in fair value recorded in the other income (expense) section of the Company’s Condensed Consolidated Statements of Operations as a net gain or loss on derivative instruments. As of March 31, 2024, the estimated fair value of the Permian Basin Sale Contingent Consideration was $46.1 million, of which $23.8 million was classified as a current derivative asset and $22.2 million was classified as a non-current derivative asset on the Condensed Consolidated Balance Sheet. As of December 31, 2023, the estimated fair value of the Permian Basin Sale Contingent Consideration was $42.7 million, of which $22.6 million was classified as a current derivative asset and $20.1 million was classified as a non-current derivative asset on the Condensed Consolidated Balance Sheet. See Note 5—Fair Value Measurements for additional information.

14

The following table summarizes the location and amounts of gains and losses from the Company’s derivative instruments recorded in the Company’s Condensed Consolidated Statements of Operations for the periods presented:

		Three Months Ended March 31,
Derivative Instrument	Statements of Operations Location	2024		2023
		(In thousands)
Commodity derivatives	Net gain (loss) on derivative instruments	$	(30,951)	$	65,840
Commodity derivatives (buy/sell transportation contracts)	Gathering, processing and transportation expenses(1)	(3,229)		11,157
Contingent consideration	Net gain (loss) on derivative instruments	3,374		1,094

__________________ 

(1)    The change in the fair value of the transportation derivative contracts was recorded in GPT expenses as a loss for the three months ended March 31, 2024 and as a gain for the three months ended March 31, 2023.

In accordance with the FASB’s authoritative guidance on disclosures about offsetting assets and liabilities, the Company is required to disclose both gross and net information about instruments and transactions eligible for offset in the statement of financial position as well as instruments and transactions subject to an agreement similar to a master netting agreement. The Company’s derivative instruments are presented as assets and liabilities on a net basis by counterparty, as all counterparty contracts provide for net settlement. No margin or collateral balances are deposited with counterparties, and as such, gross amounts are offset to determine the net amounts presented in the Company’s Condensed Consolidated Balance Sheets.

15

The following table summarizes the location and fair value of all outstanding derivative instruments recorded in the Company’s Condensed Consolidated Balance Sheets:

		March 31, 2024
Derivative Instrument	Balance Sheet Location	Gross Amount		Gross Amount Offset		Net Amount
		(In thousands)
Derivatives assets:
Commodity derivatives	Derivative instruments — current assets	$	9,317	$	(9,273)	$	44
Contingent consideration	Derivative instruments — current assets	23,849		—		23,849
Commodity derivatives (buy/sell transportation contracts)	Derivative instruments — current assets	2,647		—		2,647
Commodity derivatives	Derivative instruments — non-current assets	14,485		(14,485)		—
Contingent consideration	Derivative instruments — non-current assets	22,231		—		22,231
Total derivatives assets		$	72,529	$	(23,758)	$	48,771
Derivatives liabilities:
Commodity derivatives	Derivative instruments — current liabilities	$	28,796	$	(9,273)	$	19,523
Commodity derivatives	Derivative instruments — non-current liabilities	17,507		(14,485)		3,022
Total derivatives liabilities		$	46,303	$	(23,758)	$	22,545
		December 31, 2023
Derivative Instrument	Balance Sheet Location	Gross Amount		Gross Amount Offset		Net Amount
		(In thousands)
Derivatives assets:
Commodity derivatives	Derivative instruments — current assets	$	20,647	$	(11,769)	$	8,878
Contingent consideration	Derivative instruments — current assets	22,614		—		22,614
Commodity derivatives (buy/sell transportation contracts)	Derivative instruments — current assets	5,877		—		5,877
Commodity contracts	Derivative instruments — non-current assets	16,760		(14,326)		2,434
Contingent consideration	Derivative instruments — non-current assets	20,092		—		20,092
Total derivatives assets		$	85,990	$	(26,095)	$	59,895
Derivatives liabilities:
Commodity derivatives	Derivative instruments — current liabilities	$	25,978	$	(11,769)	$	14,209
Commodity derivatives	Derivative instruments — non-current liabilities	15,043		(14,326)		717
Total derivatives liabilities		$	41,021	$	(26,095)	$	14,926

16

7. Property, Plant and Equipment

The following table sets forth the Company’s property, plant and equipment:

	March 31, 2024		December 31, 2023
	(In thousands)
Proved oil and gas properties	$	6,476,984	$	6,220,766
Less: Accumulated depletion	(1,198,211)		(1,035,393)
Proved oil and gas properties, net	5,278,773		5,185,373
Unproved oil and gas properties	98,322		99,477
Other property and equipment	49,087		49,051
Less: Accumulated depreciation	(20,073)		(19,223)
Other property and equipment, net	29,014		29,828
Total property, plant and equipment, net	$	5,406,109	$	5,314,678

8. Acquisitions

2024 Acquisition

On February 21, 2024, the Company entered into the Arrangement Agreement, pursuant to which, among other things, the Company has agreed to acquire Enerplus in a stock-and-cash transaction (such transaction, the “Arrangement”), subject to satisfaction of certain closing conditions.

Under the terms of the Arrangement Agreement, among other things, Enerplus shareholders will receive 0.10125 shares of Chord common stock and $1.84 in cash in exchange for each common share of Enerplus they own at the closing of the Arrangement. The transaction is expected to close in the second quarter of 2024. The Arrangement will be accounted for under the acquisition method of accounting in accordance with FASB ASC 805, Business Combinations.

2023 Acquisition

On May 22, 2023, the Company announced that a wholly-owned subsidiary of the Company had entered into a definitive agreement to acquire approximately 62,000 net acres in the Williston Basin from XTO Energy Inc. and affiliates, each a subsidiary of Exxon Mobil Corporation (collectively “XTO”), for total cash consideration of $375.0 million, subject to customary purchase price adjustments (the “2023 Williston Basin Acquisition”). The effective date of the 2023 Williston Basin Acquisition was April 1, 2023.

On June 30, 2023, the Company completed the 2023 Williston Basin Acquisition for total cash consideration of $361.6 million, including a deposit of $37.5 million paid to XTO upon execution of the purchase and sale agreement and $324.1 million paid to XTO at closing (including customary purchase price adjustments). The Company funded the 2023 Williston Basin Acquisition with cash on hand. The 2023 Williston Basin Acquisition was accounted for as a business combination and was recorded under the acquisition method of accounting in accordance with ASC 805. The post-acquisition operating results and pro forma revenue and earnings for the 2023 Williston Basin Acquisition were not material to the Company’s condensed consolidated financial statements and have therefore not been presented.

Purchase price allocation. The Company recorded the assets acquired and liabilities assumed in the 2023 Williston Basin Acquisition at their estimated fair value on June 30, 2023 of $361.6 million. The allocation of the fair value to the identifiable assets acquired and liabilities assumed resulted in no goodwill or bargain purchase gain being recognized. Determining the fair value of the assets and liabilities of the 2023 Williston Basin Acquisition required judgement and certain assumptions to be made. See Note 5—Fair Value Measurements for additional information.

17

The table below presents the total consideration transferred and its allocation to the identifiable assets acquired and liabilities assumed as of the acquisition date on June 30, 2023. As provided under ASC 805, the purchase price allocation may be subject to change for up to one year after June 30, 2023, which may result in a different allocation than what is presented in the table below. As of December 31, 2023, the purchase price was finalized with an immaterial adjustment to the preliminary purchase price allocation.

	Purchase Price Consideration
	(In thousands)
Cash consideration transferred	$	361,609

	Purchase Price Allocation
	(In thousands)
Assets acquired:
Oil and gas properties	$	367,672
Inventory	1,844
Total assets acquired	$	369,516
Liabilities assumed:
Asset retirement obligations	$	6,771
Revenue and production taxes payable	1,136
Total liabilities assumed	$	7,907
Net assets acquired	$	361,609

9. Divestitures

2024 Divestitures

Other divestitures. During the three months ended March 31, 2024, the Company completed certain non-operated wellbore divestitures in the Williston Basin for total net cash proceeds of $2.4 million. Subsequently, in April 2024, the Company completed additional non-operated wellbore divestitures in the Williston Basin for total net cash proceeds of $12.2 million.

2023 Divestitures

Non-core properties. During the year ended December 31, 2023, the Company entered into separate agreements with multiple buyers to sell a vast majority of its non-core properties located outside of the Williston Basin (the “Non-core Asset Sales”). As of December 31, 2023, the Company completed these Non-core Asset Sales and received total net cash proceeds (including purchase price adjustments) of $39.1 million, subject to customary post-closing adjustments. During the year ended December 31, 2023, the Company recorded a pre-tax net loss on sale of assets of $8.4 million for the Non-core Asset Sales and an impairment loss of $5.6 million to adjust the carrying value of the assets held for sale to their estimated fair value less costs to sell. The impairment loss was recorded within exploration and impairment expenses on the Condensed Consolidated Statements of Operations.

Other divestitures. In addition, during the year ended December 31, 2023, the Company completed certain non-operated wellbore divestitures in the Williston Basin for total net cash proceeds of $12.1 million.

10. Investment in Unconsolidated Affiliate

As of March 31, 2024 and December 31, 2023, the fair value of the Company’s investment in Energy Transfer was $114.2 million and $100.2 million, respectively. As of March 31, 2024 and December 31, 2023, the Company owned less than 5% of Energy Transfer’s issued and outstanding common units. The carrying amount of the Company’s investment in Energy Transfer is recorded to investment in unconsolidated affiliate on the Condensed Consolidated Balance Sheet.

18

During the three months ended March 31, 2024, the Company recorded a net gain of $16.3 million on its investment in Energy Transfer, comprised of an unrealized gain for the change in fair value of the investment of $14.0 million and a realized gain for cash distributions received of $2.3 million. During the three months ended March 31, 2023, the Company recorded a net loss of $2.2 million on its investment, including an unrealized loss for the change in the fair value of its investment of $5.7 million, partially offset by a realized gain for cash distributions received of $3.0 million.

11. Long-Term Debt

The Company’s long-term debt consists of the following:

	March 31, 2024		December 31, 2023
	(In thousands)
Senior secured revolving line of credit	$	—	$	—
Senior unsecured notes	400,000		400,000
Less: unamortized deferred financing costs	(3,676)		(4,098)
Total long-term debt, net	$	396,324	$	395,902

Senior secured revolving line of credit. The Company has a senior secured revolving credit facility (the “Credit Facility”) with a $2.5 billion borrowing base and $1.0 billion of elected commitments that matures on July 1, 2027. At March 31, 2024 and December 31, 2023, the Company had no borrowings outstanding and $8.9 million of outstanding letters of credit issued under the Credit Facility, resulting in an unused borrowing capacity of $991.1 million.

During the three months ended March 31, 2024 and 2023, the Company incurred no borrowings on the Credit Facility, resulting in a weighted average interest rate of 0.00% in each period. The Company was in compliance with the financial covenants under the Credit Facility at March 31, 2024. The fair value of the Credit Facility approximates its carrying value since borrowings under the Credit Facility bear interest at variable rates, which are tied to current market rates.

Borrowings are subject to varying rates of interest based on (i) the total outstanding borrowings (including the value of all outstanding letters of credit) in relation to the borrowing base and (ii) whether the loan is a Term SOFR Loan or an ABR Loan (each as defined in the Credit Facility). The Company incurs interest on outstanding loans at their respective interest rate plus a margin rate ranging between 1.75% to 2.75% for Term SOFR Loans and 0.75% to 1.75% for ABR Loans. In addition, Term SOFR Loans are also subject to a 0.1% credit spread adjustment. The unused borrowing base is subject to a commitment fee ranging between 0.375% to 0.500%.

The Company is expected to complete the semi-annual borrowing base redetermination in the second quarter of 2024.

Senior unsecured notes. At March 31, 2024, the Company had $400.0 million of 6.375% senior unsecured notes outstanding due June 1, 2026 (the “Senior Notes”). Interest on the Senior Notes is payable semi-annually on June 1 and December 1 of each year. As of March 31, 2024 and December 31, 2023, the fair value of the Senior Notes, which are publicly traded among qualified institutional investors and represent a Level 1 fair value measurement, was $401.7 million and $400.0 million, respectively.

12. Asset Retirement Obligations

The following table reflects the changes in the Company’s ARO during the three months ended March 31, 2024 (in thousands):

Balance at December 31, 2023	$	165,546
Liabilities incurred during period	973
Liabilities settled during period	1,317
Accretion expense during period	2,913
Balance at March 31, 2024	$	170,749

Accretion expense is included in depreciation, depletion and amortization on the Company’s Condensed Consolidated Statements of Operations. At March 31, 2024, the current portion of the total ARO balance was $15.1 million and is included in accrued liabilities on the Company’s Condensed Consolidated Balance Sheet.

19

13. Income Taxes

The Company’s effective tax rate was 22.4% of pre-tax income for the three months ended March 31, 2024 as compared to an effective tax rate of 23.6% for the three months ended March 31, 2023.

The effective tax rates for the three months ended March 31, 2024 and 2023 were higher than the statutory federal rate of 21% primarily as a result of the impact of state income taxes.

14. Equity-Based Compensation

The Company has previously granted RSUs, PSUs and LSUs (each as defined below), as well as phantom unit awards under its equity compensation plans.

Equity-based compensation expenses are recognized in general and administrative expenses on the Company’s Condensed Consolidated Statements of Operations. During the three months ended March 31, 2024 and 2023, the Company recognized $4.8 million and $11.9 million, respectively, in equity-based compensation expenses related to equity-classified awards. Equity-based compensation costs related to liability-classified awards were not material for the three months ended March 31, 2024 or 2023.

Restricted stock units. Restricted stock units (“RSUs”) are contingent shares that generally vest on either a cliff or graded basis over a one-year, three-year or four-year period (as applicable) and are subject to a service condition. During the three months ended March 31, 2024, the Company granted 120,071 RSUs to employees of the Company with a weighted average grant date value of $163.48 per share.

Performance share units. Performance share units (“PSUs”) that were granted prior to 2024 are contingent shares that vest on a graded basis over a three-year and four-year period and are subject to a service condition.

2024 Performance share units. During the three months ended March 31, 2024, the Company issued PSUs that include (i) total stockholder return (“TSR”) PSUs (“Absolute TSR PSUs”) and (ii) relative TSR PSUs (“Relative TSR PSUs” and collectively with the Absolute TSR PSUs, the “2024 PSUs”), which are eligible to vest and become earned at the end of the applicable performance period on December 31, 2026, subject to the level of achievement with respect to certain performance goals.

The Absolute TSR PSUs are subject to time-based service requirements and market conditions based on the TSR achieved by the Company during the performance period. Depending on the Company’s TSR, award recipients may earn between 0% and 300% of the target number of Absolute TSR PSUs originally granted.

The Relative TSR PSUs are subject to time-based service requirements and market conditions based on a comparison of the TSR achieved by the Company against the TSR achieved by the members of a defined peer group at the end of the performance period. Depending on the Company’s TSR performance relative to the TSR performance of the members of the defined peer group, award recipients may earn between 0% and 200% of the target number of Relative TSR PSUs originally granted.

Any earned 2024 PSUs will be settled in shares of the Company’s common stock for up to 100% of the target number of PSUs subject to each applicable award, with any remaining earned PSUs that exceed the target number of PSUs subject to the award being settled in cash based on the fair market value of a share of the Company’s common stock on the applicable payment date.

The 2024 PSUs are bifurcated and classified as equity-based and liability-based awards based on the probability of achieving various target performance thresholds. During the three months ended March 31, 2024, the Company granted (i) 14,677 Absolute TSR PSUs to employees of the Company with a weighted average grant date value of $233.19 per share and (ii) 44,033 Relative TSR PSUs to employees of the Company with a weighted average grant date value of $198.73 per share.

Fair value assumptions. The aggregate grant date fair value of the 2024 PSUs was determined by a third-party valuation specialist using a Monte Carlo simulation model which uses a probabilistic approach for estimating the fair value of the awards. The key valuation inputs were: (i) the forecast period, (ii) risk-free interest rate, (iii) the yield curve associated with the Company’s credit rating, (iv) implied equity volatility, (v) stock price on the date of grant and, solely for Relative TSR PSUs, (vi) correlation coefficient. The risk-free interest rates are the U.S. Treasury bond rates on the date of grant that correspond to the performance period. Implied equity volatility is derived by solving for an asset volatility and equity volatility based on the leverage of the Company and each of its peers. For the Relative TSR PSUs, the correlation coefficient measures the strength of the linear relationship between and amongst the Company and its peers based on historical stock price data.

20

The following table summarizes the assumptions used in the Monte Carlo simulation model to determine the grant date fair value and associated equity-based compensation expenses by grant date for the 2024 PSUs:

	Absolute TSR		Relative TSR
Grant date	February 20, 2024	March 4, 2024	February 20, 2024	March 4, 2024
Forecast period (years)	3	3	3	3
Risk-free interest rates	4.4%	4.4%	4.4%	4.4%
Implied equity volatility	35%	35%	35%	35%
Stock price on date of grant	$163.75	$160.23	$163.75	$160.23

Leveraged stock units. Leveraged stock units (“LSUs”) are contingent shares granted to certain employees that cliff vest over a three-year and four-year period and are subject to a service condition. No LSUs were granted during the three months ended March 31, 2024.

Phantom unit awards. Phantom unit awards represent the right to receive a cash payment equal to the fair market value of one share of common stock upon vesting and vest on a graded basis over a three-year period and are subject to a service condition. During the three months ended March 31, 2024, the Company granted 10,531 phantom unit awards to employees with a weighted average grant date fair value of $163.75 per share.

15. Stockholders’ Equity

Dividends

The following table summarizes the Company’s fixed and variable dividends declared for the three months ended March 31, 2024 and 2023:

	Rate per Share
	Base		Variable		Total		Total Dividends Declared
							(In thousands)
Q1 2024	$	1.25	$	2.00	$	3.25	$	137,541
Q1 2023	1.25		3.55		4.80		204,884

Total dividends declared in the table above includes $2.5 million and $5.1 million associated with dividend equivalent rights on unvested equity-based compensation awards for the three months ended March 31, 2024 and 2023, respectively.

On May 7, 2024, the Company declared a base-plus-variable cash dividend of $2.94 per share of common stock. The dividend will be payable on June 5, 2024 to shareholders of record as of May 22, 2024.

Share Repurchase Program

During the three months ended March 31, 2024, the Company repurchased 193,269 shares of common stock at a weighted average price of $155.20 per common share for a total cost of $30.0 million. As of March 31, 2024, there was $653.0 million of capacity remaining under the Company’s $750.0 million share repurchase program.

During the three months ended March 31, 2023, the Company repurchased 110,667 shares of common stock at a weighted average price of $135.55 per common share for a total cost of $15.0 million.

Warrants

As of March 31, 2024, the Company had 2,812,498 warrants outstanding, comprised of (i) 494,352 warrants with an exercise price of $75.57 per share that expire on November 19, 2024, (ii) 1,102,262 warrants with an exercise price of $116.37 per share that expire on September 1, 2024 and (iii) 1,215,884 warrants with an exercise price of $133.70 per share that expire on September 1, 2025.

During the three months ended March 31, 2024 and March 31, 2023, there were 420,157 and 82,954 warrants exercised, respectively.

21

16. Earnings Per Share

The Company calculates earnings per share under the two-class method. The Company has granted RSUs to non-employee directors which include non-forfeitable rights to dividends and are therefore considered “participating securities.” Accordingly, the Company computes earnings per share under the two-class earnings allocation method, which computes earnings per share for each class of common stock and participating security according to dividends declared (or accumulated) and participation rights in undistributed earnings.

Basic earnings per share amounts have been computed as (i) net income (loss) (ii) less distributed and undistributed earnings allocated to participating securities (iii) divided by the weighted average number of basic shares outstanding for the periods presented. Diluted earnings per share amounts have been computed as (i) basic net income attributable to common stockholders (ii) plus the reallocation of distributed and undistributed earnings allocated to participating securities (iii) divided by the weighted average number of diluted shares outstanding for the periods presented. The Company calculates diluted earnings per share under both the two-class method and treasury stock method and reports the more dilutive of the two calculations.

The following table summarizes the basic and diluted earnings per share for the periods presented:

	Three Months Ended March 31,
	2024		2023
	(In thousands, except per share data)
Net income	$	199,353	$	296,999
Distributed and undistributed earnings allocated to participating securities	(787)		(682)
Net income attributable to common stockholders (basic)	198,566		296,317
Reallocation of distributed and undistributed earnings allocated to participating securities	7		8
Net income attributable to common stockholders (diluted)	$	198,573	$	296,325
Weighted average common shares outstanding:
Basic weighted average common shares outstanding	41,468		41,568
Dilutive effect of share-based awards	500		902
Dilutive effect of warrants	779		679
Diluted weighted average common shares outstanding	42,747		43,149
Basic earnings per share	$	4.79	$	7.13
Diluted earnings per share	$	4.65	$	6.87
Anti-dilutive weighted average common shares:
Potential common shares	2,238		4,561

    

For the three months ended March 31, 2024 and 2023, the diluted earnings per share calculation excludes the impact of unvested share-based awards and outstanding warrants that were anti-dilutive.

17. Commitments and Contingencies

As of March 31, 2024, the Company’s material off-balance sheet arrangements and transactions include $8.9 million in outstanding letters of credit under the Credit Facility and $31.6 million in net surety bond exposure issued as financial assurance on certain agreements.

As of March 31, 2024, there have been no material changes to the Company’s commitments and contingencies disclosed in Note 21 — Commitments and Contingencies in the 2023 Annual Report.

22

18. Leases

In the first quarter of 2023, the Company began negotiations to sublease a portion of its Denver corporate office. As a result of an offer received and the overall market conditions, the Company recorded a right-of-use (“ROU”) asset impairment charge of $17.5 million during the three months ended March 31, 2023. This asset impairment charge primarily consisted of $12.1 million related to the amount by which the carrying value of the ROU asset exceeded the fair value and $5.5 million related to the remaining leasehold improvements. The Company estimated the fair value of the ROU asset using an income approach based on the net present value of the expected sublease rental income during the sublease term. The ROU asset impairment charge is recorded within exploration and impairment on the Condensed Consolidated Statements of Operations. There were no lease impairment charges recorded during the three months ended March 31, 2024.

Other than the item disclosed above, no other material changes have occurred to the Company’s lease portfolio for the periods presented. Refer to the 2023 Annual Report for more information on the Company’s leases.

23

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

The following discussion and analysis of our financial condition and results of operations should be read in conjunction with “Management’s Discussion and Analysis of Financial Condition and Results of Operations” contained in our Annual Report on Form 10-K for the year ended December 31, 2023 (“2023 Annual Report”), as well as the unaudited condensed consolidated financial statements and notes thereto included in this Quarterly Report on Form 10-Q.

CAUTIONARY NOTE REGARDING FORWARD-LOOKING STATEMENTS

This Quarterly Report on Form 10-Q contains “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933, as amended (the “Securities Act”), and Section 21E of the Securities Exchange Act of 1934, as amended (the “Exchange Act”). These forward-looking statements are subject to a number of risks and uncertainties, many of which are beyond our control. All statements, other than statements of historical fact included in this Quarterly Report on Form 10-Q, regarding our strategic tactics, future operations, financial position, estimated revenues and losses, projected costs, prospects, plans and objectives of management are forward-looking statements. When used in this Quarterly Report on Form 10-Q, the words “aim,” “mission,” “could,” “believe,” “anticipate,” “intend,” “estimate,” “expect,” “may,” “continue,” “predict,” “potential,” “project,” “plans” and similar expressions are intended to identify forward-looking statements, although not all forward-looking statements contain such identifying words. In particular, the factors discussed below and detailed under “Part II, Item 1A. Risk Factors” in this Quarterly Report on Form 10-Q could affect our actual results and cause our actual results to differ materially from expectations, estimates, or assumptions expressed in, forecasted in, or implied in such forward-looking statements.

These forward-looking statements are based on management’s current belief, based on currently available information, as to the outcome and timing of future events. Without limiting the generality of the foregoing, certain statements incorporated by reference or included in this Quarterly Report on Form 10-Q constitute forward-looking statements.

Forward-looking statements may include statements about:

•crude oil, NGLs and natural gas realized prices;

•uncertainty regarding the future actions of foreign oil producers and the related impacts such actions have on the balance between the supply of and demand for crude oil, NGLs and natural gas;

•the actions taken by OPEC+ with respect to oil production levels and announcements of potential changes in such levels, including the ability of the OPEC+ countries to agree on and comply with supply limitations;

•war between Russia and Ukraine as well as war between Hamas and Israel, with the potential for escalation of hostilities across the surrounding countries in the Middle East, and their effect on commodity prices;

•general economic conditions;

•inflation rates and the impact of associated monetary policy responses, including increased interest rates;

•logistical challenges and supply chain disruptions;

•our business strategy;

•the geographic concentration of our operations;

•estimated future net reserves and present value thereof;

•timing and amount of future production of crude oil, NGLs and natural gas;

•drilling and completion of wells;

•estimated inventory of wells remaining to be drilled and completed;

•costs of exploiting and developing our properties and conducting other operations;

•availability of drilling, completion and production equipment and materials;

•availability of qualified personnel;

•infrastructure for produced and flowback water gathering and disposal;

•gathering, transportation and marketing of crude oil, NGLs and natural gas in the Williston Basin and other regions in the United States;

•the possible shutdown of the Dakota Access Pipeline;

•the expected timing and closing of the Arrangement (as defined in the “Recent Developments” section of Item 2 below);

24

•the possibility that required shareholder approvals related to the Arrangement may not be obtained;

•the risk that a condition to closing the Arrangement may not be satisfied;

•the risk that either party may terminate the Arrangement Agreement (as defined in the “Recent Developments” section of Item 2 below) upon the occurrence of certain circumstances or that the closing of the Arrangement might be delayed or not occur at all;

•property acquisitions, including the Arrangement, and divestitures;

•integration and benefits of property acquisitions or the effects of such acquisitions on our cash position and levels of indebtedness, including the Arrangement;

•any litigation relating to the Arrangement;

•the amount, nature and timing of capital expenditures;

•availability and terms of capital;

•our financial strategic tactics, budget, projections, execution of business plan and operating results;

•cash flows and liquidity;

•our ability to return capital to shareholders;

•our ability to utilize net operating loss carryforwards or other tax attributes in future periods;

•our ability to comply with the covenants under our credit agreement and other indebtedness;

•operating hazards, natural disasters, weather-related delays, casualty losses and other matters beyond our control;

•interruptions in service and fluctuations in tariff provisions of third-party connecting pipelines;

•potential effects arising from cybersecurity threats, terrorist attacks and any consequential or other hostilities;

•compliance with, and, changes in environmental, safety and other laws and regulations, including the Inflation Reduction Act of 2022;

•execution of our ESG initiatives;

•effectiveness of risk management activities;

•competition in the oil and gas industry;

•counterparty credit risk;

•incurring environmental liabilities;

•developments in the global economy as well as any public health crisis similar to or caused by a recurrence of the novel COVID-19 pandemic and resulting demand and supply for crude oil, NGLs and natural gas;

•governmental regulation and the taxation of the oil and gas industry;

•developments in crude oil-producing and natural gas-producing countries;

•technology;

•consumer demand and preferences for, and governmental policies encouraging, fossil fuel alternatives;

•the effects of accounting pronouncements issued periodically during the periods covered by forward-looking statements;

•uncertainty regarding future operating results;

•our ability to successfully forecast future operating results and manage activity levels with ongoing macroeconomic uncertainty;

•the impact of disruptions in the financial markets, including any bank failures and the interest rate environment;

•plans, objectives, expectations and intentions contained in this Quarterly Report on Form 10-Q that are not historical; and

•certain factors discussed elsewhere in this Quarterly Report on Form 10-Q, in our 2023 Annual Report and in our other filings with the SEC.

25

All forward-looking statements speak only as of the date of this Quarterly Report on Form 10-Q. We undertake no obligation to publicly update any forward-looking statement, whether written or oral, that may be made from time to time, whether as a result of new information, future developments or otherwise. You should not place undue reliance on these forward-looking statements. Although we believe that our plans, intentions and expectations reflected in or suggested by the forward-looking statements we make in this Quarterly Report on Form 10-Q are reasonable, we can give no assurance that these plans, intentions or expectations will be achieved. Some of the key factors which could cause actual results to vary from our expectations include changes in crude oil, NGL and natural gas prices, climatic and environmental conditions, the timing of planned capital expenditures, availability of acquisitions, uncertainties in estimating proved reserves and forecasting production results, operational factors affecting the commencement or maintenance of producing wells, the condition of the capital markets generally, as well as our ability to access them, inflation, the proximity to and capacity of transportation facilities and uncertainties regarding environmental regulations or litigation and other legal or regulatory developments affecting our business, as well as those factors discussed below and elsewhere in this Quarterly Report on Form 10-Q, all of which are difficult to predict. In light of these risks, uncertainties and assumptions, the forward-looking events discussed may not occur. These cautionary statements qualify all forward-looking statements attributable to us or persons acting on our behalf.

26

Overview

Chord Energy Corporation (together with its consolidated subsidiaries, the “Company”, “Chord”, “we”, “us,” or “our”) is an independent exploration and production (“E&P”) company engaged in the acquisition, exploration, development and production of crude oil, NGL and natural gas in the Williston Basin. Our mission is to responsibly produce hydrocarbons while exercising capital discipline, operating efficiently, improving continuously and providing a rewarding environment for our employees. We are ideally positioned to enhance return of capital and generate strong free cash flow, while being responsible stewards of the communities and environment where we operate.

Market Conditions and Commodity Prices

Our revenue, profitability and ability to return cash to shareholders depend substantially on factors beyond our control, such as economic, political and regulatory developments as well as competition from other sources of energy. Prices for crude oil, NGLs and natural gas have experienced significant fluctuations in recent years and may continue to fluctuate widely in the future due to a combination of macro-economic factors that impact the supply and demand for crude oil, NGLs and natural gas.

While we are unable to predict future commodity prices, we do not believe that an impairment of our oil and gas properties is reasonably likely to occur in the near future at current price levels; however, we would evaluate the recoverability of the carrying value of our oil and gas properties as a result of a future material or extended decline in the price of crude oil, NGLs or natural gas or a material increase in the costs of labor, materials or services.

In an effort to improve price realizations from the sale of our crude oil, NGLs and natural gas, we manage our commodities marketing activities in-house, which enables us to market and sell our crude oil, NGLs and natural gas to a broader array of potential purchasers. We enter into crude oil, NGL and natural gas sales contracts with purchasers who have access to transportation capacity, utilize derivative financial instruments to manage our commodity price risk and enter into physical delivery contracts to manage our price differentials. Due to the availability of other markets and pipeline connections, we do not believe that the loss of any single customer would have a material adverse effect on our results of operations or cash flows.

Additionally, we sell a significant amount of our crude oil production through gathering systems connected to multiple pipeline and rail facilities. These gathering systems, which originate at the wellhead, reduce the need to transport barrels by truck from the wellhead, helping remove trucks from local highways and reduce greenhouse gas emissions. As of March 31, 2024, substantially all of our gross operated crude oil and natural gas production were connected to gathering systems.

Recent Developments

Pending Acquisition

On February 21, 2024, we entered into an arrangement agreement (the “Arrangement Agreement ”) with Enerplus Corporation, a corporation existing under the laws of the Province of Alberta, Canada (“Enerplus”), and Spark Acquisition ULC, an unlimited liability company organized and existing under the laws of the Province of Alberta, Canada and a wholly-owned subsidiary of the Company, pursuant to which, among other things, we have agreed to acquire Enerplus in a stock-and-cash transaction (such transaction, the “Arrangement”), subject to satisfaction of certain closing conditions. The transaction will be effected by way of a plan of arrangement under the Business Corporations Act (Alberta) (the “Plan of Arrangement”).

Enerplus is an independent North American oil and gas exploration and production company. We believe that the combination of Chord and Enerplus will provide improving returns, capital efficiency, low-cost inventory, and a peer-leading balance sheet, all of which support sustainable free cash flow generation and meaningful shareholder returns. Under the terms of the Arrangement Agreement, among other things, Enerplus shareholders will receive 0.10125 shares of Chord common stock and $1.84 in cash in exchange for each common share of Enerplus they own at closing. The transaction is expected to close on May 31, 2024, subject to customary closing conditions.

27

Results of Operations

Operational and Financial Highlights

•Production volumes averaged 168,424 Boepd (59% oil), including crude oil volumes of 99,036 Bopd in the first quarter of 2024.

•E&P and other capital expenditures (excluding capitalized interest) were $257.7 million in the first quarter of 2024.

•Lease operating expenses (“LOE”) were $10.39 Boe in the first quarter of 2024.

•Net cash provided by operating activities was $406.7 million, and net income was $199.4 million in the first quarter of 2024.

Shareholder Return Highlights

•Paid $3.25 per share base-plus-variable cash dividend on March 19, 2024.

•Repurchased $30.0 million of common stock in the first quarter of 2024 with $653.0 million remaining under our $750 million share repurchase program.

•Declared a base-plus-variable cash dividend of $2.94 per share of common stock. The dividend will be payable on June 5, 2024 to shareholders of record as of May 22, 2024.

Revenues

Our crude oil, NGL and natural gas revenues are derived from the sale of crude oil, NGL and natural gas production. These revenues do not include the effects of derivative instruments and may vary significantly from period to period as a result of changes in volumes of production sold or changes in commodity prices. Our purchased oil and gas sales are derived from the sale of crude oil, NGLs and natural gas purchased through our marketing activities primarily to optimize transportation costs, for blending to meet pipeline specifications or to cover production shortfalls. Revenues and expenses from crude oil, NGL and natural gas sales and purchases are generally recorded on a gross basis, as we act as a principal in these transactions by assuming control of the purchased crude oil or natural gas before it is transferred to the counterparty. In certain cases, we enter into sales and purchases with the same counterparty in contemplation of one another, and these transactions are recorded on a net basis.

28

The following table summarizes our revenues, production and average realized prices for the periods presented:

	Three Months Ended March 31, 2024		Three Months Ended December 31, 2023		Three Months Ended March 31, 2023
Revenues (in thousands)
Crude oil revenues	$	678,851	$	761,216	$	650,908
NGL revenues	47,256		45,897		62,243
Natural gas revenues	22,055		23,047		53,049
Purchased oil and gas sales	337,098		134,525		130,317
Total revenues	$	1,085,260	$	964,685	$	896,517
Production data
Crude oil (MBbls)	9,012		9,774		8,560
NGLs (MBbls)	3,133		3,506		2,946
Natural gas (MMcf)	19,090		21,755		19,923
Oil equivalents (MBoe)	15,327		16,907		14,827
Average daily production (Boepd)	168,424		183,768		164,740
Average daily crude oil production (Bopd)	99,036		106,243		95,113
Average sales prices
Crude oil (per Bbl)
Average sales price	$	75.32	$	77.88	$	76.04
Effect of derivative settlements(1)	(0.15)		(5.16)		(10.25)
Average realized price after the effect of derivative settlements(1)	$	75.17	$	72.72	$	65.79
NGLs (per Bbl)
Average sales price	$	15.09	$	13.09	$	21.13
Effect of derivative settlements(1)	—		—		0.97
Average realized price after the effect of derivative settlements(1)	$	15.09	$	13.09	$	22.10
Natural gas (per Mcf)
Average sales price	$	1.16	$	1.06	$	2.66
Effect of derivative settlements(1)	—		—		(0.35)
Average realized price after the effect of derivative settlements(1)	$	1.16	$	1.06	$	2.31

____________________

(1)The effect of derivative settlements includes the gains or losses on commodity derivatives for contracts ending in the periods presented. Our commodity derivatives do not qualify for or were not designated as hedging instruments for accounting purposes.

Three months ended March 31, 2024 as compared to three months ended December 31, 2023

Crude oil revenues. Our crude oil revenues decreased $82.4 million to $678.9 million for the three months ended March 31, 2024 as compared to the three months ended December 31, 2023. Our crude oil revenues decreased $57.4 million due to lower crude oil production volumes sold quarter over quarter driven by inclement weather conditions in the first quarter of 2024 and $25.0 million due to lower crude oil realized prices. Average crude oil sales prices, without derivative settlements, decreased by $2.56 per barrel quarter over quarter to an average of $75.32 per barrel for the three months ended March 31, 2024 due to a decrease in NYMEX WTI and lower price differentials.

NGL revenues. Our NGL revenues increased $1.4 million to $47.3 million for the three months ended March 31, 2024 as compared to the three months ended December 31, 2023. Our NGL revenues increased $7.0 million due to higher NGL realized prices, partially offset by $5.6 million due to lower volumes sold quarter over quarter driven by inclement weather conditions in the first quarter of 2024. Average NGL sales prices, without derivative settlements, increased by $2.00 per barrel quarter over quarter to an average of $15.09 per barrel for the three months ended March 31, 2024 primarily due to higher index prices at the Conway hub in Kansas.

29

Natural gas revenues. Our natural gas revenues decreased $1.0 million to $22.1 million for the three months ended March 31, 2024 as compared to the three months ended December 31, 2023. Our natural gas revenues decreased $3.1 million due to decreased volumes sold quarter over quarter, partially offset by $2.2 million due to higher realized natural gas prices. Average natural gas sales prices, without derivative settlements, increased by $0.10 per Mcf quarter over quarter to $1.16 per Mcf for the three months ended March 31, 2024 primarily due to higher index prices.

Purchased oil and gas sales. Purchased oil and gas sales increased $202.6 million to $337.1 million for the three months ended March 31, 2024 as compared to the three months ended December 31, 2023. This increase was primarily due to an increase in volumes of crude oil purchased and subsequently sold.

Three months ended March 31, 2024 as compared to three months ended March 31, 2023

Crude oil revenues. Our crude oil revenues increased $27.9 million to $678.9 million for the three months ended March 31, 2024 as compared to the three months ended March 31, 2023. Our crude oil revenues increased $34.1 million due to higher crude oil production volumes sold period over period due to more wells TIL’d during the last twelve months, partially offset by a decrease of $6.2 million due to lower crude oil realized prices. Average crude oil sales prices, without derivative settlements, decreased by $0.72 per barrel period over period to an average of $75.32 per barrel for the three months ended March 31, 2024 driven by lower price differentials.

NGL revenues. Our NGL revenues decreased $15.0 million to $47.3 million for the three months ended March 31, 2024 as compared to the three months ended March 31, 2023. This decrease was primarily driven by a $17.8 million decrease due to lower NGL realized prices, partially offset by a $2.8 million increase due to higher production volumes sold period over period. Average NGL sales prices, without derivative settlements, decreased by $6.04 per barrel period over period to an average of $15.09 for the three months ended March 31, 2024 due to the impact of incurring a fixed fee for the majority of our NGL marketing contracts beginning in the second quarter of 2023.

Natural gas revenues. Our natural gas revenues decreased $31.0 million to $22.1 million for the three months ended March 31, 2024 as compared to the three months ended March 31, 2023 primarily due to lower realized gas prices. Average natural gas sales prices, without derivative settlements, decreased by $1.50 per Mcf period over period to $1.16 per Mcf for the three months ended March 31, 2024 primarily due to the impact of incurring a fixed fee for the majority of our natural gas marketing contracts beginning in the second quarter of 2023, coupled with lower index prices.

Purchased oil and gas sales. Purchased oil and gas sales increased $206.8 million to $337.1 million for the three months ended March 31, 2024 as compared to the three months ended March 31, 2023. This increase was primarily due to an increase in the volume of crude oil purchased and subsequently sold.

30

Expenses and other income (expense)

The following table summarizes our operating expenses and other income (expense) for the periods presented:

	Three Months Ended March 31, 2024		Three Months Ended December 31, 2023		Three Months Ended March 31, 2023
	(In thousands, except per Boe of production data)
Operating expenses
Lease operating expenses	$	159,206	$	169,861	$	153,408
Gathering, processing and transportation expenses	53,984		47,513		37,015
Purchased oil and gas expenses	335,762		133,892		129,593
Production taxes	63,911		68,512		60,517
Depreciation, depletion and amortization	168,894		167,432		133,791
General and administrative expenses	25,712		25,545		32,484
Exploration and impairment	6,154		2,073		24,864
Total operating expenses	813,623		614,828		571,672
Gain (loss) on sale of assets, net	1,302		(6,502)		1,227
Operating income	272,939		343,355		326,072
Other income (expense)
Net gain (loss) on derivative instruments	(27,577)		51,935		66,934
Net gain (loss) from investment in unconsolidated affiliate	16,296		(91)		(2,216)
Interest expense, net of capitalized interest	(7,592)		(6,344)		(7,135)
Other income	2,826		827		5,193
Total other income (expense), net	(16,047)		46,327		62,776
Income before income taxes	256,892		389,682		388,848
Income tax expense	(57,539)		(88,049)		(91,849)
Net income	$	199,353	$	301,633	$	296,999
Costs and expenses (per Boe of production)
Lease operating expenses	$	10.39	$	10.05	$	10.35
Gathering, processing and transportation expenses	3.52		2.81		2.50
Production taxes	4.17		4.05		4.08

Three months ended March 31, 2024 as compared to three months ended December 31, 2023

Lease operating expenses. LOE decreased $10.7 million to $159.2 million for the three months ended March 31, 2024 as compared to the three months ended December 31, 2023 primarily due to lower fixed and variable costs driven by a decrease in production volumes quarter over quarter. LOE per Boe increased $0.34 per Boe to $10.39 per Boe for the three months ended March 31, 2024 primarily due to lower production volumes quarter over quarter.

Gathering, processing and transportation expenses. GPT expenses increased $6.5 million to $54.0 million for the three months ended March 31, 2024 as compared to the three months ended December 31, 2023. GPT increased primarily due to a $7.0 million higher loss attributable to the change in fair value of certain derivative transportation contracts quarter over quarter. GPT expenses per Boe increased $0.71 per Boe to $3.52 per Boe for the three months ended March 31, 2024 due to the increase described above.

Purchased oil and gas expenses. Purchased oil and gas expenses increased $201.9 million to $335.8 million for the three months ended March 31, 2024 as compared to the three months ended December 31, 2023 driven by an increase in the volume of crude oil purchased quarter over quarter.

Depreciation, depletion and amortization. Depreciation, depletion and amortization (“DD&A”) expense remained relatively consistent for the three months ended March 31, 2024 as compared to the three months ended December 31, 2023. Depletion expense decreased $0.7 million, driven by a decrease of $15.3 million due to lower production volumes quarter over quarter, mostly offset by an increase of $14.6 million due to a higher depletion rate quarter over quarter. The depletion rate increased $0.95 per Boe quarter over quarter to $10.62 per Boe for the three months ended March 31, 2024.

31

General and administrative expenses. General and administrative (“G&A”) expenses increased $0.2 million to $25.7 million for the three months ended March 31, 2024 as compared to the three months ended December 31, 2023. This increase was primarily due to an increase in merger-related costs quarter over quarter of $8.1 million due to the Arrangement, mostly offset by a decrease of $5.3 million due to lower current expected credit losses and a decrease in stock-based compensation costs of $4.1 million due to the vesting of certain equity-based compensation awards during the three months ended December 31, 2023.

Exploration and impairment. Exploration and impairment expenses increased $4.1 million to $6.2 million for the three months ended March 31, 2024 as compared to the three months ended December 31, 2023 primarily as a result of a lower of cost or net realizable value write down of oil-in-tank inventory during the three months ended March 31, 2024. There were no impairment expenses recorded during the three months ended December 31, 2023.

Derivative instruments. We recorded a $27.6 million net loss on derivative instruments for the three months ended March 31, 2024, which was comprised of a net loss of $31.0 million associated with our contracts to manage commodity price risk, partially offset by an unrealized gain of $3.4 million associated with a contract that includes contingent consideration. The net loss of $31.0 million on commodity derivative contracts included an unrealized loss of $29.6 million related to the change in fair value of our commodity derivative contracts and a realized loss of $1.4 million on settled commodity derivative contracts. During the three months ended December 31, 2023, we recorded a $51.9 million net gain on derivative instruments, which primarily included a gain of $52.3 million associated with our contracts to manage commodity price risk. The net gain of $52.3 million on commodity derivative contracts included an unrealized gain of $102.8 million related to the change in fair value of our commodity derivative contracts, partially offset by a realized loss of $50.5 million on settled commodity derivative contracts.

Investment in unconsolidated affiliate. We recorded a $16.3 million gain related to our investment in Energy Transfer LP (“Energy Transfer”) for the three months ended March 31, 2024, primarily due to an unrealized gain of $14.0 million as a result of an increase in the fair value of the investment during the period, coupled with a gain of $2.3 million for a cash distribution received from Energy Transfer. During the three months ended December 31, 2023, we recorded a $0.1 million loss on our investment in Energy Transfer due to an unrealized loss of $2.4 million as a result of a decrease in the fair value of the investment during the period, offset by a gain of $2.3 million for a cash distribution received from Energy Transfer.

Income tax expense. Our effective tax rate for the three months ended March 31, 2024 was relatively consistent with the effective tax rate for the three months ended December 31, 2023. Our income tax expense was recorded at 22.4% and 22.6% of pre-tax income for the three months ended March 31, 2024 and December 31, 2023, respectively.

Three months ended March 31, 2024 as compared to three months ended March 31, 2023

Lease operating expenses. LOE increased $5.8 million to $159.2 million for the three months ended March 31, 2024 as compared to the three months ended March 31, 2023. LOE increased primarily due to $11.7 million of higher fixed and variable costs driven by an increase in well count and production volumes period over period, partially offset by a decrease in workover costs of $5.0 million. LOE per Boe increased $0.04 per Boe period over period to $10.39 per Boe for the three months ended March 31, 2024 primarily due to higher costs described above.

Gathering, processing and transportation expenses. GPT expenses increased $17.0 million to $54.0 million for the three months ended March 31, 2024 as compared to the three months ended March 31, 2023 due to an increase of $14.4 million due to a higher loss attributable to the change in fair value of certain derivative transportation contracts period over period. GPT expenses per Boe increased $1.02 per Boe period over period to $3.52 per Boe for the three months ended March 31, 2024 due to the increase described above.

Purchased oil and gas expenses. Purchased oil and gas expenses increased $206.2 million to $335.8 million for the three months ended March 31, 2024 as compared to the three months ended March 31, 2023 primarily due to an increase in the volume of crude oil purchased.

Depreciation, depletion and amortization. DD&A expense increased $35.1 million to $168.9 million for the three months ended March 31, 2024 as compared to the three months ended March 31, 2023 primarily due to an increase of $28.7 million driven by a higher depletion rate period over period and $4.4 million due to higher production volumes. The depletion rate increased $1.87 per Boe period over period to $10.62 per Boe for the three months ended March 31, 2024.

General and administrative expenses. G&A expenses decreased $6.8 million to $25.7 million for the three months ended March 31, 2024 as compared to the three months ended March 31, 2023. This decrease was due to a decrease in stock-based compensation costs of $7.1 million due to the vesting for certain equity-based compensation awards during the three months ended December 31, 2023, as well as higher credits of $4.4 million related to billable overhead. These decreases were partially offset by an increase in merger-related costs of $5.3 million related to the Arrangement.

32

Exploration and impairment. Exploration and impairment expenses decreased $18.7 million to $6.2 million for the three months ended March 31, 2024 as compared to the three months ended March 31, 2023. During the three months ended March 31, 2024, we recorded an impairment charge of $3.9 million associated with a lower of cost or net realizable value write down of oil-in-tank inventory. During the three months ended March 31, 2023, impairment expenses totaled $23.3 million, which was primarily comprised of $17.5 million associated with the write-down of the right-of-use asset for our Denver office lease and $5.8 million associated with a lower of cost or net realizable value write down of oil-in-tank inventory.

Derivative instruments. We recorded a $27.6 million net loss on derivative instruments for the three months ended March 31, 2024, which was comprised of a net loss of $31.0 million associated with our contracts to manage commodity price risk, partially offset by an unrealized gain of $3.4 million associated with a contract that includes contingent consideration. The net loss of $31.0 million on commodity derivative contracts included an unrealized loss of $29.6 million related to the change in fair value of our commodity derivative contracts and a realized loss of $1.4 million on settled commodity derivative contracts. During the three months ended March 31, 2023, we recorded a $66.9 million net gain on derivative instruments, which was primarily due to a net gain of $65.8 million associated with our contracts to manage commodity price risk that was comprised of an unrealized gain of $157.7 million related to the change in fair value of our commodity derivative contracts, partially offset by a realized loss of $91.9 million on settled commodity derivative contracts.

Investment in unconsolidated affiliate. We recorded a $16.3 million gain related to our investment in Energy Transfer for the three months ended March 31, 2024, which primarily included an unrealized gain of $14.0 million as a result of an increase in the fair value of the investment during the period, coupled with a gain of $2.3 million for a cash distribution received from Energy Transfer. During the three months ended March 31, 2023, we recorded a net loss of $2.2 million primarily due to a loss of $5.7 million as a result of a decrease in the fair value of the investment during the period, partially offset by a gain of $3.0 million for a cash distribution received from Energy Transfer.

Income tax expense. Our effective tax rate for the three months ended March 31, 2024 was recorded at 22.4% of pre-tax income as compared to 23.6% of pre-tax income for the three months ended March 31, 2023. The decrease in our effective tax rate period over period was primarily due to the impact of equity-based compensation windfalls.

Liquidity and Capital Resources

As of March 31, 2024, we had $1.3 billion of liquidity available, including $296.4 million in cash and cash equivalents and $991.1 million of aggregate unused borrowing capacity available under our Credit Facility (defined below). Our primary sources of liquidity are from cash on hand, cash flows from operations and available borrowing capacity under our Credit Facility. Our primary liquidity requirements are for capital expenditures for the development of oil and gas properties, dividend payments, share repurchases and working capital requirements.

Capital availability will be affected by prevailing conditions in our industry, the global economy, the global banking and financial markets, stakeholder scrutiny of ESG matters and other factors, many of which are beyond our control. The U.S. Federal Reserve’s increases in interest rates and the potential for such rates to increase further or to remain elevated for an extended period of time have created additional economic uncertainty. Although we are unable to predict future interest rates, this disruption to the broader economy and financial markets may reduce our ability to access capital or result in such capital being available on less favorable terms, which could in the future negatively affect our liquidity. We believe, however, we have adequate liquidity to fund our capital expenditures and meet our contractual obligations during the next 12 months and the foreseeable future.

Our cash flows depend on many factors, including the price of crude oil, NGLs and natural gas and the success of our development and exploration activities as well as future acquisitions. We actively manage our exposure to commodity price fluctuations by executing derivative transactions to mitigate the impact of changes in crude oil, NGL and natural gas prices on our production, which mitigates our exposure to crude oil, NGL and natural gas price declines; however, these transactions may also limit our cash flow in periods of rising crude oil, NGL and natural gas prices.

Commodity derivative contracts. As of March 31, 2024, our commodity derivative contracts cover 5,770 MBbls of our crude oil production for 2024, 3,552 MBbls of our crude oil production and 651,600 MMBtu of our natural gas production for 2025 and 270 MBbls of our crude oil production for 2026. See “Item 3. Quantitative and Qualitative Disclosures about Market Risk” for additional information.

33

In April 2024, we entered into new commodity derivative contracts to manage risks related to changes in crude oil prices. The following table summarizes these commodity derivative contracts:

			Volumes (Bbl)		Weighted Average Prices
Commodity	Settlement Period	Derivative Instrument	Total	Daily	Fixed-Price Swaps		Floor		Ceiling
Crude oil	2024	Two-way collars	736,000	2,676			$	75.00	$	88.15
Crude oil	2024	Fixed-price swaps	550,000	2,000	$	80.01

We also have contracts which include provisions for the delivery, transport or purchase of a minimum volume of crude oil, NGLs, natural gas and water within specified time frames, the majority of which are five years or less. Under the terms of these contracts, if we fail to deliver, transport or purchase the committed volumes we will be required to pay a deficiency payment for the volumes not tendered over the duration of the contract. We believe that for the substantial majority of these agreements our future production will be adequate to meet our delivery commitments or that we will be able to purchase sufficient volumes of crude oil, NGLs and natural gas from third parties to satisfy our minimum volume commitments. See “Item 1. Financial Statements (Unaudited)—Note 17—Commitments and Contingencies” for additional information on our volume delivery commitments.

Our material cash requirements from known obligations include repayment of outstanding borrowings and interest payment obligations related to our long-term debt, obligations to plug, abandon and remediate our oil and gas properties at the end of their productive lives, payment of income taxes, obligations associated with outstanding commodity derivative contracts that settle in a loss position, obligations to pay dividends on vested equity awards that include dividend equivalent rights and obligations associated with our leases. In addition, we have announced a return of capital plan pursuant to which we intend to return capital to stockholders through a mix of base and variable dividend payouts, supplemented by opportunistic share repurchases. There were no borrowings outstanding under the Credit Facility (defined below) as of March 31, 2024; however, on a quarterly basis, we pay a commitment fee on the average amount of borrowing base capacity not utilized during the quarter and fees calculated on the average amount of letter of credit balances outstanding during the quarter.

Merger-related costs. In connection with the Arrangement, we incurred certain costs for advisory, legal and other third-party fees which were recorded to G&A expenses on the Condensed Consolidated Statements of Operations. During the three months ended March 31, 2024, we incurred merger-related costs of $8.1 million primarily related to legal and advisory services.

Revolving credit facility. We have a senior secured revolving credit facility (the “Credit Facility”) with a borrowing base of $2.5 billion and elected commitments of $1.0 billion that is due July 1, 2027. As of March 31, 2024, we had no borrowings outstanding and $8.9 million of outstanding letters of credit, resulting in an unused borrowing capacity of $991.1 million. Additionally, we are permitted to incur term loans in addition to the revolving loans provided under the amended and restated credit agreement. We were in compliance with the financial covenants under the Credit Facility as of March 31, 2024. See “Item 1. Financial Statements (Unaudited)—Note 11—Long-Term Debt” for additional information.

We are expected to complete our semi-annual borrowing base redetermination in the second quarter of 2024.

Senior unsecured notes. As of March 31, 2024, we had $400.0 million of 6.375% senior unsecured notes outstanding (the “Senior Notes”) that mature on June 1, 2026. Interest on the Senior Notes is payable semi-annually on June 1 and December 1 of each year. See “Item 1. Financial Statements (Unaudited)—Note 11—Long-Term Debt” for additional information.

34

Cash Flows

Our cash flows for the three months ended March 31, 2024 and 2023 are presented below:

	Three Months Ended March 31,
	2024		2023
	(In thousands)
Net cash provided by operating activities	$	406,698	$	468,811
Net cash used in investing activities	(204,887)		(241,588)
Net cash used in financing activities	(223,455)		(228,074)
Decrease in cash and cash equivalents	$	(21,644)	$	(851)

Cash flows provided by operating activities

Our net cash flows from operating activities are primarily impacted by commodity prices, production volumes, operating costs and G&A expenses. Net cash provided by operating activities was $406.7 million for the three months ended March 31, 2024. The decrease in net cash provided by operating activities of $62.1 million as compared to the three months ended March 31, 2023 was primarily due to a decrease in oil, NGL and gas revenues and a decrease in our working capital as well as increases in LOE, GPT expenses and merger-related costs. See “Results of Operations” above for additional information.

Working Capital. Our working capital is primarily impacted due to the factors discussed above, coupled with the timing of cash receipts and disbursements. Changes in working capital (as reflected in the Condensed Consolidated Statements of Cash Flows) decreased net cash flows from operating activities by $9.8 million and $1.3 million during the three months ended March 31, 2024 and 2023, respectively. Changes in working capital associated with our capital expenditure activities and settlement of outstanding commodity derivative instruments impact our cash flows from investing activities.

The Credit Facility includes a requirement that we maintain a Current Ratio (as defined in the Credit Facility) of no less than 1.0 to 1.0 as of the last day of any fiscal quarter. For purposes of the Current Ratio, the Credit Facility’s definition of total current assets includes unused commitments under the Credit Facility, which were $991.1 million as of March 31, 2024, and excludes current hedge assets, which were $26.5 million as of March 31, 2024. For purposes of the Current Ratio, the Credit Facility’s definition of total current liabilities excludes current hedge liabilities, which were $19.5 million as of March 31, 2024.

Cash flows used in investing activities

Net cash used in investing activities was $204.9 million for the three months ended March 31, 2024. The decrease in net cash used in investing activities of $36.7 million as compared to the three months ended March 31, 2023 was primarily due to a decrease of $79.6 million used to settle outstanding commodity derivative contracts and the receipt of the 2023 contingent consideration earn-out payment of $25.0 million in the first quarter of 2024. The decrease was partially offset by an increase of $49.8 million of capital expenditures incurred to develop our oil and gas properties during the three months ended March 31, 2024 as compared to the three months ended March 31, 2023.

Cash flows used in financing activities

For the three months ended March 31, 2024, net cash used in financing activities of $223.5 million was primarily attributable to dividends paid to shareholders of $152.4 million, income tax withholdings on vested equity-based compensation awards of $46.1 million and payments of $32.0 million to repurchase our common stock, partially offset by proceeds of $7.4 million from the exercise of outstanding warrants. Net cash used in financing activities for the three months ended March 31, 2023 of $228.1 million was primarily attributable to dividends paid to shareholders of $202.5 million, payments of $15.0 million to repurchase our common stock and payments of $10.3 million for income tax withholdings on vested equity-based compensation awards.

35

Capital Expenditures

Expenditures for the acquisition and development of oil and gas properties are the primary use of our capital resources. Our capital expenditures are summarized in the following table:

	Three Months Ended
	March 31, 2024
	(In thousands)
E&P	$	257,712
Other capital expenditures(1)	745
Total capital expenditures(2)(3)	$	258,457

(1)Other capital expenditures includes items such as infrastructure capital, administrative capital and capitalized interest. Capitalized interest totaled $0.7 million for the three months ended March 31, 2024.

(2)Total capital expenditures for the three months ended March 31, 2024 includes approximately $3.9 million related to non-operated divested assets that are expected to be reimbursed.

(3)Total capital expenditures reflected in the table above differs from the amounts shown in the statements of cash flows in our unaudited condensed consolidated financial statements because amounts reflected in the table include changes in accrued liabilities from the previous reporting period for capital expenditures, while the amounts presented in the statements of cash flows are presented on a cash basis.

Dividends

On May 7, 2024, we declared a base-plus-variable cash dividend of $2.94 per share of common stock. The dividend will be payable on June 5, 2024 to shareholders of record as of May 22, 2024. See “Item 1. Financial Statements (Unaudited)—Note 15—Stockholders’ Equity” for additional information.

See “Part II. Item 7.—Management’s Discussion and Analysis of Financial Condition and Results of Operations—Recent Developments—Return of Capital Plan” in our 2023 Annual Report for additional information regarding our strategy on future dividend payments. Future dividend payments will depend on the Company’s earnings, financial condition, capital requirements, level of indebtedness, statutory and contractual restrictions applicable to the payment of dividends and other considerations that the Board of Directors deems relevant.

Share Repurchase Program

During the three months ended March 31, 2024, we repurchased 193,269 shares of common stock at a weighted average price of $155.20 per common share for a total cost of $30.0 million, under our $750 million share repurchase program. As of March 31, 2024, there was $653.0 million of capacity remaining under our $750 million share repurchase program.

We repurchased 110,667 shares of common stock during the three months ended March 31, 2023 under the previous share repurchase program, which was replaced by our current $750 million share repurchase program.

Fair Value of Financial Instruments

See “Item 1. Financial Statements (Unaudited)—Note 5—Fair Value Measurements” for additional information on our derivative instruments and their related fair value measurements. See also “Item 3. Quantitative and Qualitative Disclosures about Market Risk” below.

Critical Accounting Policies and Estimates

There have been no material changes in our critical accounting policies and estimates from those disclosed in our 2023 Annual Report.

36

Item 3. — Quantitative and Qualitative Disclosures about Market Risk

We are exposed to a variety of market risks, including commodity price risk, interest rate risk, counterparty and customer risk and inflation risk. We address these risks through a program of risk management, including the use of derivative instruments.

The primary objective of the following information is to provide forward-looking quantitative and qualitative information about our potential exposure to market risk. The term “market risk” refers to the risk of loss arising from adverse changes in crude oil, NGL and natural gas prices and interest rates. The disclosures are not meant to be precise indicators of expected future losses, but rather indicators of reasonably possible losses. This forward-looking information provides indicators of how we view and manage our ongoing market risk exposures. All of our market risk derivative instruments were entered into for hedging purposes, rather than for speculative trading. The following market risk disclosures should be read in conjunction with the quantitative and qualitative disclosures about market risk contained in our 2023 Annual Report, as well as with the unaudited condensed consolidated financial statements and notes thereto included in this Quarterly Report on Form 10-Q.

Commodity price exposure risk. We are exposed to market risk as the prices of crude oil, NGLs and natural gas fluctuate as a result of a variety of factors, including changes in supply and demand and the macroeconomic environment, all of which are typically beyond our control. The markets for crude oil, NGLs and natural gas have been volatile, especially over the last several years, and these prices will likely continue to be volatile in the future. To partially reduce price risk caused by these market fluctuations, we have entered into derivative instruments in the past and expect to enter into derivative instruments in the future to cover a portion of our future production. In addition, entering into derivative instruments could limit the benefit we would receive from increases in the prices for crude oil, NGLs and natural gas. We recognize all derivative instruments at fair value. The credit standing of our counterparties is analyzed and factored into the fair value amounts recognized on our unaudited condensed consolidated balance sheets. Derivative assets and liabilities arising from our derivative contracts with the same counterparty are also reported on a net basis, as all counterparty contracts provide for net settlement. See “Item 1. Financial Statements (Unaudited)—Note 5—Fair Value Measurements” and “Note 6—Derivative Instruments” for additional information regarding our derivative instruments.

The fair value of our unrealized crude oil derivative positions at March 31, 2024 was a net liability position of $22.0 million. A 10% increase in crude oil prices would increase the fair value of this unrealized derivative liability position by approximately $47.1 million, while a 10% decrease in crude oil prices would decrease the fair value of this unrealized derivative liability position by approximately $39.3 million. The fair value of our unrealized natural gas derivative positions at March 31, 2024 was a net asset position of $0.4 million. A 10% increase in natural gas prices would decrease the fair value of this unrealized derivative asset position by approximately $0.2 million, while a 10% decrease in natural gas prices would increase the fair value of this unrealized derivative asset position by approximately $0.2 million. See “Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations—Market Conditions and Commodity Prices,” for further discussion on the commodity price environment. See “Item 1. Financial Statements (Unaudited)—Note 6—Derivative Instruments” for additional information regarding our derivative instruments.

In addition, in connection with the 2021 divestiture of oil and gas properties in the Texas region of in the Permian Basin, we are entitled to receive up to three earn-out payments of $25.0 million per year for each of 2023, 2024 and 2025 if the average daily settlement price of NYMEX WTI crude oil exceeds $60 per barrel for such year. If the NYMEX WTI crude oil price for calendar year 2023 or 2024 is less than $45 per barrel, then each calendar year thereafter our right to receive any remaining earn-out payments is terminated. As of March 31, 2024, the fair value of this contingent consideration was $46.1 million. During the three months ended March 31, 2024, we received $25.0 million related to the 2023 earn-out payment. See “Item 1. Financial Statements (Unaudited)—Note 6—Derivative Instruments” for additional information.

Interest rate risk. At March 31, 2024, we had $400.0 million of senior unsecured notes at a fixed interest rate of 6.375% per annum. At March 31, 2024, we had no borrowings and $8.9 million of outstanding letters of credit issued under the Credit Facility. Borrowings under the Credit Facility are subject to varying rates of interest based on (i) the total outstanding borrowings (including the value of all outstanding letters of credit) in relation to the borrowing base and (ii) whether the loan is a Term SOFR Loan or an ABR Loan (each as defined in the amended and restated credit agreement). See “Item 1. Financial Statements (Unaudited)—Note 11—Long-Term Debt” for additional information on the interest incurred on the Credit Facility.

We do not currently, but may in the future, utilize interest rate derivatives to mitigate interest rate exposure in an attempt to reduce interest rate expense related to debt issued under the Credit Facility. Interest rate derivatives would be used solely to modify interest rate exposure and not to modify the overall leverage of the debt portfolio.

37

Counterparty and customer credit risk. Joint interest receivables arise from billing entities which own partial interest in the wells we operate. These entities participate in our wells primarily based on their ownership in leases on which we choose to drill. We have limited ability to control participation in our wells. For the three months ended March 31, 2024, our credit losses on joint interest receivables were immaterial. We are also subject to credit risk due to the concentration of our crude oil, NGL and natural gas receivables with several significant customers. The inability or failure of our significant customers to meet their obligations to us, or their insolvency or liquidation, may adversely affect our financial position and related financial results.

We monitor our exposure to counterparties on crude oil, NGL and natural gas 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, NGL and natural gas sales receivables owed to us. Historically, our credit losses on crude oil, NGL and natural gas sales receivables have been immaterial.

In addition, our crude oil, NGL and natural gas derivative arrangements expose us to credit risk in the event of nonperformance by counterparties. However, in order to mitigate the risk of nonperformance, we only enter into derivative contracts with counterparties that are high credit-quality financial institutions. All of the counterparties on our derivative instruments currently in place are lenders under the Credit Facility with investment grade ratings. We are likely to enter into any future derivative instruments with these or other lenders under the Credit Facility, which also carry investment grade ratings. This risk is also managed by spreading our derivative exposure across several institutions and limiting the volumes placed under individual contracts. Furthermore, the agreements with each of the counterparties on our derivative instruments contain netting provisions. As a result of these netting provisions, our maximum amount of loss due to credit risk is limited to the net amounts due to and from the counterparties under the derivative contracts.

Item 4. — Controls and Procedures

Evaluation of disclosure controls and procedures

As required by Rule 13a-15(b) of the Exchange Act, management, under the supervision and with the participation of our Chief Executive Officer (“CEO”), our principal executive officer, and our Chief Financial Officer (“CFO”), our principal financial officer, has evaluated the effectiveness of the design and operation of our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Exchange Act) as of March 31, 2024. Our disclosure controls and procedures are designed to provide reasonable assurance that information required to be disclosed by us in the reports filed or submitted by us under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms, and that such information is accumulated and communicated to our management, including our CEO and CFO as appropriate, to allow timely decisions regarding required disclosure. Based on the evaluation, our CEO and CFO concluded that our disclosure controls and procedures were effective as of March 31, 2024.

Changes in internal control over financial reporting

There were no changes in internal control over financial reporting that occurred during the quarter ended March 31, 2024 that have materially affected, or are reasonably likely to have a material effect on, our internal control over financial reporting.

38

PART II — OTHER INFORMATION

Item 1. — Legal Proceedings

See “Part I, Item 1. — Financial Statements (Unaudited)—Note 17—Commitments and Contingencies,” which is incorporated herein by reference, for a discussion of material legal proceedings.

Item 1A. — Risk Factors

Our business faces many risks. Any of the risks discussed elsewhere in this Form 10-Q and our other SEC filings could have a material impact on our business, financial position, results of operations or cash flows. Additional risks and uncertainties not presently known to us or that we currently believe to be immaterial may also impair our business operations.

For a discussion of our potential risks and uncertainties, see the information in “Part I. Item 1A. Risk Factors” in our 2023 Annual Report. There have been no material changes in our risk factors from those described in our 2023 Annual Report, except as described below.

The SEC’s Final Rules on The Enhancement and Standardization of Climate-Related Disclosures could result in increased compliance risks and costs.

The SEC released its final rule on climate-related disclosures on March 6, 2024, requiring the disclosure of certain climate-related risks, management and governance practices, and financial impacts, as well as greenhouse gas emissions. Large accelerated filers will be required to incorporate the applicable climate-related disclosures into their filings beginning in fiscal year 2025, with additional requirements relating to the disclosure of Scope 1 and 2 greenhouse gas emissions, if material, and attestation reports for certain large accelerated filers subsequently phasing in. Refer to “Item 1. Business—Regulation—Environmental and occupational health and safety regulation” in our 2023 Annual Report for prior discussion of the SEC’s then-proposed rule. While we are still assessing our obligations under the rule, complying with such obligations may result in increased costs and SEC or investor scrutiny of our disclosures. The SEC has paused implementation of the final rule pending the resolution of consolidated legal challenges that are currently proceeding before the U.S. Court of Appeals for the Eighth Circuit. The outcome of this litigation may reduce or expand our obligations under the final rule.

39

Item 2. — Unregistered Sales of Equity Securities and Use of Proceeds

Unregistered sales of equity securities. There were no sales of unregistered equity securities during the period covered by this report.

Issuer purchases of equity securities. The following table contains information about our acquisition of equity securities during the three months ended March 31, 2024:

Period	Total Number of Shares Exchanged(1)(2)	Average Price Paid per Share		Total Number of Shares Purchased as Part of Publicly Announced Plans or Programs(2)	Maximum Number (or Approximate Dollar Value) of Shares that May Be Purchased Under the Plans or Programs(2)(3)
January 1 – January 31, 2024	445,587	$	156.75	193,269	$	653,007,171
February 1 – February 29, 2024	27,269	160.76		—	653,007,171
March 1 – March 31, 2024	—	—		—	653,007,171
Total	472,856	$	156.98	193,269

___________________ 

(1)During the first quarter of 2024, we withheld 279,587 shares of common stock to satisfy tax withholding obligations upon vesting of certain equity-based awards.

(2)During the first quarter of 2024, we repurchased 193,269 shares of our common stock at a weighted average price of $155.20 per common share for a total cost of $30.0 million under our publicly announced share repurchase program.

(3)In October 2023, our Board of Directors authorized a share repurchase program of up to $750 million of our common stock.

Item 5. — Other Information

Rule 10b5-1 trading arrangements. During the fiscal quarter ended March 31, 2024, none of our directors or officers (as defined in Rule 16a-1 under the Exchange Act) adopted or terminated a “Rule 10b5-1 trading arrangement” or “non-Rule 10b5-1 trading arrangement,” as each term is defined in Item 408 of Regulation S-K.

tem 6. — Exhibits

Exhibit No.	Description of Exhibit
2.1	Arrangement Agreement, dated as of February 21, 2024, by and among Chord Energy Corporation, Spark Acquisition ULC and Enerplus Corporation (filed as Exhibit 2.1 to the Company’s Current Report on Form 8-K on February 26, 2024, and incorporated herein by reference).
10.1	Chord Energy Corporation Executive Severance Plan (filed as Exhibit 10.25 to the Company’s Annual Report on Form 10-K on February 26, 2024, and incorporated herein by reference).
10.2	Form of Performance Share Unit Agreement (Relative TSR) (filed as Exhibit 10.26 to the Company’s Annual Report on Form 10-K on February 26, 2024, and incorporated herein by reference).
10.3	Form of Performance Share Unit Agreement (Absolute TSR) (filed as Exhibit 10.27 to the Company’s Annual Report on Form 10-K on February 26, 2024, and incorporated herein by reference).
10.4	Letter Agreement, dated as of February 21, 2024, between Chord Energy Corporation and Ian C. Dundas (filed as Exhibit 10.1 to the Company’s Current Report on Form 8-K on February 26, 2024, and incorporated herein by reference).
31.1(a)	Sarbanes-Oxley Section 302 certification of Principal Executive Officer.
31.2(a)	Sarbanes-Oxley Section 302 certification of Principal Financial Officer.
32.1(b)	Sarbanes-Oxley Section 906 certification of Principal Executive Officer.
32.2(b)	Sarbanes-Oxley Section 906 certification of Principal Financial Officer.
101.INS(a)	XBRL Instance Document - the instance document does not appear in the Interactive Data File because its XBRL tags are embedded within the Inline XBRL document.
101.SCH(a)	XBRL Schema Document.
101.CAL(a)	XBRL Calculation Linkbase Document.
101.DEF(a)	XBRL Definition Linkbase Document.

40

101.LAB(a)	XBRL Label Linkbase Document.
101.PRE(a)	XBRL Presentation Linkbase Document.
104(a)	Cover Page Interactive Data File - the cover page interactive data file does not appear in the Interactive Data File because its XBRL tags are embedded within the Inline XBRL document.

___________________

(a)Filed herewith.

(b)Furnished herewith.

41

SIGNATURES

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.

			CHORD ENERGY CORPORATION
Date:	May 9, 2024	By:	/s/ Daniel E. Brown
			Daniel E. Brown
			President and Chief Executive Officer (Principal Executive Officer)

By:	/s/ Richard N. Robuck
	Richard N. Robuck
	Executive Vice President and Chief Financial Officer (Principal Financial Officer and Principal Accounting Officer)

42