Chord Energy (NASDAQ: CHRD) grows Q1 2026 revenue as hedge losses cut profit
Filing Impact
Filing Sentiment
Form Type
10-Q
Rhea-AI Filing Summary
Chord Energy Corporation reported lower profit for Q1 2026 despite higher commodity prices and volumes. Total revenues rose to $1.67 billion, driven by stronger crude oil, NGL and gas pricing and a sharp increase in purchased oil and gas sales. Net income fell to $108.6 million from $219.8 million a year earlier, mainly due to a $241.5 million net loss on commodity derivatives.
Production averaged 275,615 Boepd (57% oil), with crude oil volumes of 158,027 Bopd. Operating cash flow remained strong at $507.5 million, funding $344.9 million of capital spending, a $1.30 per share base dividend and $70.7 million of share repurchases under a $1.0 billion buyback program.
Positive
- None.
Negative
- None.
Insights
Chord grew revenue and cash flow in Q1 2026, but derivative losses cut earnings roughly in half year over year.
Chord Energy benefited from higher oil, NGL and gas prices and slightly higher production, lifting Q1 2026 revenues to $1.67 billion. Average production reached 275,615 Boepd, with crude oil at 158,027 Bopd, underscoring the scale of its Williston Basin-focused portfolio.
Earnings were pressured by a large non-cash mark-to-market on hedges. A net loss on derivative instruments of $241.5 million drove net income down to $108.6 million, even as operating income stayed above $333 million. The quarter also included a $41.8 million out-of-period tax benefit that lowered the effective tax rate.
From a balance sheet and capital return standpoint, leverage remained modest with long-term debt of about $1.48 billion and no revolver borrowings. Strong operating cash flow of $507.5 million funded $344.9 million of capital expenditures, a base dividend of $1.30 per share and $70.7 million of buybacks, while leaving cash at $225.8 million as of March 31 2026.
Key Figures
Total revenues: $1,665.6M
Net income: $108.6M
Net loss on derivative instruments: $241.5M
+5 more
8 metrics
Total revenues
$1,665.6M
Three months ended March 31, 2026
Net income
$108.6M
Three months ended March 31, 2026
Net loss on derivative instruments
$241.5M
Three months ended March 31, 2026
Net cash from operating activities
$507.5M
Three months ended March 31, 2026
Capital expenditures
$344.9M
Three months ended March 31, 2026
Average production
275,615 Boepd
Three months ended March 31, 2026
Dividend per share
$1.30
Base cash dividend for Q1 2026
Share repurchases
$70.7M
Cost of 559,064 shares in Q1 2026, excl. excise tax
Key Terms
Barrels of oil equivalent (Boe), Asset retirement obligations, Three-way collar, Net loss on derivative instruments, +2 more
6 terms
Barrels of oil equivalent (Boe) financial
"Boe. Barrels of oil equivalent, with 6,000 cubic feet of natural gas being equivalent to one barrel of crude oil."
A barrel of oil equivalent (boe) is a single unit that combines different types of energy production—mainly crude oil and natural gas—by converting them into the same energy value so they can be compared and totaled. Think of it as turning apples and oranges into pieces of fruit so you can count them together; investors use boe to compare production, reserves and revenue potential across companies and projects on a like-for-like basis.
Asset retirement obligations financial
"“ARO.” Asset retirement obligations."
Asset retirement obligations are a company’s recorded promise to pay for dismantling, cleaning up, or restoring property when a long-lived asset is retired — for example decommissioning a plant or removing equipment. Companies estimate the future cleanup cost today and book it as a liability (and add the cost to the asset), so it affects the balance sheet, reported profits over time, and future cash needs; investors watch it like a planned bill that can reduce cash available for returns.
Three-way collar financial
"Crude oil | 2026 | Three-way collar | 3,527,000 | Bbls"
Net loss on derivative instruments financial
"Net loss on derivative instruments | ( 241,471 )"
Effective tax rate financial
"The Company’s effective tax rate was (15.2)% for the three months ended March 31, 2026"
The effective tax rate is the percentage of a company's profits that it pays in taxes. It shows how much of its earnings go to taxes after all deductions and credits are considered. For investors, it indicates how much of the company's income is taken by taxes, impacting overall profitability and financial health.
Earnings Snapshot
Total revenues: $1,665.6M
Q1 2026
Total revenues
$1,665.6M
higher than Q1 2025
Net income
$108.6M
lower than Q1 2025
Diluted EPS
$1.90
lower than Q1 2025
Net cash from operating activities
$507.5M
below Q1 2025 level
Table of Contents
UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM | ||
| QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 | |||||
For the quarterly period ended March 31, 2026
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
(Exact name of registrant as specified in its charter) | ||
| (State or other jurisdiction of incorporation or organization) | (I.R.S. Employer Identification No.) | |||||||
| (Address of principal executive offices) | (Zip Code) | |||||||
( (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 | ||||||||||||
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.
☒ | 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 4, 2026: 56,299,183 shares.
Table of Contents
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, 2026 and December 31, 2025 | 4 | ||||
Condensed Consolidated Statements of Operations for the Three Months Ended March 31, 2026 and 2025 | 6 | ||||
Condensed Consolidated Statements of Changes in Stockholders’ Equity for the Three Months Ended March 31, 2026 and 2025 | 7 | ||||
Condensed Consolidated Statements of Cash Flows for the Three Months Ended March 31, 2026 and 2025 | 8 | ||||
Notes to Condensed Consolidated Financial Statements | 10 | ||||
1. Organization and Summary of Significant Accounting Policies | 10 | ||||
2. Revenue Recognition | 11 | ||||
3. Inventory | 12 | ||||
4. Additional Balance Sheet Information | 12 | ||||
5. Fair Value Measurements | 13 | ||||
6. Derivative Instruments | 14 | ||||
7. Property, Plant and Equipment | 16 | ||||
8. Acquisitions | 17 | ||||
9. Investment in Equity Securities | 18 | ||||
10. Long-Term Debt | 18 | ||||
11. Asset Retirement Obligations | 19 | ||||
12. Income Taxes | 19 | ||||
13. Equity-Based Compensation | 20 | ||||
14. Stockholders’ Equity | 21 | ||||
15. Earnings Per Share | 22 | ||||
16. Commitments and Contingencies | 22 | ||||
17. Leases | 23 | ||||
Item 2. — Management’s Discussion and Analysis of Financial Condition and Results of Operations | 24 | ||||
Overview | 26 | ||||
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 | 36 | ||||
Item 4. — Controls and Procedures | 37 | ||||
PART II — OTHER INFORMATION | 38 | ||||
Item 1. — Legal Proceedings | 38 | ||||
Item 1A. — Risk Factors | 38 | ||||
Item 2. — Unregistered Sales of Equity Securities and Use of Proceeds | 38 | ||||
Item 5.— Other Information | 38 | ||||
Item 6. — Exhibits | 39 | ||||
SIGNATURES | 40 | ||||
GLOSSARY OF TERMS
The terms defined in this section are used throughout this Quarterly Report on Form 10-Q:
“ABR.” Alternate base rate.
“ARO.” Asset retirement obligations.
“ASC.” Accounting Standards Codification.
“ASU.” Accounting Standards Update.
“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.
“Bopd.” Barrels of oil 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 crude oil or natural gas, or in the case of a dry hole, the reporting of abandonment to the appropriate agency.
“DD&A.” Depreciation, depletion and amortization.
“Dry hole.” A well found to be incapable of producing hydrocarbons in sufficient quantities such that proceeds from the sale of such production would 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.
“FASB.” Financial Accounting Standards Board.
“Formation.” A layer of rock which has distinct characteristics that differ from nearby rock.
“G&A.” General and administrative.
“GAAP.” Generally accepted accounting principles in the United States.
“GPT.” Gathering, processing and transportation.
“ICE BRENT.” The Intercontinental Exchange Brent crude oil price index.
“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.
“NGL.” Natural gas liquids.
“NYMEX.” The New York Mercantile Exchange.
“NYMEX WTI.” The New York Mercantile Exchange West Texas Intermediate crude oil price index.
“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 would exceed production expenses and taxes.
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“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.
“SOFR.” Secured overnight financing rate as administered by the Federal Reserve Bank of New York.
“Workover.” The repair or stimulation of an existing productive well for the purpose of restoring, prolonging or enhancing the production of hydrocarbons.
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PART I — FINANCIAL INFORMATION
Item 1. — Financial Statements (Unaudited)
Chord Energy Corporation
Condensed Consolidated Balance Sheets (Unaudited)
| March 31, 2026 | December 31, 2025 | ||||||||||
| (In thousands, except share data) | |||||||||||
| ASSETS | |||||||||||
| Current assets | |||||||||||
| Cash and cash equivalents | $ | $ | |||||||||
| Accounts receivable, net | |||||||||||
| Inventory | |||||||||||
| Prepaid expenses | |||||||||||
| Derivative instruments | |||||||||||
| Other current assets | |||||||||||
| Total current assets | |||||||||||
| Property, plant and equipment | |||||||||||
| Oil and gas properties (successful efforts method) | |||||||||||
| Other property and equipment | |||||||||||
| Less: accumulated depreciation, depletion and amortization | ( | ( | |||||||||
| Total property, plant and equipment, net | |||||||||||
| Derivative instruments | |||||||||||
| Investment in equity securities | |||||||||||
| Long-term inventory | |||||||||||
| Operating right-of-use assets | |||||||||||
| Other assets | |||||||||||
| Total assets | $ | $ | |||||||||
| LIABILITIES AND STOCKHOLDERS’ EQUITY | |||||||||||
| Current liabilities | |||||||||||
| Accounts payable | $ | $ | |||||||||
| Revenues and production taxes payable | |||||||||||
| Accrued liabilities | |||||||||||
| Accrued interest payable | |||||||||||
| Derivative instruments | |||||||||||
| Current operating lease liabilities | |||||||||||
| Other current liabilities | |||||||||||
| Total current liabilities | |||||||||||
| Long-term debt | |||||||||||
| Deferred tax liabilities | |||||||||||
| Asset retirement obligations | |||||||||||
| Derivative instruments | |||||||||||
| Operating lease liabilities | |||||||||||
| Other liabilities | |||||||||||
| Total liabilities | |||||||||||
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| March 31, 2026 | December 31, 2025 | ||||||||||
| (In thousands, except share data) | |||||||||||
Commitments and contingencies (Note 16) | |||||||||||
| Stockholders’ equity | |||||||||||
Common stock, $ | |||||||||||
Treasury stock, at cost: | ( | ( | |||||||||
| Additional paid-in capital | |||||||||||
| Retained earnings | |||||||||||
| Total stockholders’ equity | |||||||||||
| Total liabilities and stockholders’ equity | $ | $ | |||||||||
The accompanying notes are an integral part of these condensed consolidated financial statements.
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Chord Energy Corporation
Condensed Consolidated Statements of Operations (Unaudited)
| Three Months Ended March 31, | |||||||||||
| 2026 | 2025 | ||||||||||
| (In thousands, except per share data) | |||||||||||
| Revenues | |||||||||||
| Oil, NGL and gas revenues | $ | $ | |||||||||
| Purchased oil and gas sales | |||||||||||
| Total revenues | |||||||||||
| Operating expenses | |||||||||||
| Lease operating expenses | |||||||||||
| Gathering, processing and transportation expenses | |||||||||||
| Purchased oil and gas expenses | |||||||||||
| Production taxes | |||||||||||
| Depreciation, depletion and amortization | |||||||||||
| General and administrative expenses | |||||||||||
| Exploration and impairment | |||||||||||
| Total operating expenses | |||||||||||
| Gain on sale of assets, net | |||||||||||
| Operating income | |||||||||||
| Other income (expense) | |||||||||||
| Net loss on derivative instruments | ( | ( | |||||||||
| Net gain (loss) from investment in equity securities | ( | ||||||||||
| Interest expense, net of capitalized interest | ( | ( | |||||||||
| Loss on debt extinguishment | ( | ||||||||||
| Other income (expense), net | ( | ||||||||||
| Total other expense, net | ( | ( | |||||||||
| Income before income taxes | |||||||||||
| Income tax benefit (expense) | ( | ||||||||||
Net income | $ | $ | |||||||||
Earnings per share (Note 15): | |||||||||||
Basic | $ | $ | |||||||||
Diluted | $ | $ | |||||||||
| Weighted average shares outstanding: | |||||||||||
Basic | |||||||||||
Diluted | |||||||||||
The accompanying notes are an integral part of these condensed consolidated financial statements.
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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, 2025 | $ | $ | ( | $ | $ | $ | |||||||||||||||||||||||||||||||||||
| Equity-based compensation and vestings | — | — | — | ||||||||||||||||||||||||||||||||||||||
| Tax withholdings on settlement of equity-based awards | ( | — | — | — | ( | — | ( | ||||||||||||||||||||||||||||||||||
Dividends | — | — | — | — | — | ( | ( | ||||||||||||||||||||||||||||||||||
| Share repurchases | ( | — | ( | — | — | ( | |||||||||||||||||||||||||||||||||||
| Net income | — | — | — | — | — | ||||||||||||||||||||||||||||||||||||
| Balance as of March 31, 2026 | $ | $ | ( | $ | $ | $ | |||||||||||||||||||||||||||||||||||
| Common Stock | Treasury Stock | Additional Paid-in Capital | Retained Earnings | Total Stockholders’ Equity | |||||||||||||||||||||||||||||||||||||
| Shares | Amount | Shares | Amount | ||||||||||||||||||||||||||||||||||||||
| (In thousands) | |||||||||||||||||||||||||||||||||||||||||
| Balance as of December 31, 2024 | $ | $ | ( | $ | $ | $ | |||||||||||||||||||||||||||||||||||
| Equity-based compensation and vestings | — | — | — | ||||||||||||||||||||||||||||||||||||||
| Tax withholdings on settlement of equity-based awards | ( | ( | — | — | ( | — | ( | ||||||||||||||||||||||||||||||||||
| Dividends | — | — | — | — | — | ( | ( | ||||||||||||||||||||||||||||||||||
| Share repurchases | ( | — | ( | — | — | ( | |||||||||||||||||||||||||||||||||||
| Net income | — | — | — | — | — | ||||||||||||||||||||||||||||||||||||
| Balance as of March 31, 2025 | $ | $ | ( | $ | $ | $ | |||||||||||||||||||||||||||||||||||
The accompanying notes are an integral part of these condensed consolidated financial statements.
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Chord Energy Corporation
Condensed Consolidated Statements of Cash Flows (Unaudited)
| Three Months Ended March 31, | |||||||||||
| 2026 | 2025 | ||||||||||
| (In thousands) | |||||||||||
| Cash flows from operating activities: | |||||||||||
| Net income | $ | $ | |||||||||
| Adjustments to reconcile net income to net cash provided by operating activities: | |||||||||||
| Depreciation, depletion and amortization | |||||||||||
| Loss on debt extinguishment | |||||||||||
| Gain on sale of assets | ( | ( | |||||||||
| Deferred income taxes | ( | ||||||||||
| Net loss on derivative instruments | |||||||||||
| Net (gain) loss from investment in equity securities | ( | ||||||||||
| Equity-based compensation expenses | |||||||||||
| Settlement of asset retirement obligations | ( | ( | |||||||||
| Deferred financing costs amortization and other | ( | ( | |||||||||
| Working capital and other changes: | |||||||||||
| Change in accounts receivable, net | ( | ( | |||||||||
| Change in inventory | ( | ||||||||||
| Change in prepaid expenses | |||||||||||
| Change in accounts payable, interest payable and accrued liabilities | |||||||||||
| Change in other assets and liabilities, net | ( | ||||||||||
Net cash provided by operating activities | |||||||||||
| Cash flows from investing activities: | |||||||||||
| Capital expenditures | ( | ( | |||||||||
| Acquisitions | ( | ( | |||||||||
| Proceeds from divestitures | |||||||||||
| Derivative settlements | |||||||||||
| Contingent consideration received | |||||||||||
| Distributions from investment in equity securities | |||||||||||
Net cash used in investing activities | ( | ( | |||||||||
| Cash flows from financing activities: | |||||||||||
| Proceeds from revolving credit facility | |||||||||||
| Principal payments on revolving credit facility | ( | ( | |||||||||
| Repayment and discharge of senior notes | ( | ||||||||||
| Issuance of senior notes | |||||||||||
| Deferred financing costs | ( | ||||||||||
| Repurchases of common stock | ( | ( | |||||||||
| Tax withholding on vesting of equity-based awards | ( | ( | |||||||||
| Dividends paid | ( | ( | |||||||||
| Payments on finance lease liabilities | ( | ( | |||||||||
Net cash used in financing activities | ( | ( | |||||||||
Increase (decrease) in cash and cash equivalents | ( | ||||||||||
| Cash and cash equivalents: | |||||||||||
| Beginning of period | |||||||||||
| End of period | $ | $ | |||||||||
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| Three Months Ended March 31, | |||||||||||
| 2026 | 2025 | ||||||||||
| (In thousands) | |||||||||||
| Supplemental non-cash transactions: | |||||||||||
| Change in accrued capital expenditures | $ | ( | $ | ||||||||
| Change in asset retirement obligations | |||||||||||
| Change in dividends payable | |||||||||||
The accompanying notes are an integral part of these condensed consolidated financial statements.
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Chord Energy Corporation
Notes to Condensed Consolidated Financial Statements (Unaudited)
1. Organization and Summary of Significant Accounting Policies
Chord Energy Corporation, a Delaware corporation (together with its consolidated subsidiaries, the “Company” or “Chord”), is an independent exploration and production (“E&P”) company engaged in the acquisition, exploration, development and production of crude oil, NGL and natural gas primarily in the Williston Basin with limited non-operated interests in the Marcellus Shale.
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, 2025 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.
Risks and Uncertainties
As a producer of crude oil, NGL and natural gas, the Company’s revenue, profitability and future growth are substantially dependent upon the prevailing and future prices for crude oil, NGL and natural gas, which are cyclical and dependent upon numerous factors beyond the Company’s control such as economic, geopolitical, political and regulatory developments and competition from other energy sources. Energy markets experienced significant volatility during the first quarter of 2026, driven primarily by geopolitical tensions and the resulting disruptions to global oil supply. Following the escalation of conflict in the Middle East in late February, the NYMEX WTI spot price increased more than 50% by the end of the first quarter. Continued geopolitical tensions, uncertainty around OPEC+ production policy and the potential economic outcomes of tariff and trade policy decisions of the U.S. or other governments create difficulty in predicting future impacts to commodity prices, which could affect the Company’s financial position, results of operations, cash flows, capital and operating costs, and the quantities of crude oil, NGL and natural gas reserves that may be economically produced.
Out-of-Period Adjustment
During the three months ended March 31, 2026, the Company recorded an out-of-period tax benefit in the amount of $41.8
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Significant Accounting Policies
There have been no material changes to the Company’s significant accounting policies and estimates from those disclosed in the 2025 Annual Report.
Recent Accounting Pronouncements
In November 2024, the FASB issued ASU No. 2024-03, “Income Statement—Reporting Comprehensive Income—Expense Disaggregation Disclosures (Subtopic 220-40): Disaggregation of Income Statement Expenses” (“ASU 2024-03”). This standard requires that public business entities disclose additional information about specific expense categories in the notes to financial statements at interim and annual reporting periods. This ASU is effective for annual reporting periods beginning after December 15, 2026, and interim periods within annual reporting periods beginning after December 15, 2027, with early adoption permitted. The Company is currently evaluating this ASU to determine its impact on the Company’s financial statement disclosures.
In July 2025, the FASB issued ASU 2025-05, Financial Instruments—Credit Losses (Topic 326): Measurement of Credit Losses for Accounts Receivable and Contract Assets (“ASU 2025-05”). This standard amends the guidance for measuring expected credit losses on accounts receivable and contract assets. The amendments are intended to clarify the application of the current expected credit loss model to short-term receivables and contract assets, and to provide additional guidance on the use of historical loss information and forecasts in estimating expected credit losses. ASU 2025-05 is effective for annual and interim reporting periods beginning after December 15, 2025, with early adoption permitted. The Company adopted this ASU effective January 1, 2026, and the adoption did not have a material impact on the Company’s consolidated financial statements.
In December 2025, the FASB issued ASU 2025-10, Government Grants (Topic 832): Accounting for Government Grants Received by Business Entities (“ASU 2025-10”). This standard establishes guidance for how a business entity accounts for government grants, distinguishing between grants related to assets and grants related to income. The standard also requires enhanced disclosures regarding the nature, terms, and amounts of government grants recognized in the financial statements. ASU 2025-10 is effective for annual and interim reporting periods beginning after December 15, 2026, with early adoption permitted. The Company is currently evaluating this ASU to determine its impact on the Company’s consolidated financial statements.
2. Revenue Recognition
Revenues from contracts with customers were as follows for the periods presented:
| Three Months Ended March 31, | |||||||||||
| 2026 | 2025 | ||||||||||
| (In thousands) | |||||||||||
| Crude oil revenues | $ | $ | |||||||||
| Purchased crude oil sales | |||||||||||
| NGL and natural gas revenues | |||||||||||
| Purchased natural gas sales | |||||||||||
| Total revenues | $ | $ | |||||||||
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 revenues during a reporting period and record any differences between the estimated revenues and actual revenues in the following reporting period. Differences between estimated revenues and actual revenues have historically not been significant. For the three months ended March 31, 2026 and 2025, revenue recognized related to performance obligations satisfied in prior reporting periods was not material.
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3. Inventory
The Company’s inventory balances are comprised of the following:
| March 31, 2026 | December 31, 2025 | ||||||||||
| (In thousands) | |||||||||||
| Inventory | |||||||||||
| Equipment and materials | $ | $ | |||||||||
| Crude oil inventory | |||||||||||
| Total inventory | |||||||||||
| Long-term inventory | |||||||||||
| Linefill in third-party pipelines | |||||||||||
| Total long-term inventory | |||||||||||
| Total | $ | $ | |||||||||
4. Additional Balance Sheet Information
The following table sets forth certain balance sheet amounts comprised of the following:
| March 31, 2026 | December 31, 2025 | ||||||||||
| (In thousands) | |||||||||||
| Accounts receivable, net | |||||||||||
| Trade and other accounts | $ | $ | |||||||||
| Joint interest accounts | |||||||||||
| Total accounts receivable | |||||||||||
| Less: allowance for credit losses | ( | ( | |||||||||
| Total accounts receivable, net | $ | $ | |||||||||
| Revenues and production taxes payable | |||||||||||
| Royalties payable and revenue suspense | $ | $ | |||||||||
| Production taxes payable | |||||||||||
| Total revenues and production taxes payable | $ | $ | |||||||||
| Accrued liabilities | |||||||||||
| Accrued oil and gas marketing | $ | $ | |||||||||
| Accrued capital costs | |||||||||||
| Accrued lease operating expenses | |||||||||||
| Accrued general and administrative expenses | |||||||||||
| Current portion of asset retirement obligations | |||||||||||
| Accrued dividends | |||||||||||
| Other accrued liabilities | |||||||||||
| Total accrued liabilities | $ | $ | |||||||||
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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 ARO (see Note 11—Asset Retirement Obligations) and properties acquired in a business combination (See Note 8—Acquisitions) or upon impairment (see Note 7—Property, Plant and Equipment), at fair value on a non-recurring basis.
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, 2026 | |||||||||||||||||||||||
| Level 1 | Level 2 | Level 3 | Total | ||||||||||||||||||||
| (In thousands) | |||||||||||||||||||||||
| Assets: | |||||||||||||||||||||||
Commodity derivative contracts (see Note 6) | $ | $ | $ | $ | |||||||||||||||||||
Investment in equity securities (see Note 9) | |||||||||||||||||||||||
| Total assets | $ | $ | $ | $ | |||||||||||||||||||
| Liabilities: | |||||||||||||||||||||||
Commodity derivative contracts (see Note 6) | $ | $ | $ | $ | |||||||||||||||||||
| Total liabilities | $ | $ | $ | $ | |||||||||||||||||||
| Fair value at December 31, 2025 | |||||||||||||||||||||||
| Level 1 | Level 2 | Level 3 | Total | ||||||||||||||||||||
| (In thousands) | |||||||||||||||||||||||
| Assets: | |||||||||||||||||||||||
Commodity derivative contracts (see Note 6) | $ | $ | $ | $ | |||||||||||||||||||
Investment in equity securities (see Note 9) | |||||||||||||||||||||||
| Total assets | $ | $ | $ | $ | |||||||||||||||||||
| Liabilities: | |||||||||||||||||||||||
Commodity derivative contracts (see Note 6) | $ | $ | $ | $ | |||||||||||||||||||
| Total liabilities | $ | $ | $ | $ | |||||||||||||||||||
Commodity derivative contracts. The Company enters into commodity derivative contracts to manage risks related to changes in crude oil and natural gas prices. The Company’s swaps, basis swaps and two-way and three-way collars 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 compares the valuation performed by the third-party preparer to counterparty valuation statements to assess the reasonableness of its valuation. The determination of the fair value also incorporates a credit adjustment for non-performance risk, as required by GAAP. The Company calculates the credit adjustment for derivatives in a net asset position using current credit default swap values for each counterparty. The credit adjustment for derivatives in a net liability position is based on the market credit spread of the Company or similarly rated public issuers. The credit risk adjustments to the fair value of the Company’s net derivative assets and liabilities were not material for the periods presented. See Note 6—Derivative Instruments for additional information.
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Investment in equity securities. 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, 2026 and December 31, 2025, respectively. See Note 9—Investment in Equity Securities 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.
Business Combinations. The Company records the fair value of the oil and gas properties acquired using an income approach based on the net discounted future cash flows from the oil and gas properties and related assets acquired. 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 pricing assumptions (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 ARO assumed in this acquisition at fair value. The inputs utilized in valuing the assumed ARO were mostly Level 3 unobservable inputs, including estimated economic lives of oil and natural gas wells as of the acquisition date, anticipated future plugging and abandonment costs and an appropriate credit-adjusted risk-free rate to discount such costs. This valuation technique was used in the following business combination:
•2025 Williston Basin Acquisition. On October 31, 2025, the Company completed the 2025 Williston Basin Acquisition (defined in Note 8—Acquisitions). The assets acquired and liabilities assumed were recorded at fair value as of October 31, 2025.
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, while crude oil basis swaps settle monthly based on the average fixed differential between NYMEX WTI and the ICE BRENT index price. 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, two-way and three-way collars, and basis swaps 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. A basis swap transaction has an established fixed basis differential corresponding to two floating index prices. Depending on the difference of the two floating index prices in relation to the fixed basis differential, the Company either receives an amount from its counterparty, or pays an amount to its counterparty, equal to the difference multiplied by 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.
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At March 31, 2026, 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 | 2026 | Three-way collar | Bbls | $ | $ | $ | |||||||||||||||||||||||||||||||||||||||||
| Crude oil | 2026 | Two-way collar | Bbls | $ | $ | ||||||||||||||||||||||||||||||||||||||||||
| Crude oil | 2026 | Fixed price swaps | Bbls | $ | |||||||||||||||||||||||||||||||||||||||||||
| Crude oil | 2027 | Three-way collar | Bbls | $ | $ | $ | |||||||||||||||||||||||||||||||||||||||||
| Crude oil | 2027 | Two-way collar | Bbls | $ | $ | ||||||||||||||||||||||||||||||||||||||||||
| Crude oil | 2027 | Fixed price swaps | Bbls | $ | |||||||||||||||||||||||||||||||||||||||||||
| Crude oil | 2028 | Three-way collar | Bbls | $ | $ | $ | |||||||||||||||||||||||||||||||||||||||||
| Natural gas | 2026 | Two-way collar | MMBtu | $ | $ | ||||||||||||||||||||||||||||||||||||||||||
| Natural gas | 2026 | Fixed price swaps | MMBtu | $ | |||||||||||||||||||||||||||||||||||||||||||
| Natural gas | 2027 | Two-way collar | MMBtu | $ | $ | ||||||||||||||||||||||||||||||||||||||||||
| Natural gas | 2027 | Fixed price swaps | MMBtu | $ | |||||||||||||||||||||||||||||||||||||||||||
At March 31, 2026, the Company had the following outstanding crude oil basis swaps:
| Index | Settlement Period | Volumes | Weighted Average Differential(1) | ||||||||||||||||||||
| NYMEX WTI - ICE BRENT | 2026 | Bbls | $ | ( | |||||||||||||||||||
(1)The weighted average differential represents the average fixed differential to NYMEX WTI as stated in the related contracts, which is compared to the ICE BRENT index price. If NYMEX WTI combined with the fixed differential as stated in each contract is lower than the ICE BRENT index price at any settlement date, the Company receives the difference. Conversely, if NYMEX WTI combined with the fixed differential as stated in each contract is higher than the ICE BRENT index price, the Company pays the difference.
Subsequent to March 31, 2026, the Company entered into the following commodity derivative contracts:
| Weighted Average Prices | ||||||||||||||||||||||||||||||||||||||||||||
| Commodity | Settlement Period | Derivative Instrument | Volumes | Sub-Floor | Floor | Ceiling | ||||||||||||||||||||||||||||||||||||||
| Crude oil | 2026 | Three-way collar | Bbls | $ | $ | $ | ||||||||||||||||||||||||||||||||||||||
| Crude oil | 2026 | Two-way collar | Bbls | $ | $ | |||||||||||||||||||||||||||||||||||||||
| Crude oil | 2027 | Three-way collar | Bbls | $ | $ | $ | ||||||||||||||||||||||||||||||||||||||
Contingent consideration. In connection with the Company’s 2021 divestiture of certain oil and gas properties, the Company was entitled to receive up to three earn-out payments of $25.0 60 per barrel for such year (the “Contingent Consideration”). In each of January 2024, 2025 and 2026, the Company received $25.0
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 | 2026 | 2025 | |||||||||||||||||
| (In thousands) | ||||||||||||||||||||
| Commodity derivatives | Net loss on derivative instruments | $ | ( | $ | ( | |||||||||||||||
| Contingent consideration | Net loss on derivative instruments(1) | |||||||||||||||||||
____________________
(1)The change in the fair value of the 2025 Contingent Consideration was recorded in net loss on derivative instruments as a gain for the three months ended March 31, 2025.
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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.
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, 2026 | ||||||||||||||||||||||||||
| Derivative Instrument | Balance Sheet Location | Gross Amount | Gross Amount Offset | Net Amount | ||||||||||||||||||||||
| (In thousands) | ||||||||||||||||||||||||||
| Derivatives assets: | ||||||||||||||||||||||||||
| Commodity derivatives | Derivative instruments — current assets | $ | $ | ( | $ | |||||||||||||||||||||
| Commodity derivatives | Derivative instruments — non-current assets | ( | ||||||||||||||||||||||||
| Total derivatives assets | $ | $ | ( | $ | ||||||||||||||||||||||
| Derivatives liabilities: | ||||||||||||||||||||||||||
| Commodity derivatives | Derivative instruments — current liabilities | $ | $ | ( | $ | |||||||||||||||||||||
| Commodity derivatives | Derivative instruments — non-current liabilities | ( | ||||||||||||||||||||||||
| Total derivatives liabilities | $ | $ | ( | $ | ||||||||||||||||||||||
| December 31, 2025 | ||||||||||||||||||||||||||
| Derivative Instrument | Balance Sheet Location | Gross Amount | Gross Amount Offset | Net Amount | ||||||||||||||||||||||
| (In thousands) | ||||||||||||||||||||||||||
| Derivatives assets: | ||||||||||||||||||||||||||
| Commodity derivatives | Derivative instruments — current assets | $ | $ | ( | $ | |||||||||||||||||||||
| Commodity derivatives | Derivative instruments — non-current assets | ( | ||||||||||||||||||||||||
| Total derivatives assets | $ | $ | ( | $ | ||||||||||||||||||||||
| Derivatives liabilities: | ||||||||||||||||||||||||||
| Commodity derivatives | Derivative instruments — current liabilities | $ | $ | ( | $ | |||||||||||||||||||||
| Commodity derivatives | Derivative instruments — non-current liabilities | ( | ||||||||||||||||||||||||
| Total derivatives liabilities | $ | $ | ( | $ | ||||||||||||||||||||||
7. Property, Plant and Equipment
The following table sets forth the Company’s property, plant and equipment for the periods presented:
| March 31, 2026 | December 31, 2025 | ||||||||||
| (In thousands) | |||||||||||
Proved oil and gas properties | $ | $ | |||||||||
| Less: Accumulated depletion | ( | ( | |||||||||
| Proved oil and gas properties, net | |||||||||||
| Unproved oil and gas properties | |||||||||||
Other property and equipment | |||||||||||
| Less: Accumulated depreciation | ( | ( | |||||||||
| Other property and equipment, net | |||||||||||
| Total property, plant and equipment, net | $ | $ | |||||||||
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8. Acquisitions
2025 Acquisition
On September 15, 2025, a wholly-owned subsidiary of the Company entered into a definitive agreement to acquire certain developed and undeveloped oil and gas assets located in the Williston Basin from XTO Energy Inc. and affiliates (collectively, “XTO”), subsidiaries of Exxon Mobil Corporation, for total cash consideration of $550.0 million, subject to customary purchase price adjustments (the “2025 Williston Basin Acquisition”). The effective date of the 2025 Williston Basin Acquisition was September 1, 2025.
On October 31, 2025, the Company completed the 2025 Williston Basin Acquisition for total cash consideration of $542.2 million, including a cash deposit of $55.0 million to XTO upon execution of the purchase and sale agreement and $487.2 million paid to XTO at closing (including customary preliminary purchase price adjustments). The Company funded the 2025 Williston Basin Acquisition with proceeds from the issuance of the 2030 Senior Notes (defined in Note 10—Long-Term Debt) and cash on hand. The 2025 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 2025 Williston Basin Acquisition were not material to the Company’s consolidated financial statements and have therefore not been presented.
Preliminary purchase price allocation. The Company recorded the assets acquired and liabilities assumed in the 2025 Williston Basin Acquisition at their estimated fair value on October 31, 2025 of $542.2 million. The allocation of the fair value to the identifiable assets acquired and liabilities assumed resulted in no
The tables below present the total consideration transferred and its allocation to the identifiable assets acquired and liabilities assumed as of the acquisition date on October 31, 2025. Certain estimated values for the acquisition, including oil and natural gas properties, are not yet finalized.
| Purchase Price Consideration | ||||||||
| (In thousands) | ||||||||
| Cash consideration transferred | $ | |||||||
| Preliminary Purchase Price Allocation | ||||||||
| (In thousands) | ||||||||
| Assets acquired: | ||||||||
| Oil and gas properties (successful efforts method) | $ | |||||||
| Other property and equipment | ||||||||
| Inventory | ||||||||
| Total assets acquired | $ | |||||||
| Liabilities assumed: | ||||||||
| Asset retirement obligations | $ | |||||||
| Revenue and production taxes payable | ||||||||
| Total liabilities assumed | $ | |||||||
| Net assets acquired | $ | |||||||
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9. Investment in Equity Securities
As of March 31, 2026 and December 31, 2025, the fair value of the Company’s investment in Energy Transfer was $140.1 million and $119.7 million, respectively, which represented less than 5
During the three months ended March 31, 2026, the Company recorded a net gain of $22.8 million on its investment in Energy Transfer, comprised of an unrealized gain for the change in fair value of the investment of $20.4 million and a realized gain for cash distributions received of $2.4 million. During the three months ended March 31, 2025, the Company recorded a net loss of $4.9 million on its investment in Energy Transfer, comprised of an unrealized loss for the change in the fair value of its investment of $7.3 million, partially offset by a realized gain for cash distributions received of $2.4 million.
10. Long-Term Debt
The Company’s long-term debt consists of the following:
| March 31, 2026 | December 31, 2025 | ||||||||||
| (In thousands) | |||||||||||
| Senior secured revolving line of credit | $ | $ | |||||||||
2030 Senior Notes | |||||||||||
2033 Senior Notes | |||||||||||
Less: unamortized deferred financing costs | ( | ( | |||||||||
| Total long-term debt, net | $ | $ | |||||||||
Senior secured revolving line of credit. The Company has a senior secured revolving credit facility (the “Credit Facility”) that matures on November 3, 2029. The Credit Facility’s borrowing base is subject to redetermination semi-annually, on or about April 1 and October 1. The most recent redetermination was completed in May 2026 and reaffirmed the borrowing base and the aggregate elected commitment at $2.75 billion and $2.0 billion, respectively. The next redetermination is scheduled for October 2026.
At March 31, 2026, the Company had no borrowings outstanding and $32.6 million of outstanding letters of credit issued under the Credit Facility, resulting in an unused borrowing capacity of $1,967.4 million. At December 31, 2025, the Company had no borrowings outstanding and $32.8 million of outstanding letters of credit issued under the Credit Facility, resulting in an unused borrowing capacity of $1,967.2 million.
During the three months ended March 31, 2026, the weighted average interest rate incurred on borrowings on the Credit Facility was 7.50 %, and during the three months ended March 31, 2025, the weighted average interest rate was 6.42 %. The Company was in compliance with the financial covenants under the Credit Facility at March 31, 2026. 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, an ABR Loan or a Swingline Loan (each as defined in the Credit Facility). The Company incurs interest on outstanding loans at their respective interest rates plus a margin rate ranging between 1.75 % to 2.75 % for Term SOFR Loans and 0.75 % to 1.75 % for ABR Loans or Swingline Loans. The unused borrowing base is subject to a commitment fee ranging between 0.375 % to 0.500 %.
2030 Senior Notes. On September 30, 2025, the Company issued in a private placement $750.0 million of 6.000 % senior unsecured notes due October 1, 2030 (the “2030 Senior Notes”). The 2030 Senior Notes were issued at par and resulted in proceeds of $739.6 million, after deducting underwriters’ discounts, commissions and other expenses. Interest on the 2030 Senior Notes is payable semi-annually on April 1 and October 1 of each year, beginning April 1, 2026. The proceeds were used (i) to fund the 2025 Williston Basin Acquisition and to pay related costs and expenses, (ii) to pay fees and expenses associated with the offering of the 2030 Senior Notes and (iii) for general corporate purposes, including repayment of a portion of the borrowings outstanding under the Credit Facility. In connection with the issuance of the 2030 Senior Notes, the Company recorded deferred financing costs of $10.4 million, which are amortized to interest expense on the Company’s Condensed Consolidated Statement of Operations over the term of the 2030 Senior Notes. As of March 31, 2026, the fair value of the 2030 Senior Notes, which are traded among qualified institutional investors and represent a Level 1 fair value measurement, was $760.0 million.
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2033 Senior Notes. On March 13, 2025, the Company issued in a private placement $750.0 million of 6.750 % senior unsecured notes due March 15, 2033 (the “2033 Senior Notes”). The 2033 Senior Notes were issued at par and resulted in proceeds of $738.8 million, after deducting underwriters’ discounts, commissions and other expenses. Interest on the 2033 Senior Notes is payable semi-annually on March 15 and September 15 of each year, which began on September 15, 2025. The proceeds were used to repurchase the 2026 Senior Notes (as defined below) tendered in a concurrent tender offer, to satisfy and discharge the remaining 2026 Senior Notes not tendered in the concurrent tender offer (which were redeemed on June 1, 2025) and to repay a portion of the borrowings outstanding under the Credit Facility. In connection with the issuance of the 2033 Senior Notes, the Company recorded deferred financing costs of $11.6 million, which are amortized to interest expense on the Company’s Condensed Consolidated Statement of Operations over the term of the 2033 Senior Notes. As of March 31, 2026, the fair value of the 2033 Senior Notes, which are traded among qualified institutional investors and represent a Level 1 fair value measurement, was $774.3 million.
The 2030 Senior Notes and the 2033 Senior Notes are guaranteed on a senior unsecured basis by certain subsidiaries of the Company (the “Chord Guarantors”). These guarantees are full and unconditional and joint and several among the Chord Guarantors, subject to certain customary release provisions. The indentures governing the 2030 Senior Notes and the 2033 Senior Notes contain customary events of default as well as cross-default provisions with other indebtedness of Chord and its restricted subsidiaries.
2026 Senior Notes. At December 31, 2024, the Company had $400.0 million of 6.375 % senior unsecured notes outstanding due June 1, 2026 (the “2026 Senior Notes”). Concurrent with the issuance of the 2033 Senior Notes on March 13, 2025, the purchase and satisfaction and discharge of the 2026 Senior Notes resulted in a loss on debt extinguishment of $3.5 million, primarily including the write-off of unamortized debt issuance costs of $2.1 million and a premium paid to redeem a portion of the 2026 Senior Notes totaling $1.1 million.
11. Asset Retirement Obligations
The following table reflects the changes in the Company’s ARO during the three months ended March 31, 2026:
| (In thousands) | |||||
| Balance at December 31, 2025 | $ | ||||
| Liabilities incurred during period | |||||
| Liabilities settled during period | ( | ||||
Accretion expense during period | |||||
Balance at March 31, 2026 | $ | ||||
12. Income Taxes
The Company’s effective tax rate was (15.2 )% for the three months ended March 31, 2026 as compared to an effective tax rate of 25.0 % for the three months ended March 31, 2025.
The effective tax rate for the three months ended March 31, 2026 was lower than the statutory federal rate of 21% primarily as a result of the identification of an error in the tax provision for the three and six months ended June 30, 2025 pertaining to the impact of goodwill impairment on the Company’s deferred taxes on unremitted earnings. As a result, the Company recognized an additional income tax benefit of $41.8
The effective tax rate for the three months ended March 31, 2025 was higher than the statutory federal rate of 21% primarily as a result of the impact of state income taxes and deferred taxes on unremitted earnings.
The Company paid income taxes of $21.0 million and $33.9 million during the three months ended March 31, 2026 and 2025, respectively.
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13. Equity-Based Compensation
The Company has granted RSUs, PSUs, and MSUs (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. The Company recognized $8.0 million and $6.9 million in equity-based compensation expenses related to equity-classified awards during the three months ended March 31, 2026 and 2025, respectively. Equity-based compensation expenses related to liability-classified awards were $3.5 million for the three months ended March 31, 2026 and not material for the three months ended March 31, 2025.
Restricted stock units. Restricted stock units (“RSUs”) are contingent shares that generally vest on either a cliff or graded basis over a one-year or three-year period (as applicable) and are subject to a service condition. During the three months ended March 31, 2026, the Company granted 268,825 RSUs to employees and non-employee directors of the Company with a weighted average grant date fair value of $95.53 per share.
Market stock units. During the three months ended March 31, 2026, the Company granted Market Stock Units (“MSUs”), which are eligible to vest and become earned at the end of the three-year performance period, which begins on January 1 of the initial grant year and ends on December 31 of the third year, subject to the level of achievement with respect to certain performance goals.
The MSUs are subject to time-based service requirements and market conditions based on the total stockholder return (“TSR”) achieved by the Company during the performance period. Depending on the Company’s TSR, award recipients may earn between 0 % and 200 % of the number of MSUs originally granted. Any earned MSUs will be settled in shares of the Company’s common stock.
During the three months ended March 31, 2026, the Company granted 24,131 MSUs to certain employees of the Company with a weighted average grant date fair value of $128.29 per share.
Performance share units. During the three months ended March 31, 2026, the Company granted PSUs that include (i) TSR PSUs (“Absolute TSR PSUs”) and (ii) relative TSR PSUs (“Relative TSR PSUs” and collectively with the Absolute TSR PSUs, the “PSUs”), which are eligible to vest and become earned at the end of the three-year performance period which begins on January 1 of the initial grant year and ends on December 31 of the third year.
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 200 % 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 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 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, 2026, the Company granted (i) 30,299 Absolute TSR PSUs to certain employees of the Company with a weighted average grant date fair value of $101.14 per share and (ii) 90,912 Relative TSR PSUs to employees of the Company with a weighted average grant date fair value of $114.53 per share.
Fair value assumptions. The aggregate grant date fair value of the PSUs and MSUs were 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 (vi) solely for Relative TSR PSUs, 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.
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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 for the PSUs and MSUs granted during the three months ended March 31, 2026:
| Absolute and Relative TSR PSUs | Absolute TSR MSUs | ||||||||||||||||||||||
| Forecast period (years) | |||||||||||||||||||||||
| Risk-free interest rate | |||||||||||||||||||||||
| Implied equity volatility | |||||||||||||||||||||||
| Stock price on date of grant | $ | $ | |||||||||||||||||||||
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, 2026, the Company granted 21,918 phantom unit awards to employees with a weighted average grant date fair value of $95.53 per share.
14. Stockholders’ Equity
Dividends
The following table summarizes the Company’s dividends declared for the three months ended March 31, 2026 and 2025:
| Base Dividend Rate per Share | Total Dividends Declared | |||||||||||||
| (In thousands, except per share data) | ||||||||||||||
| Q1 2026 | $ | $ | ||||||||||||
| Q1 2025 | ||||||||||||||
Total dividends declared in the table above include $1.0 million and $0.8 million associated with dividend equivalent rights on unvested equity-based compensation awards for the three months ended March 31, 2026 and 2025.
On May 5, 2026, the Company declared a base cash dividend of $1.30 per share of common stock. The dividend will be payable on June 5, 2026 to shareholders of record as of May 20, 2026.
Share Repurchase Program
In August 2025, the Board of Directors authorized a share repurchase program of up to $1.0 billion of the Company’s common stock, which replaced the Company’s previous share repurchase programs. The Company has repurchased, and may repurchase in the future, shares pursuant to a Rule 10b5-1 trading plan under the Securities Exchange Act of 1934, as amended, which permits the Company to repurchase shares at times that may otherwise be prohibited under its insider trading policy. The share repurchase program does not require the Company to make purchases within a particular time frame.
During the three months ended March 31, 2026, the Company repurchased 559,064 shares of common stock at a weighted average price of $126.53 per common share for a total cost of $70.7 million, excluding accrued excise tax of $0.6 881.4 million of capacity remaining under the Company’s $1.0 billion share repurchase program.
During the three months ended March 31, 2025, the Company repurchased 1,994,496 shares of common stock at a weighted average price of $108.54 per common share for a total cost of $216.5 million, under its previous share repurchase programs.
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15. 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 (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.
| Three Months Ended March 31, | |||||||||||
| 2026 | 2025 | ||||||||||
| (In thousands, except per share data) | |||||||||||
| Net income | $ | $ | |||||||||
| Distributed and undistributed earnings allocated to participating securities | ( | ( | |||||||||
| Net income attributable to common stockholders (basic) | |||||||||||
| Reallocation of distributed and undistributed earnings allocated to participating securities | |||||||||||
| Net income attributable to common stockholders (diluted) | $ | $ | |||||||||
| Weighted average common shares outstanding: | |||||||||||
| Basic weighted average common shares outstanding | |||||||||||
Dilutive effect of share-based awards | |||||||||||
| Diluted weighted average common shares outstanding | |||||||||||
| Basic earnings per share | $ | $ | |||||||||
| Diluted earnings per share | $ | $ | |||||||||
| Anti-dilutive weighted average common shares: | |||||||||||
| Potential common shares | |||||||||||
For the three months ended March 31, 2026, the diluted earnings per share calculation excludes the impact of unvested share-based awards that were anti-dilutive. For the three months ended March 31, 2025, the diluted earnings per share calculation excludes the impact of unvested share-based awards and outstanding warrants that were anti-dilutive. There were no remaining warrants as of March 31, 2026, as all previously outstanding warrants expired on September 1, 2025.
16. Commitments and Contingencies
Included below is a discussion of various future commitments of the Company as of March 31, 2026. The commitments under these arrangements are not recorded in the accompanying Condensed Consolidated Balance Sheets. The amounts disclosed represent undiscounted cash flows on a gross basis and no inflation elements have been applied. As of March 31, 2026, the Company’s material off-balance sheet arrangements and transactions include $32.6 million in outstanding letters of credit issued under the Credit Facility and $114.8 million in net surety bond exposure issued as financial assurance on certain agreements.
Volume commitment agreements. As of March 31, 2026, the Company had certain agreements with an aggregate requirement to deliver, transport or purchase a minimum quantity of approximately 76.7 MMBbl of crude oil, 10.0 MMBbl of NGL, 302.1 Bcf of natural gas and 12.0 MMBbl of water within specified timeframes.
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As of March 31, 2026, the estimable future commitments under these volume commitment agreements are as follows:
| (In thousands) | |||||
| 2027 | $ | ||||
| 2028 | |||||
| 2029 | |||||
| 2030 | |||||
| 2031 | |||||
| Thereafter | |||||
| $ | |||||
The future commitments under certain agreements cannot be estimated and are therefore excluded from the table above as they are based on fixed differentials relative to a commodity index price under the agreements as compared to the differential relative to a commodity index price for the production month.
The Company enters into long-term contracts to provide production flow assurance in oversupplied areas with limited infrastructure, which provides for optimization of transportation and processing costs. As properties are undergoing development activities, the Company may experience temporary delivery or transportation shortfalls until production volumes grow to meet or exceed the minimum volume commitments. The Company recognizes any monthly deficiency payments in the period in which the under delivery takes place and the related liability has been incurred. The table above does not include any such deficiency payments that may be incurred under the Company’s physical delivery contracts, since it cannot be predicted with accuracy the amount and timing of any such penalties incurred.
17. Leases
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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, 2025 (“2025 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”). All statements, other than statements of historical fact included in this Quarterly Report on Form 10-Q, regarding, but not limited to, 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 “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.
These forward-looking statements are subject to a number of risks and uncertainties, many of which are beyond our control. 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.
We believe these factors and risks relate to forward-looking statements including, but not limited to, the following:
•crude oil, NGL 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, NGL 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 production levels;
•changes in trade policies and regulations, including increases or change in duties, current and potentially new tariffs or quotas; and other similar measures, as well as the potential impact of retaliatory tariffs and other actions;
•war between Russia and Ukraine, military conflicts in the Red Sea Region, Iran, and the wider Middle East and their effect on commodity prices;
•changes or uncertainty in general economic and geopolitical conditions;
•inflation rates and the impact of associated monetary policy responses, including fluctuating interest rates;
•logistical challenges and supply chain disruptions, including as a result of conflicts;
•our business strategy, including the continued implementation of our 4-mile well program;
•the geographic concentration of our operations;
•estimated future net reserves and present value thereof;
•timing and amount of future production of crude oil, NGL 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, NGL and natural gas in the Williston Basin and other regions in the United States;
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•the possible shutdown of the Dakota Access Pipeline;
•our ability to realize the anticipated benefits from acquisitions;
•property acquisitions and divestitures;
•integration and benefits of property acquisitions or the effects of such acquisitions on our cash position and levels of indebtedness;
•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 pursue goals regarding capital management activities such as share repurchases, paying dividends on our common stock or additional means 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 Facility 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 disruptions arising from cybersecurity threats, terrorist attacks and any consequential or other hostilities;
•compliance with, and changes in, environmental, safety and other laws and regulations;
•execution of our sustainability initiatives;
•effectiveness of risk management activities;
•competition in the oil and gas industry;
•counterparty credit risk;
•incurring environmental liabilities;
•developments in the global economy and resulting demand and supply for crude oil, NGL and natural gas;
•governmental regulation, including, but not limited to, that of the Federal Energy Regulatory Commission (“FERC”), and the taxation of the oil and gas industry;
•developments in crude oil-producing and natural gas-producing countries;
•integration of emerging technologies, including artificial intelligence and machine learning technologies for improving operational efficiency;
•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 bank failures and the volatile 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 2025 Annual Report and in our other filings with the SEC.
In light of these risks, uncertainties and assumptions, the forward-looking events discussed may not occur. 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. These cautionary statements qualify all forward-looking statements attributable to us or persons acting on our behalf.
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Overview
Chord Energy Corporation, a Delaware 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 primarily in the Williston Basin with limited non-operated interests in the Marcellus Shale. Our mission is to responsibly produce hydrocarbons while exercising capital discipline, operating efficiently, improving continuously and providing a fun and rewarding environment for our employees. We are ideally positioned to generate strong free cash flow and enhance return of capital, 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. Energy markets experienced significant volatility during the first quarter of 2026, driven primarily by geopolitical tensions and the resulting disruptions to global oil supply. Following the escalation of conflict in the Middle East in late February, the NYMEX WTI spot price increased more than 50% by the end of the first quarter. Continued geopolitical tensions, uncertainty around OPEC+ production policy and the potential economic outcomes of tariff and trade policy decisions of the U.S. or other governments create difficulty in predicting future impacts to commodity prices, which could affect our financial position, results of operations, cash flows, capital and operating costs, and the quantities of crude oil, NGL and natural gas reserves that may be economically produced.
In an effort to improve price realizations from the sale of our crude oil, NGL and natural gas, we manage our commodities marketing activities in-house, which enables us to market and sell our crude oil, NGL 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, 2026, substantially all of our gross operated crude oil and natural gas production were connected to gathering systems. Our market optionality on these crude oil gathering systems allows us to shift volumes between pipeline and, to a lesser extent, rail markets in order to optimize price realizations. Expansions of both pipeline and rail facilities in the Williston Basin has reduced prior constraints on crude oil takeaway capacity and improved our price differentials received at the lease.
In an effort to reduce inflationary pressures that emerged in the broader economy, central banks have in the past raised interest rates. Although U.S. inflation rates have shown signs of moderating, higher interest rates generally reduce economic activity levels, which have and could in the future again result in lower commodity prices due to reduced demand for crude oil, NGL and natural gas. To the extent we and our relevant markets experience high inflation, we may see cost increases in our operations, including increases in equipment and labor costs, and as a result our revenues, estimates of future reserves, borrowing base calculations and impairment assessments could be negatively impacted.
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Results of Operations
Operational and Financial Highlights
•Production volumes averaged 275,615 Boepd (57% oil), including average daily crude oil volumes of 158,027 Bopd in the first quarter of 2026.
•Capital expenditures (excluding capitalized interest) were $344.9 million in the first quarter of 2026.
•Lease operating expenses (“LOE”) were $9.87 per Boe in the first quarter of 2026.
•Net cash provided by operating activities was $507.5 million and net income was $108.6 million for the first quarter of 2026.
Shareholder Return Highlights
•Paid $1.30 per share base cash dividend on March 27, 2026.
•Repurchased $70.7 million of common stock (excluding accrued excise taxes) in the first quarter of 2026.
•Declared a base cash dividend of $1.30 per share of common stock. The dividend will be payable on June 5, 2026 to shareholders of record as of May 20, 2026.
Net Income
We had net income of $108.6 million for the three months ended March 31, 2026, which decreased 51% as compared to $219.8 million for the three months ended March 31, 2025, primarily due to an unrealized loss on our commodity derivative contracts driven by an upward shift in the crude oil futures curve. Additional impacts on net income from increases and decreases in certain revenues and expenses are further explained below.
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 and/or changes in commodity prices. Our purchased oil and gas sales are derived from the sale of crude oil 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 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.
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The following table summarizes our revenues, production and average realized prices for the periods presented:
| Three Months Ended March 31, 2026 | Three Months Ended December 31, 2025 | Three Months Ended March 31, 2025 | |||||||||||||||
| Revenues (in thousands) | |||||||||||||||||
Crude oil revenues | $ | 996,296 | $ | 801,016 | $ | 956,138 | |||||||||||
| NGL revenues | 38,222 | 23,541 | 61,345 | ||||||||||||||
| Natural gas revenues | 116,071 | 52,046 | 85,942 | ||||||||||||||
Purchased oil and gas sales | 515,046 | 292,836 | 111,622 | ||||||||||||||
| Total revenues | $ | 1,665,635 | $ | 1,169,439 | $ | 1,215,047 | |||||||||||
| Production data | |||||||||||||||||
| Crude oil (MBbls) | 14,222 | 14,078 | 13,835 | ||||||||||||||
| NGL (MBbls) | 4,413 | 4,825 | 4,325 | ||||||||||||||
Natural gas (MMcf)(1) | 37,023 | 37,187 | 37,303 | ||||||||||||||
| Oil equivalents (MBoe) | 24,805 | 25,101 | 24,377 | ||||||||||||||
| Average daily production (Boepd) | 275,615 | 272,840 | 270,855 | ||||||||||||||
| Average daily crude oil production (Bopd) | 158,027 | 153,026 | 153,720 | ||||||||||||||
| Average sales prices | |||||||||||||||||
| Crude oil (per Bbl) | |||||||||||||||||
| Average sales price | $ | 70.05 | $ | 56.90 | $ | 69.11 | |||||||||||
Effect of derivative settlements(2) | (0.48) | 1.72 | (0.03) | ||||||||||||||
Average realized price after the effect of derivative settlements(2) | $ | 69.57 | $ | 58.62 | $ | 69.08 | |||||||||||
| NGL (per Bbl) | |||||||||||||||||
| Average sales price | $ | 8.66 | $ | 4.88 | $ | 14.18 | |||||||||||
Effect of derivative settlements(2) | — | — | — | ||||||||||||||
Average realized price after the effect of derivative settlements(2) | $ | 8.66 | $ | 4.88 | $ | 14.18 | |||||||||||
| Natural gas (per Mcf) | |||||||||||||||||
Average sales price(1) | $ | 3.14 | $ | 1.40 | $ | 2.30 | |||||||||||
Effect of derivative settlements(2) | (0.32) | 0.16 | 0.01 | ||||||||||||||
Average realized price after the effect of derivative settlements(1)(2) | $ | 2.82 | $ | 1.56 | $ | 2.31 | |||||||||||
____________________
(1)For the three months ended March 31, 2026, December 31, 2025 and March 31, 2025, natural gas production volume from the Marcellus Shale was 11,745 MMcf, 10,950 MMcf and MMcf 11,563, respectively. The related realized natural gas price prior to the effect of derivative settlements was $6.40 per Mcf, $3.19 per Mcf and $4.71 per Mcf for the three months ended March 31, 2026, December 31, 2025 and March 31, 2025, respectively.
(2)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, 2026 as compared to three months ended December 31, 2025
Crude oil revenues. Our crude oil revenues increased $195.3 million to $996.3 million for the three months ended March 31, 2026 as compared to the three months ended December 31, 2025. The increase was primarily due to higher crude oil realized prices quarter over quarter resulting in a $185.2 million increase, coupled with an increase of $10.1 million due to higher crude oil production volumes sold quarter over quarter. Average crude oil sales prices, without derivative settlements, increased by $13.15 per barrel quarter over quarter to an average of $70.05 per barrel for the three months ended March 31, 2026 primarily due to an increase in NYMEX WTI.
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NGL revenues. Our NGL revenues increased $14.7 million to $38.2 million for the three months ended March 31, 2026 as compared to the three months ended December 31, 2025. The increase was primarily due to higher realized NGL prices quarter over quarter resulting in a $18.3 million increase, partially offset by a decrease of $3.6 million due to lower NGL production volumes sold quarter over quarter. Average NGL sales prices, without derivative settlements, increased by $3.78 per barrel quarter over quarter to an average of $8.66 per barrel for the three months ended March 31, 2026 primarily due to increases in the corresponding NGL product index prices for butane and pentane.
Natural gas revenues. Our natural gas revenues increased $64.0 million to $116.1 million for the three months ended March 31, 2026 as compared to the three months ended December 31, 2025. The increase was primarily due to higher natural gas realized prices quarter over quarter resulting in a $64.5 million increase, partially offset by a decrease of $0.5 million due to lower natural gas production volumes sold quarter over quarter. Average natural gas sales prices, without derivative settlements, increased by $1.74 per Mcf quarter over quarter to $3.14 per Mcf for the three months ended March 31, 2026 primarily due to the seasonality of colder weather resulting in higher index prices quarter over quarter.
Purchased oil and gas sales. Purchased oil and gas sales increased $222.2 million to $515.0 million for the three months ended March 31, 2026 as compared to the three months ended December 31, 2025. This increase was primarily due to an increase in the volume of crude oil purchased and subsequently sold quarter over quarter, coupled with increased crude oil prices over the same period.
Three months ended March 31, 2026 as compared to three months ended March 31, 2025
Crude oil revenues. Our crude oil revenues increased $40.2 million to $996.3 million for the three months ended March 31, 2026 as compared to the three months ended March 31, 2025. The increase was primarily due to higher crude oil production volumes sold period over period resulting in a $27.1 million increase, coupled with an increase of $13.1 million due to higher crude oil realized prices period over period. Average crude oil sales prices, without derivative settlements, increased by $0.94 per barrel period over period to an average of $70.05 per barrel for the three months ended March 31, 2026 primarily due to an increase in NYMEX WTI.
NGL revenues. Our NGL revenues decreased $23.1 million to $38.2 million for the three months ended March 31, 2026 as compared to the three months ended March 31, 2025. The decrease was primarily due to lower realized NGL prices period over period resulting in a $23.9 million decrease, partially offset by an increase of $0.8 million due to higher NGL production volumes sold period over period. Average NGL sales prices, without derivative settlements, decreased by $5.52 per barrel period over period to an average of $8.66 per barrel for the three months ended March 31, 2026 primarily due to decreases in the corresponding NGL product index prices.
Natural gas revenues. Our natural gas revenues increased $30.1 million to $116.1 million for the three months ended March 31, 2026 as compared to the three months ended March 31, 2025. The increase was primarily due to higher natural gas realized prices period over period resulting in a $31.0 million increase, partially offset by a decrease of $0.9 million due to lower natural gas production volumes sold period over period. Average natural gas sales prices, without derivative settlements, increased by $0.84 per Mcf period over period to $3.14 per Mcf for the three months ended March 31, 2026 primarily due to increases in the corresponding natural gas index prices period over period.
Purchased oil and gas sales. Purchased oil and gas sales increased $403.4 million to $515.0 million for the three months ended March 31, 2026 as compared to the three months ended March 31, 2025. This increase was primarily due to an increase in the volume of crude oil purchased and subsequently sold period over period.
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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, 2026 | Three Months Ended December 31, 2025 | Three Months Ended March 31, 2025 | |||||||||||||||
| (In thousands, except per Boe of production data) | |||||||||||||||||
| Operating expenses | |||||||||||||||||
| Lease operating expenses | $ | 244,909 | $ | 243,966 | $ | 233,074 | |||||||||||
| Gathering, processing and transportation expenses | 67,018 | 70,451 | 73,314 | ||||||||||||||
| Purchased oil and gas expenses | 509,832 | 291,068 | 111,368 | ||||||||||||||
| Production taxes | 86,711 | 68,764 | 74,642 | ||||||||||||||
| Depreciation, depletion and amortization | 384,215 | 368,446 | 349,809 | ||||||||||||||
| General and administrative expenses | 37,508 | 33,516 | 38,377 | ||||||||||||||
| Exploration and impairment | 2,563 | 5,454 | 1,983 | ||||||||||||||
| Total operating expenses | 1,332,756 | 1,081,665 | 882,567 | ||||||||||||||
| Gain on sale of assets, net | 343 | 4,083 | 5,516 | ||||||||||||||
| Operating income | 333,222 | 91,857 | 337,996 | ||||||||||||||
| Other income (expense) | |||||||||||||||||
| Net gain (loss) on derivative instruments | (241,471) | 44,944 | (20,281) | ||||||||||||||
| Net gain (loss) from investment in equity securities | 22,829 | (2,450) | (4,900) | ||||||||||||||
| Interest expense, net of capitalized interest | (26,596) | (26,826) | (15,818) | ||||||||||||||
| Loss on debt extinguishment | — | — | (3,494) | ||||||||||||||
| Other income (expense), net | 6,329 | 8,350 | (501) | ||||||||||||||
| Total other income (expense), net | (238,909) | 24,018 | (44,994) | ||||||||||||||
| Income before income taxes | 94,313 | 115,875 | 293,002 | ||||||||||||||
| Income tax benefit (expense) | 14,295 | (31,459) | (73,165) | ||||||||||||||
| Net income | $ | 108,608 | $ | 84,416 | $ | 219,837 | |||||||||||
| Costs and expenses (per Boe of production) | |||||||||||||||||
| Lease operating expenses | $ | 9.87 | $ | 9.72 | $ | 9.56 | |||||||||||
| Gathering, processing and transportation expenses | 2.70 | 2.81 | 3.01 | ||||||||||||||
| Production taxes | 3.50 | 2.74 | 3.06 | ||||||||||||||
Three months ended March 31, 2026 as compared to three months ended December 31, 2025
Lease operating expenses. LOE increased $0.9 million to $244.9 million for the three months ended March 31, 2026 as compared to the three months ended December 31, 2025. The increase was primarily due to higher workover activity and costs of $7.2 million and an increase in operating costs from our non-operated assets of $1.2 million, partially offset by lower fixed costs of $4.8 million and lower water costs of $3.5 million quarter over quarter. The same factors contributed to an increase in LOE per BOE, which increased $0.15 per Boe quarter over quarter to $9.87 per Boe for the three months ended March 31, 2026.
Gathering, processing and transportation expenses. GPT expenses decreased $3.4 million to $67.0 million for the three months ended March 31, 2026 as compared to the three months ended December 31, 2025. The decrease was primarily due to a decrease in NGL and natural gas production volumes of $3.0 million quarter over quarter. GPT expenses decreased $0.11 per Boe quarter over quarter to $2.70 per Boe for the three months ended March 31, 2026 primarily due to lower NGL and natural gas production volumes.
Purchased oil and gas expenses. Purchased oil and gas expenses increased $218.8 million to $509.8 million for the three months ended March 31, 2026 as compared to the three months ended December 31, 2025. The increase was primarily due to an increase in the volume of crude oil purchased quarter over quarter at increased crude oil prices over the same period.
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Production taxes. Production taxes increased $17.9 million to $86.7 million for the three months ended March 31, 2026 as compared to the three months ended December 31, 2025 primarily due to higher crude oil revenues quarter over quarter. The production tax rate as a percentage of crude oil, NGL and natural gas revenues of 7.5% for the three months ended March 31, 2026 decreased from 7.8% for the three months ended December 31, 2025 primarily due to natural gas comprising a larger percentage of total sales relative to the prior quarter due to higher natural gas realized prices, while total natural gas production volumes, which drive production taxes on natural gas, remained relatively flat.
Depreciation, depletion and amortization. DD&A expense increased $15.8 million to $384.2 million for the three months ended March 31, 2026 as compared to the three months ended December 31, 2025. The increase was primarily driven by $24.0 million related to a higher depletion rate quarter over quarter, offset by a decrease in plugging and abandonment expenses of $5.8 million. The depletion rate increased $1.03 per Boe quarter over quarter to $15.20 per Boe for the three months ended March 31, 2026 primarily due to a decrease in proved developed reserves quarter over quarter.
General and administrative expenses. G&A expenses increased $4.0 million to $37.5 million for the three months ended March 31, 2026 as compared to the three months ended December 31, 2025. The increase was primarily attributable to an increase in equity-based compensation costs of $4.8 million due to the impact of our stock price on the fair value of our liability-based awards coupled with new award grants during the current quarter and an increase of $3.6 million due to higher current expected credit losses. These increases were partially offset by a decrease of $4.4 million primarily attributable to various cost savings related to other G&A expenses quarter over quarter.
Derivative instruments. We recorded a $241.5 million net loss on derivative instruments for the three months ended March 31, 2026, which included an unrealized loss of $223.0 million related to the change in fair value of our commodity derivative contracts primarily driven by an upward shift in the futures curve for forecasted commodity prices, coupled with a realized loss on settled commodity derivative contracts of $18.5 million. During the three months ended December 31, 2025, we recorded a $44.9 million net gain on derivative instruments, which was comprised of a net gain of $19.9 million associated with our commodity derivative contracts, coupled with a gain of $25.0 million associated with a contract that included contingent consideration. The net gain of $19.9 million on commodity derivative contracts included a realized gain of $30.2 million on settled commodity derivative contracts, partially offset by an unrealized loss of $10.3 million related to the change in fair value of our commodity derivative contracts.
Investment in equity securities. We recorded a $22.8 million net gain related to our investment in Energy Transfer LP (“Energy Transfer”) for the three months ended March 31, 2026, which included an unrealized gain of $20.4 million as a result of an increase in the fair value of the investment during the quarter, coupled with a gain of $2.4 million for a cash distribution from Energy Transfer during the quarter. During the three months ended December 31, 2025, we recorded a $2.5 million net loss related to our investment in Energy Transfer, which included an unrealized loss of $4.9 million as a result of a decrease in the fair value of the investment during the quarter, partially offset by a gain of $2.4 million for a cash distribution from Energy Transfer during the quarter.
Income tax benefit (expense). Our effective tax rate was recorded at (15.2)% of pre-tax income for the three months ended March 31, 2026 and 27.1% of pre-tax income for the three months ended December 31, 2025. The effective tax rate for the three months ended March 31, 2026 was lower than the statutory federal rate of 21% primarily as a result of the identification of an error in the tax provision for the three and six months ended June 30, 2025 pertaining to the impact of goodwill impairment on our deferred taxes on unremitted earnings. As a result, we recognized an additional income tax benefit of $41.8 million during the three months ended March 31, 2026, with a corresponding decrease to deferred tax liabilities. The effective tax rate for the three months ended December 31, 2025 was higher than the statutory federal rate of 21% primarily as a result of state income tax and return to provision adjustments resulting from filing our tax returns during the quarter.
Three months ended March 31, 2026 as compared to three months ended March 31, 2025
Lease operating expenses. LOE increased $11.8 million to $244.9 million for the three months ended March 31, 2026 as compared to the three months ended March 31, 2025. The increase was primarily due to increased activity and operating costs from our non-operated assets of $14.6 million, higher workover costs of $4.6 million and higher variable costs of $1.9 million, partially offset by decreased fixed costs of $9.4 million period over period. The same factors contributed to an increase in LOE per Boe, which increased $0.31 per Boe period over period to $9.87 per Boe for the three months ended March 31, 2026.
Gathering, processing and transportation expenses. GPT expenses decreased $6.3 million to $67.0 million for the three months ended March 31, 2026 as compared to the three months ended March 31, 2025. The decrease was primarily due to lower NGL and natural gas gathering and processing fees of $7.6 million and lower crude oil transportation fees of $1.9 million, partially offset by an increase in crude oil and NGL production volumes of $3.5 million period over period. GPT expenses decreased $0.31 per Boe period over period to $2.70 per Boe for the three months ended March 31, 2026 primarily due to lower gathering, processing and transportation fees.
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Purchased oil and gas expenses. Purchased oil and gas expenses increased $398.5 million to $509.8 million for the three months ended March 31, 2026 as compared to the three months ended March 31, 2025 primarily due to an increase in the volume of crude oil purchased period over period.
Production taxes. Production taxes increased $12.1 million to $86.7 million for the three months ended March 31, 2026 as compared to the three months ended March 31, 2025. The increase was primarily due to higher crude oil revenues period over period, partially offset by a $10.9 million decrease in non-recurring refunds period over period related to certain North Dakota wells receiving an extraction tax exemption. The production tax rate as a percentage of crude oil, NGL and natural gas revenues increased from 6.8% for the three months ended March 31, 2025 to 7.5% for the three months ended March 31, 2026 primarily due to increased crude oil revenues and fewer wells qualifying for the extraction tax exemption relative to the prior period.
Depreciation, depletion and amortization. DD&A expense increased $34.4 million to $384.2 million for the three months ended March 31, 2026 as compared to the three months ended March 31, 2025. The increase was primarily due to $24.3 million of additional depletion expense due to a higher depletion rate period over period, coupled with $9.3 million of additional DD&A expense related to an overall increase in production volumes. The depletion rate increased $1.11 per Boe period over period to $15.20 per Boe for the three months ended March 31, 2026 primarily due to a decrease in proved developed reserves period over period.
General and administrative expenses. G&A expenses decreased $0.9 million to $37.5 million for the three months ended March 31, 2026 as compared to the three months ended March 31, 2025. The decrease was primarily attributable to a decrease in merger-related costs of $5.1 million, lower employee compensation expenses of $2.5 million and a decrease of $1.7 million primarily attributable to various cost savings related to other G&A expenses, partially offset by an increase of $4.5 million due to higher current expected credit losses and an increase in equity-based compensation costs of $4.0 million period over period.
Derivative instruments. During the three months ended March 31, 2026, we recorded a $241.5 million net loss on derivative instruments, which included an unrealized loss of $223.0 million related to the change in fair value of our commodity derivative contracts primarily driven by an upward shift in the futures curve for forecasted commodity prices, coupled with a realized loss of $18.5 million on settled commodity derivative contracts. During the three months ended March 31, 2025, we recorded a $20.3 million net loss on derivative instruments, which was comprised of a net loss of $21.0 million associated with our commodity derivative contracts and an unrealized gain of $0.7 million associated with a contract that included contingent consideration. The net loss of $21.0 million on commodity derivative contracts included an unrealized loss of $20.7 million related to the change in fair value of our commodity derivative contracts primarily driven by an upward shift in the crude oil and natural gas futures curves, coupled with a realized loss of $0.3 million on settled commodity derivative contracts.
Investment in equity securities. We recorded a $22.8 million net gain related to our investment in Energy Transfer for the three months ended March 31, 2026, which included an unrealized gain of $20.4 million as a result of an increase in the fair value of the investment during the period, coupled with a gain of $2.4 million for a cash distribution from Energy Transfer during the period. During the three months ended March 31, 2025, we recorded a net loss of $4.9 million related to our investment in Energy Transfer, which included an unrealized loss of $7.3 million as a result of a decrease in the fair value of the investment during the period, partially offset by a gain of $2.4 million for a cash distribution from Energy Transfer during the period.
Interest expense, net of capitalized interest. Interest expense increased $10.8 million to $26.6 million for the three months ended March 31, 2026 as compared to the three months ended March 31, 2025. The increase is primarily due to additional interest expense period over period on our senior unsecured notes of $23.5 million as a result of the issuance of the 2033 Senior Notes (defined below) and the 2030 Senior Notes (defined below) during 2025. This increase was partially offset by a $7.7 million decrease resulting from the repayment of the 2026 Senior Notes (defined below) during March 2025 and a $5.0 million decrease in interest expense on the Credit Facility (defined below) period over period. For the three months ended March 31, 2026, the weighted average borrowings outstanding under the Credit Facility were $0.2 million, and the weighted average interest rate incurred on the outstanding borrowings was 7.5%. During the three months ended March 31, 2025, the weighted average borrowings outstanding under the Credit Facility were $383.4 million, and the weighted average interest rate incurred on the outstanding borrowings was 6.4%.
Loss on debt extinguishment. On March 13, 2025, we paid an aggregate of $409.1 million to purchase and satisfy and discharge $400.0 million of 6.375% senior unsecured notes outstanding due June 1, 2026 (the “2026 Senior Notes”), resulting in a loss on debt extinguishment of $3.5 million for the three months ended March 31, 2025. The loss primarily included the write-off of unamortized debt issuance costs of $2.1 million and a premium paid to redeem a portion of the 2026 Senior Notes of $1.1 million.
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Income tax benefit (expense). Our effective tax rate was recorded at (15.2)% and 25.0% of pre-tax income for the three months ended March 31, 2026 and 2025, respectively. Our effective tax rate for the three months ended March 31, 2026 was lower than the statutory federal rate of 21% primarily as a result of the identification of an error in the tax provision for the three and six months ended June 30, 2025 pertaining to the impact of goodwill impairment on our deferred taxes on unremitted earnings. As a result, we recognized an additional income tax benefit of $41.8 million during the three months ended March 31, 2026, with a corresponding decrease to deferred tax liabilities. The effective tax rate for the three months ended March 31, 2025 was higher than the statutory federal rate of 21% primarily as a result of the impact of state income taxes and deferred taxes on unremitted earnings.
Liquidity and Capital Resources
As of March 31, 2026, we had $2,193.2 million of liquidity available, including $1,967.4 million of aggregate unused borrowing capacity available under the Credit Facility (defined below) and $225.8 million in cash and cash equivalents. During the three months ended March 31, 2026, our primary sources of liquidity were from cash flows from operations, available borrowing capacity under the Credit Facility, and cash on hand. During the same period, our primary liquidity requirements were capital expenditures for the development of oil and gas properties, dividend payments, share repurchases, and working capital requirements.
Our cash flows depend on many factors, including the price of crude oil, NGL and natural gas and the success of our development and exploration activities as well as future acquisitions. 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 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 dividend payouts, supplemented by opportunistic share repurchases. 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.
Capital availability is affected by prevailing conditions in our industry, the global economy, the global banking and financial markets, stakeholder scrutiny of sustainability matters and other factors, many of which are beyond our control. The U.S. Federal Reserve has stabilized interest rates, however the potential for such rates to decrease or increase creates 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.
Commodity derivative contracts. 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. See Note 6—Derivative Instruments and “Item 3. Quantitative and Qualitative Disclosures about Market Risk” for additional information.
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Commitments. We also have contracts which include provisions for the delivery, transport or purchase of a minimum volume of crude oil, NGL, 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. The estimable future commitments under these agreements were $587.3 million as of March 31, 2026. 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, NGL and natural gas from third parties to satisfy our minimum volume commitments. See “Item 1. Financial Statements (Unaudited)—Note 16—Commitments and Contingencies” and “Item 8. Financial Statements and Supplementary Data—Note 20—Commitments and Contingencies” in our 2025 Annual Report for additional information on our volume delivery commitments.
Long-term debt
Our long-term debt consists of a senior secured revolving line of credit that is generally used to support our working capital requirements, $750.0 million of 6.000% senior unsecured notes and $750.0 million of 6.750% senior unsecured notes.
Senior secured revolving line of credit. As of March 31, 2026, we had a senior secured revolving credit facility (the “Credit Facility”) with a borrowing base of $2.75 billion and an aggregate amount of elected commitments of $2.0 billion that is due November 3, 2029. We had no net borrowings outstanding and $32.6 million of outstanding letters of credit, resulting in an unused borrowing base capacity of $1,967.4 million as of March 31, 2026. Additionally, we are permitted to incur term loans in addition to the revolving loans provided under the Credit Facility. The semi-annual redetermination of our borrowing base was completed in May 2026, which reaffirmed the borrowing base and the aggregate elected commitment at $2.75 billion and $2.0 billion, respectively. The next redetermination is scheduled for October 2026.
For the three months ended March 31, 2026, the weighted average interest rate incurred on borrowings under the Credit Facility was 7.50% compared to 6.42% for the three months ended March 31, 2025.
We were in compliance with the financial covenants in the Credit Facility at March 31, 2026. See “Item 1. Financial Statements (Unaudited)—Note 10—Long-Term Debt” for additional information.
Senior unsecured notes. As of March 31, 2026, we had $750.0 million of 6.000% senior unsecured notes (the “2030 Senior Notes”) that mature on October 1, 2030 and $750.0 million of 6.750% senior unsecured notes (the “2033 Senior Notes”) that mature on March 15, 2033. Interest on the 2030 Senior Notes is payable semi-annually on April 1 and October 1 of each year, and interest on the 2033 Senior Notes is payable semi-annually on March 15 and September 15 of each year. See “Item 1. Financial Statements (Unaudited)—Note 10—Long-Term Debt” for additional information.
Cash Flows
Our cash flows for the three months ended March 31, 2026 and 2025 are presented below:
| Three Months Ended March 31, | |||||||||||
| 2026 | 2025 | ||||||||||
| (In thousands) | |||||||||||
Net cash provided by operating activities | $ | 507,467 | $ | 656,893 | |||||||
Net cash used in investing activities | (324,405) | (292,270) | |||||||||
Net cash used in financing activities | (146,791) | (365,819) | |||||||||
Increase (decrease) in cash and cash equivalents | $ | 36,271 | $ | (1,196) | |||||||
Cash flows provided by operating activities
Our net cash flows provided by operating activities are primarily impacted by commodity prices, production volumes and operating costs. Net cash provided by operating activities was $507.5 million for the three months ended March 31, 2026. The decrease in net cash provided by operating activities of $149.4 million as compared to the three months ended March 31, 2025 was primarily due to a decrease in our working capital, decrease in NGL revenues primarily due to lower NGL realized prices, increase in production taxes primarily driven by increased crude oil sales and increase in LOE, partially offset by increases in crude oil and natural gas revenues. See “Results of Operations” above for additional information.
Working Capital. Our working capital is primarily impacted by 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 $165.7 million during the three months ended March 31, 2026 and increased net cash flows from operating activities by $37.2 million during the three months ended March 31, 2025. Changes in working capital associated with our capital expenditure activities and settlements of outstanding commodity derivative instruments impact our cash flows from investing activities.
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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 $1,967.4 million at March 31, 2026, and excludes current hedge assets, which were $1.2 million at March 31, 2026. For purposes of the Current Ratio, the Credit Facility’s definition of total current liabilities excludes current hedge liabilities, of which there were $154.4 million at March 31, 2026.
Cash flows used in investing activities
For the three months ended March 31, 2026, net cash used in investing activities of $324.4 million was primarily attributable to capital expenditures incurred to develop our oil and gas properties of $351.3 million and acquisitions and leasehold costs of $5.0 million, partially offset by the receipt of the 2025 contingent consideration earn-out payment of $25.0 million. For the three months ended March 31, 2025, net cash used in investing activities of $292.3 million was primarily attributable to capital expenditures incurred to develop our oil and gas properties of $308.9 million and $17.9 million paid primarily for acreage in the Williston Basin, partially offset by the receipt of the 2024 contingent consideration earn-out payment of $25.0 million.
Cash flows used in financing activities
For the three months ended March 31, 2026, the net cash used in financing activities of $146.8 million was primarily attributable to dividends paid to shareholders of $74.2 million, payments to repurchase our common stock of $67.7 million, and payments for income tax withholdings on vested equity-based compensation awards of $4.3 million. For the three months ended March 31, 2025, net cash used in financing activities of $365.8 million was primarily attributable to repayments of the 2026 Senior Notes totaling $401.4 million, repayments under the Credit Facility of $1,445.0 million, partially offset by borrowings of $1,060.0 million, resulting in net repayments under the Credit Facility of $385.0 million, payments to repurchase our common stock of $215.2 million, dividends paid to shareholders of $86.5 million, payments for income tax withholdings on vested equity-based compensation awards of $14.4 million and payment of debt issuance costs of $13.0 million made primarily in connection with the issuance of the 2033 Senior Notes. These uses of cash were partially offset by proceeds from the issuance of the 2033 Senior Notes of $750.0 million.
Capital Expenditures
Our capital expenditures are summarized in the following table for the period presented:
| Three Months Ended | |||||
| March 31, 2026 | |||||
| (In thousands) | |||||
E&P(1) | $ | 330,571 | |||
| Midstream | 14,203 | ||||
Other(2) | 113 | ||||
| Capitalized interest | 933 | ||||
Total capital expenditures(3) | $ | 345,820 | |||
__________________
(1)E&P capital expenditures include approximately $3.0 million of non-operated capital expenditures related to certain non-operated divested assets that were reimbursable for the three months ended March 31, 2026.
(2)Other capital expenditures include items such as corporate and administrative capital.
(3)Total capital expenditures reflected in the table above differ from the amounts for capital expenditures shown in the statements of cash flows in our condensed consolidated financial statements because amounts reflected in the table above 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.
Acquisitions
Acquisitions and leasehold costs were $5.0 million for the three months ended March 31, 2026.
Dividends
On May 5, 2026, we declared a base cash dividend of $1.30 per share of common stock. The dividend will be payable on June 5, 2026 to shareholders of record as of May 20, 2026. See “Item 1. Financial Statements (Unaudited)—Note 14—Stockholders’ Equity” for additional information.
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See “Part I. Item 1.—Business—Business Strategy” in our 2025 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, 2026, we repurchased 559,064 shares of common stock at a weighted average price of $126.53 per common share for a total cost of $70.7 million under our $1.0 billion share repurchase program authorized by our Board of Directors in August 2025. As of March 31, 2026, there was $881.4 million of capacity remaining under this share repurchase program.
During the three months ended March 31, 2025, we repurchased 1,994,496 shares of common stock under a previous share repurchase program at a weighted average price of $108.54 per common share for a total cost of $216.5 million.
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 2025 Annual Report.
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 2025 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, NGL 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, NGL and natural gas have been volatile over the last several years, with heightened volatility over the past year, 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, NGL 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, 2026 was a net liability position of $169.8 million. A 10% increase in crude oil prices would increase the fair value of this unrealized derivative liability position by approximately $153.1 million, while a 10% decrease in crude oil prices would reduce the fair value of this unrealized derivative liability position by approximately $147.5 million. The fair value of our unrealized natural gas derivative positions at March 31, 2026 was a net asset position of $23.0 million. A 10% increase in natural gas prices would reduce the fair value of this unrealized derivative asset position by approximately $18.0 million, while a 10% decrease in natural gas prices would increase the fair value of this unrealized derivative asset position by approximately $11.2 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.
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Interest rate risk. At March 31, 2026, we had $750.0 million of senior unsecured notes at a fixed interest rate of 6.000% per annum and $750.0 million of senior unsecured notes at a fixed interest rate of 6.750% per annum. At March 31, 2026, we had no borrowings and $32.6 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, an ABR Loan or a Swingline Loan (each as defined in the Credit Facility). As of March 31, 2026, there were no borrowings outstanding under our Credit Facility; therefore, a 100-basis point increase in interest rates would have no impact on our annual interest expense. See “Item 1. Financial Statements (Unaudited)—Note 10—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.
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, 2026, our credit losses on joint interest receivables were $2.5 million. 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 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, 2026. 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, 2026.
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, 2026 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.
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PART II — OTHER INFORMATION
Item 1. — Legal Proceedings
See “Part I, Item 1. — Financial Statements (Unaudited)—Note 16—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 Quarterly Report on Form 10-Q and in 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 2025 Annual Report. There have been no material changes in our risk factors from those described in our 2025 Annual Report.
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, 2026:
| Period | Total Number of Shares Exchanged or Purchased(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) | ||||||||||||||||||||||
| January 1 – January 31, 2026 | 24,068 | $ | 94.76 | — | $ | 952,169,220 | ||||||||||||||||||||
| February 1 – February 28, 2026 | 47,090 | 105.73 | 28,027 | 949,169,851 | ||||||||||||||||||||||
| March 1 – March 31, 2026 | 531,597 | 127.54 | 531,037 | 881,431,900 | ||||||||||||||||||||||
| Total | 602,755 | $ | 124.53 | 559,064 | ||||||||||||||||||||||
___________________
(1)During the first quarter of 2026, we withheld 43,691 shares of common stock to satisfy tax withholding obligations upon vesting of certain equity-based awards.
(2)In August 2025, our Board of Directors authorized a new share repurchase program covering up to $1.0 billion of common stock. During the first quarter of 2026, we repurchased 559,064 shares of our common stock at a weighted average price of $126.53 per common share for a total cost of $70.7 million, excluding accrued excise tax of $0.6 million, under this share repurchase program.
Item 5. — Other Information
Rule 10b5-1 trading arrangements. During the fiscal quarter ended March 31, 2026, none of our directors or officers (as defined in Rule 16a-1 under the Exchange Act) adopted or terminated
•Daniel E. Brown , the Company’s President & Chief Executive Officer and Director , adopted a new “Rule 10b5-1 trading arrangement” on March 16, 2026 to sell up to 60,000 vested shares of the Company’s common stock, through March 16, 2027 , subject to certain limit prices and earlier termination in accordance with its terms;
•Michael H. Lou , the Company’s Executive Vice President, Chief Strategy Officer and Chief Commercial Officer , adopted a new “Rule 10b5-1 trading arrangement” on March 16, 2026 to sell up to 30,000 vested shares of the Company’s common stock, through March 10, 2027 , subject to certain limit prices and earlier termination in accordance with its terms.
The Rule 10b5-1 trading arrangements described above were adopted and approved in accordance with the Company’s Insider Trading Policy.
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Item 6. — Exhibits
| Exhibit No. | Description of Exhibit | |||||||
10.1 | Form of Notice of Grant for Market Stock Units (Absolute TSR) with form of associated Market Stock Unit Agreement attached thereto. | |||||||
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. | |||||||
| 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.
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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 7, 2026 | 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) | |||||||||||||||||||||||
| By: | /s/ Lara J. Kroll | ||||||||||||||||||||||
| Lara J. Kroll | |||||||||||||||||||||||
| Senior Vice President and Chief Accounting Officer (Principal Accounting Officer) | |||||||||||||||||||||||
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FAQ
How did Chord Energy (CHRD) perform financially in Q1 2026?
Chord Energy generated net income of $108.6 million on total revenues of $1.67 billion in Q1 2026. Operating income was $333.2 million, and net cash provided by operating activities reached $507.5 million, supporting capital spending and shareholder returns.
What were Chord Energy’s production levels in Q1 2026?
Chord Energy’s Q1 2026 production averaged 275,615 Boepd, with crude oil at 158,027 Bopd. Total volumes were 24.8 million Boe, reflecting its focus on liquids-rich Williston Basin assets and supporting higher revenue from stronger commodity pricing.
Why did Chord Energy’s Q1 2026 net income decline versus Q1 2025?
Net income declined to $108.6 million from $219.8 million primarily because of a $241.5 million net loss on derivative instruments. This included a large unrealized loss from higher forward crude prices, which offset benefits from stronger commodity prices and slightly higher production.
How much cash flow and capital spending did Chord Energy report for Q1 2026?
Chord Energy reported $507.5 million of net cash provided by operating activities in Q1 2026. Capital expenditures were $344.9 million (excluding capitalized interest), covering drilling and development activity while still leaving capacity for dividends, share repurchases and balance sheet strength.
What is Chord Energy’s debt and liquidity position as of March 31, 2026?
As of March 31, 2026, Chord Energy had $1.48 billion of long-term senior notes outstanding and no borrowings on its revolving credit facility. With $225.8 million of cash and $1.97 billion of unused revolver capacity, overall liquidity remained substantial.