Crescent Energy (NYSE: CRGY) lifts Q2 profit as it reshapes debt
Crescent Energy Company reported strong Q2 2026 results, with total revenues of $1.39 billion (in thousands) versus $0.90 billion a year earlier, driven mainly by oil revenue of $1.23 billion. Income from operations rose to $581.0 million, and net income attributable to Crescent increased to $492.8 million ($1.49 basic EPS) from $153.2 million ($0.61).
For the first six months of 2026, revenues reached $2.58 billion and income from operations $908.5 million, but large unrealized losses on commodity derivatives and higher interest expense produced net income of $72.9 million, below the prior‑year period’s $151.1 million, despite stronger operating cash flow of $1.12 billion.
At June 30 2026, total assets were $12.0 billion and long‑term debt $5.17 billion, down from $5.52 billion at year‑end. The company issued $690.0 million of 2.750% Convertible Senior Notes due 2031, redeemed its 9.250% 2028 Notes, added a new royalty‑focused credit facility, and maintained an expanded $400.0 million stock repurchase authorization with about $336.0 million remaining.
Positive
- Q2 2026 net income attributable to Crescent rose to $492.8 million from $153.2 million a year earlier, with basic EPS increasing to $1.49 from $0.61.
- Operating cash flow for the first half of 2026 increased to $1.12 billion (in thousands), supporting significant capital spending on development and acquisitions while also allowing a reduction in long‑term debt to $5.17 billion.
Negative
- For the first half of 2026, a total loss on derivatives of $524.7 million and higher interest expense reduced net income to $72.9 million, below the prior‑year period’s $151.1 million despite higher revenues and income from operations.
Filing Explained
Completed acquisition and incentive settlements increased common shares, while convertible notes add conditional future share-settlement exposure.
Crescent Energy’s unaudited Form 10-Q updates interim financial statements and liquidity and records completed equity issuances from the Vital Energy merger and manager incentive settlements. Those issuances increase the share base for existing common holders.
Crescent issued 73.3 million Class A shares in the Vital merger, and another 2.1 million Class A shares were issued when two manager incentive tranches settled. Additional shares increase the total share count and reduce an existing holder’s percentage ownership absent offsetting changes.
The $690.0 million of 2.750% convertible notes are debt obligations now, with conversion permitted only in specified circumstances before December 15, 2030 and at holders’ election thereafter; Crescent may settle conversions in cash, shares, or a combination. The filing records the notes’ issuance, not a conversion.
At
As a subsequent milestone, Crescent elected in July 2026 to redeem the remaining 7.750% 2029 Notes for
Key Figures
Q2 2026 Total Revenues: $1,394,954 (in thousands)
Q2 2026 Net Income Attributable to Crescent: $492,765 (in thousands)
H1 2026 Net Cash Provided by Operating Activities: $1,115,979 (in thousands)
+5 more
8 metrics
Q2 2026 Total Revenues
$1,394,954 (in thousands)
Three months ended June 30, 2026
Q2 2026 Net Income Attributable to Crescent
$492,765 (in thousands)
Three months ended June 30, 2026
H1 2026 Net Cash Provided by Operating Activities
$1,115,979 (in thousands)
Six months ended June 30, 2026
H1 2026 Loss on Derivatives
$524,708 (in thousands)
Six months ended June 30, 2026, gain (loss) on derivatives
Total Assets
$12,008,376 (in thousands)
Balance sheet at June 30, 2026
Long-Term Debt
$5,166,022 (in thousands)
Balance sheet at June 30, 2026
2031 Convertible Notes Issuance
$690,000
Aggregate principal amount of 2.750% Convertible Senior Notes due 2031 issued in March 2026
Stock Repurchase Authorization Remaining
$336.0 million
Remaining under $400.0 million program as of June 30, 2026
Key Terms
reserve-based revolving credit facility, three-way collars, contingent earn-out consideration, capped call transactions, +2 more
6 terms
reserve-based revolving credit facility financial
"we enter into derivative contracts with lenders under our reserves-based revolving credit facility"
A reserve-based revolving credit facility is a bank loan line for natural‑resource companies where the amount they can borrow is tied to the value of their proven reserves and can be drawn, repaid and redrawn over time. Think of it like a home equity line that uses oil, gas or mineral reserves as collateral; investors watch it because changes in reserve estimates or commodity prices can quickly raise borrowing costs, trigger limits or strain cash flow.
three-way collars financial
"A three-way collar adds a secondary lower price below the fixed floor price"
A three-way collar is an investment setup that combines owning a stock with three option contracts arranged to create a protected price range: one option limits losses, one caps gains, and a third adjusts the trade’s cost or protection level. Think of it like insuring a car where you set a minimum payout if it’s damaged, agree to accept a fixed resale price if it’s sold, and add a rider to lower your premium or tweak coverage. For investors, it’s a cost-conscious way to limit downside while accepting some cap on upside, useful for managing risk without fully selling a holding.
contingent earn-out consideration financial
"up to $170.0 million in contingent earn-out consideration may be paid in fiscal years 2026 and 2027"
Contingent earn-out consideration is extra money a buyer may pay a seller after a deal closes only if the acquired business hits agreed future targets (for example sales, profits, or milestones). For investors it matters because it adjusts the effective price paid, shifts risk between buyer and seller, can change future cash flows and accounting, and creates incentives tied to the business’s performance — like receiving a bonus only if certain goals are met.
capped call transactions financial
"we paid $56.6 million to enter into capped call transactions with certain financial institution counterparties"
Capped call transactions are agreements where investors buy options that give them the chance to benefit if a stock's price goes up, but with a limit on how much they can gain. This helps protect them from paying too much if the stock's price rises a lot, similar to having a maximum limit on a reward. They matter because they help investors manage risk while still allowing some upside potential.
asset retirement obligations financial
"Our ARO liabilities are based on our net ownership in wells and facilities"
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.
Up-C structure financial
"our corporate structure had been simplified through the elimination of the Company’s Up-C structure"
An up‑C structure is a two‑layer company setup often used in public listings where the operating business is owned by a partnership and public investors buy shares of a separate corporation that holds partnership interests. Think of it like buying stock in a holding company while the original owners keep a special stake in the business that preserves tax benefits. It matters because it can create tax advantages for sellers but adds tax complexity for investors, different cash‑flow claims and potential future dilution.
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FAQ
How did Crescent Energy (CRGY) perform financially in Q2 2026?
Crescent Energy generated $1.39 billion in Q2 2026 revenues and net income attributable to Crescent of $492.8 million, or $1.49 basic EPS. Oil revenue was the main driver, at $1.23 billion, and income from operations reached $581.0 million.
Why was Crescent Energy (CRGY) first-half 2026 net income lower despite higher revenues?
First-half 2026 revenues rose to $2.58 billion and income from operations to $908.5 million, but a $524.7 million loss on derivatives and higher interest expense cut net income to $72.9 million, compared with $151.1 million in the prior‑year period.
What is Crescent Energy’s (CRGY) debt position as of June 30, 2026?
As of June 30, 2026, Crescent Energy had $5.17 billion of long‑term debt. This includes $690.0 million of 2.750% Convertible Senior Notes due 2031, multiple senior note issues, and borrowings of $275.5 million under a new Crescent Royalty Finance credit facility.
What major acquisitions and divestitures affect Crescent Energy (CRGY)?
Key recent moves include the Vital Energy Merger, with 73.3 million Class A shares issued, 2026 Eagle Ford minerals acquisitions totaling about $357.8 million, the 2025 Ridgemar Acquisition, and non‑core divestitures in 2025 generating consideration in excess of $900.0 million.
What is the status of Crescent Energy’s (CRGY) stock repurchase program?
The Board expanded the stock repurchase program to $400.0 million and extended it indefinitely. By June 30, 2026, Crescent had repurchased 4.1 million Class A shares for $33.5 million, leaving approximately $336.0 million available under the authorization.
How do hedging and contingent payments impact Crescent Energy (CRGY)?
Crescent uses swaps and collars, leading to a first-half 2026 cash outflow on derivatives of $343.2 million and a total derivatives loss of $524.7 million. It also paid $45.0 million under Ridgemar contingent earn‑out arrangements tied to NYMEX WTI prices.
UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-Q
(Mark One)
| QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 | |||||
For the quarterly period ended June 30, 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 001-41132
(Exact name of registrant as specified in its charter)
(State or other jurisdiction of incorporation or organization) | (I.R.S. Employer Identification Number) | |||||||
(713 ) 332-7001
(Address, including zip code, and telephone number, including area code, of registrant’s principal executive offices)
Securities registered pursuant to Section 12(b) of the Act:
| Title of each class | Trading Symbol | 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 (“Exchange Act”) 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 ☒
As of July 31, 2026, there were approximately 330,403,696 shares outstanding of the registrant’s Class A common stock.
Table of Contents
Glossary | 2 | ||||
Cautionary Statement Regarding Forward-Looking Statements | 3 | ||||
Part I - Financial Information | |||||
Item 1. Financial Statements | 5 | ||||
Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations | 33 | ||||
Item 3. Quantitative and Qualitative Disclosures About Market Risk | 54 | ||||
Item 4. Controls and Procedures | 56 | ||||
Part II - Other Information | |||||
Item 1. Legal Proceedings | 57 | ||||
Item 1A. Risk Factors | 57 | ||||
Item 2. Unregistered Sales of Equity Securities and Use of Proceeds | 58 | ||||
Item 3. Defaults Upon Senior Securities | 58 | ||||
Item 4. Mine Safety Disclosures | 58 | ||||
Item 5. Other Information | 58 | ||||
Item 6. Exhibits | 58 | ||||
Signatures | 62 | ||||
1
GLOSSARY
The following are abbreviations and definitions of certain terms used in this document, which are commonly used in the oil and natural gas industry:
Barrel or Bbl — One stock tank barrel, or 42 United States gallons liquid volume.
Boe — One barrel of oil equivalent determined using the ratio of six Mcf of natural gas to one barrel of crude oil or condensate.
Boe/d — Barrels of oil equivalent per day.
Brent — the reference price paid in U.S. dollars for a barrel of light sweet crude oil produced from the Brent field in the UK sector of the North Sea.
Btu — British thermal unit, which is the heat required to raise the temperature of a one-pound mass of water one degree Fahrenheit.
Henry Hub — Henry Hub is the major exchange for pricing natural gas futures on the New York Mercantile Exchange. It is frequently referred to as the Henry Hub index.
MBbls — One thousand Bbls or other liquid hydrocarbons.
MBbl/d — One thousand Bbls or other liquid hydrocarbons per day.
MBoe — One thousand Boe.
MBoe/d — One thousand Boe per day.
Mcf — One thousand cubic feet of natural gas.
Mcf/d — One thousand Mcf per day.
MMBoe — One million Boe.
MMBtu — One million Btus.
MMcf — One million Mcf.
MMcf/d — One million Mcf per day.
NYMEX — The New York Mercantile Exchange.
Proved reserves — Proved reserves are those quantities of oil and natural gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible—from a given date forward, from known reservoirs and under existing economic conditions, operating methods and government regulations—prior to the time at which contracts providing the right to operate expire, unless evidence indicates 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.
Working interest — The operating interest that gives the owner the right to drill, produce and conduct operating activities on the property and a share of production.
WTI — A light crude oil produced in the United States with an American Petroleum Institute gravity of approximately 38-40 and sulfur content of approximately 0.3%.
2
Cautionary Statement Regarding Forward-Looking Statements
The information in this Quarterly Report on Form 10-Q (this “Quarterly Report”) contains or incorporates by reference information that includes or is based upon “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 facts, included herein concerning, among other things, planned capital expenditures, increases in oil, natural gas and natural gas liquids (“NGLs”) production, the number of anticipated wells to be drilled or completed after the date hereof, future cash flows and borrowings, pursuit of potential acquisition opportunities, our financial position, business strategy and other plans and objectives for future operations, are forward-looking statements. These forward-looking statements are identified by their use of terms and phrases such as “may,” “expect,” “estimate,” “project,” “plan,” “believe,” “intend,” “achievable,” “anticipate,” “will,” “continue,” “potential,” “should,” “could,” and similar terms and phrases. Although we believe that the expectations reflected in these forward-looking statements are reasonable, they do involve certain assumptions, risks and uncertainties. Our results could differ materially from those anticipated in these forward-looking statements as a result of certain factors, including, among others:
•commodity price volatility;
•our business strategy;
•our ability to integrate operations or realize any anticipated operational or corporate synergies and other benefits of our acquisitions, including our acquisition of Vital Energy, Inc. (“Vital” and such acquisition, the “Vital Energy Merger”);
•the risk that the Vital Energy Merger may not be accretive, and may be dilutive, to our earnings per share, which may negatively affect the market price of our Class A Common Stock (as defined below);
•our ability to identify and select opportunities for additional acquisitions, dispositions and other strategic transactions;
•capital requirements and uncertainty of obtaining additional funding on terms acceptable to us;
•risks and restrictions related to our debt agreements and the level of our indebtedness;
•our reliance on the Manager (as defined below) as our external manager;
•our hedging strategy and results;
•realized oil, natural gas and NGL prices;
•political and economic conditions and events in the U.S. and in foreign oil, natural gas and NGL producing countries, including embargoes, political and regulatory changes implemented by the Trump Administration, continued hostilities in the Middle East, including the Israel-Hamas conflict and the conflict with Iran, and other sustained military campaigns, the armed conflict in Ukraine and associated economic sanctions on Russia, conditions and developments in South America and in China and acts of terrorism or sabotage;
•changes in tariffs, trade barriers, price and exchange controls and other regulatory requirements, including such changes that may be implemented by the Trump Administration and foreign governments;
•general economic conditions, including the impact of inflation, elevated interest rates and associated changes in monetary policy;
•the impact of central bank policy actions, including any changes in its policy priorities, and disruptions in the banking industry and in the capital markets;
•the severity and duration of public health crises and any resultant impact on governmental actions, commodity prices, supply and demand considerations, and storage capacity;
•timing and amount of our future production of oil, natural gas and NGLs;
•a decline in oil, natural gas and NGL production, and the impact of general economic conditions on the demand for oil, natural gas and NGLs and the availability of capital;
•unsuccessful drilling and completion activities and the possibility of resulting write downs;
•our ability to meet our proposed drilling schedule and to successfully drill wells that produce oil, natural gas and NGLs in commercially viable quantities;
•shortages of equipment, supplies, services and qualified personnel and increased costs for such equipment, supplies, services and personnel, including any delays and/or supply chain disruptions due to continued hostilities in the Middle East and international trade rules and regulations;
•adverse variations from estimates of reserves, production, prices and expenditure requirements, and our inability to replace our reserves through exploration and development activities;
•incorrect estimates associated with properties we acquire relating to estimated proved reserves, the presence or recoverability of estimated oil, natural gas and NGL reserves and the actual future production rates and associated costs of such acquired properties;
•hazardous, risky drilling operations, including those associated with the employment of horizontal drilling techniques, and adverse weather and environmental conditions;
•limited control over non-operated properties;
•title defects to our properties and inability to retain our leases;
•our ability to successfully develop our large inventory of undeveloped acreage;
3
•our ability to retain key members of our senior management and key technical employees;
•our ability to successfully execute our growth strategies and risks relating to managing our growth;
•impact of environmental, occupational health and safety, and other governmental regulations, and of current or pending legislation that may negatively impact the future production of oil and natural gas or drive the substitution of renewable forms of energy for oil and natural gas;
•federal and state regulations and laws, including the One Big Beautiful Bill Act (the “OBBBA”), the Inflation Reduction Act of 2022 (the “IRA 2022”) and any impact thereon by the OBBBA, the IRA 2022, taxes, tariffs and international trade, safety and the protection of the environment;
•our ability to predict and manage the effects of actions of the Organization of Petroleum Exporting Countries and its allies (“OPEC+”) and agreements to set and maintain production levels, including compliance with, changes to or departures from such arrangements, the effects of which may be exacerbated by the continued hostilities in the Middle East, including the conflict with Iran, and developments in Venezuela and other major oil-producing countries;
•information technology failures or cyberattacks;
•changes in tax laws and the impact of those changes on us;
•effects of competition; and
•seasonal weather conditions.
We caution you that these forward-looking statements are subject to all of the risks and uncertainties incident to the development, production, gathering and sale of oil, natural gas and NGLs, most of which are difficult to predict and many of which are beyond our control. These risks include, but are not limited to, commodity price volatility, inflation, lack of availability and cost of drilling and production equipment and services, project construction delays, environmental risks, drilling and other operating risks, lack of availability or capacity of midstream gathering and transportation infrastructure, regulatory changes, including the impact of tariffs and international trade, the uncertainty inherent in estimating reserves and in projecting future rates of production, cash flow and access to capital, including restrictions due to elevated interest rates, the timing of development expenditures and the other risks described under “Risk Factors” in this Quarterly Report, in “Item 1A. Risk Factors” in our Annual Report on Form 10-K for the year ended December 31, 2025 (“Annual Report”), our Quarterly Report on Form 10-Q for the three months ended March 31, 2026 and our other reports and registration statements filed from time to time with the Securities and Exchange Commission.
Reserve engineering is a process of estimating underground accumulations of hydrocarbons that cannot be measured in an exact way. The accuracy of any reserve estimates depends on the quality of available data, the interpretation of such data and price and cost assumptions made by reserve engineers. In addition, the results of drilling, testing and production activities may justify revisions of estimates that were made previously. If significant, such revisions would change the schedule of any further production and development program. Accordingly, reserve estimates may differ significantly from the quantities of oil, natural gas and NGLs that are ultimately recovered.
Should one or more of the risks or uncertainties described in this Quarterly Report occur, or should underlying assumptions prove incorrect, our actual results and plans could differ materially from those expressed in any forward-looking statements. All forward-looking statements, expressed or implied, included in this Quarterly Report are expressly qualified in their entirety by this cautionary statement. This cautionary statement should also be considered in connection with any subsequent written or oral forward-looking statements that we or persons acting on our behalf may issue. Except as otherwise required by applicable law, we disclaim any duty to update any forward-looking statements, all of which are expressly qualified by the statements in this section, to reflect events or circumstances after the date of this Quarterly Report.
4
Part I – Financial Information
Item 1. Financial Statements
| CRESCENT ENERGY COMPANY | |||||||||||
CONDENSED CONSOLIDATED BALANCE SHEETS | |||||||||||
| (Unaudited) | |||||||||||
| (in thousands, except share data) | |||||||||||
| June 30, 2026 | December 31, 2025 | ||||||||||
| ASSETS | |||||||||||
| Current assets: | |||||||||||
| Cash and cash equivalents | $ | $ | |||||||||
| Restricted cash | |||||||||||
| Accounts receivable, net | |||||||||||
| Accounts receivable – affiliates | |||||||||||
| Derivative assets – current | |||||||||||
| Prepaid expenses | |||||||||||
| Other current assets | |||||||||||
| Total current assets | |||||||||||
| Property, plant and equipment: | |||||||||||
| Oil and natural gas properties at cost, successful efforts method | |||||||||||
| Proved | |||||||||||
| Unproved | |||||||||||
| Oil and natural gas properties at cost, successful efforts method | |||||||||||
| Field and other property and equipment, at cost | |||||||||||
| Total property, plant and equipment | |||||||||||
| Less: accumulated depreciation, depletion, amortization and impairment | ( | ( | |||||||||
| Property, plant and equipment, net | |||||||||||
| Derivative assets – noncurrent | |||||||||||
| Investments in equity affiliates | |||||||||||
Deferred tax asset | |||||||||||
| Other assets | |||||||||||
| TOTAL ASSETS | $ | $ | |||||||||
| The accompanying notes to financial statements are an integral part of these condensed consolidated financial statements | |||||||||||
5
| CRESCENT ENERGY COMPANY | |||||||||||
CONDENSED CONSOLIDATED BALANCE SHEETS | |||||||||||
| (Unaudited) | |||||||||||
| (in thousands, except share data) | |||||||||||
| June 30, 2026 | December 31, 2025 | ||||||||||
| LIABILITIES AND EQUITY | |||||||||||
| Current liabilities: | |||||||||||
| Accounts payable and accrued liabilities | $ | $ | |||||||||
| Accounts payable – affiliates | |||||||||||
| Derivative liabilities – current | |||||||||||
| Financing lease obligations – current | |||||||||||
| Other current liabilities | |||||||||||
| Total current liabilities | |||||||||||
| Long-term debt | |||||||||||
| Derivative liabilities – noncurrent | |||||||||||
| Asset retirement obligations | |||||||||||
| Deferred tax liability | |||||||||||
| Financing lease obligations – noncurrent | |||||||||||
| Other liabilities | |||||||||||
| Total liabilities | |||||||||||
| Commitments and contingencies (Note 9) | |||||||||||
| Equity: | |||||||||||
Class A common stock, $ | |||||||||||
Class B common stock, $ | |||||||||||
Preferred stock, $ | |||||||||||
Treasury stock, at cost; | ( | ( | |||||||||
| Additional paid-in capital | |||||||||||
| Retained earnings (accumulated deficit) | |||||||||||
| Noncontrolling interests | |||||||||||
| Total equity | |||||||||||
| TOTAL LIABILITIES AND EQUITY | $ | $ | |||||||||
The accompanying notes to financial statements are an integral part of these condensed consolidated financial statements
6
CRESCENT ENERGY COMPANY
CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS
(Unaudited)
(in thousands, except per share amounts)
| Three Months Ended June 30, | Six Months Ended June 30, | ||||||||||||||||||||||
| 2026 | 2025 | 2026 | 2025 | ||||||||||||||||||||
| Revenues: | |||||||||||||||||||||||
| Oil | $ | $ | $ | $ | |||||||||||||||||||
| Natural gas | |||||||||||||||||||||||
| Natural gas liquids | |||||||||||||||||||||||
| Midstream and other | |||||||||||||||||||||||
| Total revenues | |||||||||||||||||||||||
| Expenses: | |||||||||||||||||||||||
| Lease and asset operating expense | |||||||||||||||||||||||
| Workover expense | |||||||||||||||||||||||
| Gathering, processing and transportation | |||||||||||||||||||||||
| Production and other taxes | |||||||||||||||||||||||
| Depreciation, depletion and amortization | |||||||||||||||||||||||
| Impairment of oil and natural gas properties | |||||||||||||||||||||||
| Exploration expense | |||||||||||||||||||||||
| Midstream and other operating expense | |||||||||||||||||||||||
| General and administrative expense | |||||||||||||||||||||||
| (Gain) loss on sale of assets | ( | ( | ( | ( | |||||||||||||||||||
| Total expenses | |||||||||||||||||||||||
| Income (loss) from operations | |||||||||||||||||||||||
| Other income (expense): | |||||||||||||||||||||||
| Gain (loss) on derivatives | ( | ||||||||||||||||||||||
| Interest expense | ( | ( | ( | ( | |||||||||||||||||||
| Loss from extinguishment of debt | ( | ||||||||||||||||||||||
| Other income (expense) | |||||||||||||||||||||||
| Income (loss) from equity affiliates | |||||||||||||||||||||||
| Total other income (expense) | ( | ( | |||||||||||||||||||||
| Income (loss) before taxes | |||||||||||||||||||||||
| Income tax benefit (expense) | ( | ( | ( | ( | |||||||||||||||||||
| Net income (loss) | |||||||||||||||||||||||
| Less: net (income) loss attributable to noncontrolling interests | ( | ( | ( | ( | |||||||||||||||||||
| Less: net (income) loss attributable to redeemable noncontrolling interests | ( | ( | |||||||||||||||||||||
| Net income (loss) attributable to Crescent Energy | $ | $ | $ | $ | |||||||||||||||||||
| Net income (loss) per share: | |||||||||||||||||||||||
| Class A common stock – basic | $ | $ | $ | $ | |||||||||||||||||||
| Class A common stock – diluted | $ | $ | $ | $ | |||||||||||||||||||
| Class B common stock – basic and diluted | $ | $ | $ | $ | |||||||||||||||||||
| Weighted average shares outstanding: | |||||||||||||||||||||||
| Class A common stock – basic | |||||||||||||||||||||||
| Class A common stock – diluted | |||||||||||||||||||||||
| Class B common stock – basic and diluted | |||||||||||||||||||||||
The accompanying notes to financial statements are an integral part of these condensed consolidated financial statements
7
| CRESCENT ENERGY COMPANY | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| (Unaudited) | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| (in thousands) | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Crescent Energy Company | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Class A Common Stock | Class B Common Stock | Series I Preferred Stock | Treasury Stock | Additional Paid-in Capital | Retained Earnings (Accumulated Deficit) | Noncontrolling Interest | Total | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Shares | Amount | Shares | Amount | Shares | Amount | Shares | Amount | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Balance at January 1, 2025 | $ | $ | $ | $ | ( | $ | $ | ( | $ | $ | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Net income (loss) | — | — | — | — | — | — | — | — | — | ( | ( | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Distributions | — | — | — | — | — | — | — | — | — | — | ( | ( | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Dividends | — | — | — | — | — | — | — | — | ( | — | — | ( | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Equity-based compensation | — | — | — | — | — | — | — | — | — | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Change in deferred taxes related to basis in OpCo | — | — | — | — | — | — | — | — | ( | — | — | ( | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Change in equity associated with the 2025 Class A Redemption | — | ( | — | — | — | — | — | — | — | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Changes in equity associated with the Ridgemar Acquisition | — | — | — | — | — | — | — | — | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Repurchases of Class A common stock | ( | — | — | — | — | — | ( | — | — | — | ( | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Balance at March 31, 2025 | $ | $ | $ | $ | ( | $ | $ | ( | $ | $ | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Net income (loss) | — | — | — | — | — | — | — | — | — | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Distributions | — | — | — | — | — | — | — | — | — | — | ( | ( | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Dividends | — | — | — | — | — | — | — | — | — | ( | — | ( | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Equity-based compensation | — | — | — | — | — | ( | — | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Change in deferred taxes related to basis in OpCo | — | — | — | — | — | — | — | — | ( | — | — | ( | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Changes in equity associated with the Corporate Simplification | ( | ( | — | — | — | — | — | — | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Cash distributions on behalf of former redeemable noncontrolling interest holders related to income taxes | — | — | — | — | ( | — | — | ( | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Repurchases of Class A common stock | ( | — | — | — | — | — | ( | — | — | — | ( | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Other | — | — | — | — | — | — | — | — | ( | — | — | ( | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Balance at June 30, 2025 | $ | $ | $ | $ | ( | $ | $ | $ | $ | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| The accompanying notes to financial statements are an integral part of these condensed consolidated financial statements | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
8
| CRESCENT ENERGY COMPANY | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| (Unaudited) | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| (in thousands) | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Crescent Energy Company | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Class A Common Stock | Class B Common Stock | Series I Preferred Stock | Treasury Stock | Additional Paid-in Capital | Retained Earnings (Accumulated Deficit) | Noncontrolling Interest | Total | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Shares | Amount | Shares | Amount | Shares | Amount | Shares | Amount | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Balance at January 1, 2026 | $ | $ | $ | $ | ( | $ | $ | $ | $ | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Net income (loss) | — | — | — | — | — | — | — | — | — | ( | ( | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Distributions | — | — | — | — | — | — | — | — | — | — | ( | ( | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Dividends | — | — | — | — | — | — | — | — | ( | — | — | ( | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Equity-based compensation | — | — | — | — | — | ( | — | — | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Changes in equity associated with 2031 Convertible Notes capped call, net of tax impact | — | — | — | — | — | — | — | — | ( | — | — | ( | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Other | — | — | — | — | — | — | — | — | — | — | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Balance at March 31, 2026 | $ | $ | $ | $ | ( | $ | $ | ( | $ | $ | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Net income (loss) | — | — | — | — | — | — | — | — | — | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Distributions | — | — | — | — | — | — | — | — | — | — | ( | ( | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Dividends | — | — | — | — | — | — | — | — | — | ( | — | ( | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Equity-based compensation | — | — | — | — | — | ( | — | — | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Other | — | — | — | — | — | — | — | — | ( | — | — | ( | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Balance at June 30, 2026 | $ | $ | $ | $ | ( | $ | $ | $ | $ | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
The accompanying notes are an integral part of these condensed consolidated financial statements
9
CRESCENT ENERGY COMPANY
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)
(in thousands)
| Six Months Ended June 30, | |||||||||||||||||||||||
| 2026 | 2025 | ||||||||||||||||||||||
| Cash flows from operating activities: | |||||||||||||||||||||||
| Net income (loss) | $ | $ | |||||||||||||||||||||
| Adjustments to reconcile net income (loss) to net cash provided by operating activities | |||||||||||||||||||||||
| Depreciation, depletion and amortization | |||||||||||||||||||||||
| Impairment expense | |||||||||||||||||||||||
| Deferred tax expense (benefit) | |||||||||||||||||||||||
| (Gain) loss on derivatives | ( | ||||||||||||||||||||||
| Net cash (paid) received on settlement of derivatives | ( | ||||||||||||||||||||||
| Non-cash equity-based compensation expense | |||||||||||||||||||||||
| Amortization of debt issuance costs, premium and discount | |||||||||||||||||||||||
| Loss from debt extinguishment | |||||||||||||||||||||||
| (Gain) loss on sale of oil and natural gas properties | ( | ( | |||||||||||||||||||||
| Settlement of acquired derivative contracts | |||||||||||||||||||||||
| Other | ( | ( | |||||||||||||||||||||
| Changes in operating assets and liabilities | ( | ( | |||||||||||||||||||||
| Net cash provided by operating activities | |||||||||||||||||||||||
| Cash flows from investing activities: | |||||||||||||||||||||||
| Development of oil and natural gas properties | ( | ( | |||||||||||||||||||||
| Acquisitions of oil and natural gas properties, net of cash acquired | ( | ( | |||||||||||||||||||||
| Proceeds from the sale of oil and natural gas properties | |||||||||||||||||||||||
| Purchases of restricted investment securities – HTM | ( | ( | |||||||||||||||||||||
| Maturities of restricted investment securities – HTM | |||||||||||||||||||||||
| Other | ( | ||||||||||||||||||||||
| Net cash used in investing activities | ( | ( | |||||||||||||||||||||
| Cash flows from financing activities: | |||||||||||||||||||||||
| Proceeds from the issuance of Senior Notes, after premium, discount and underwriting fees | |||||||||||||||||||||||
2031 Convertible Notes capped call | ( | ||||||||||||||||||||||
| Repurchase of Senior Notes, including extinguishment costs | ( | ||||||||||||||||||||||
| Revolving Credit Facility borrowings | |||||||||||||||||||||||
| Revolving Credit Facility repayments | ( | ( | |||||||||||||||||||||
CRF Credit Facility borrowings | |||||||||||||||||||||||
Proceeds from issuance of CRF Term Loan | |||||||||||||||||||||||
Repayments of CRF Term Loan | ( | ||||||||||||||||||||||
| Payment of debt issuance costs | ( | ( | |||||||||||||||||||||
Settlement of Ridgemar contingent earn-out consideration | ( | ||||||||||||||||||||||
| Dividends | ( | ( | |||||||||||||||||||||
| Distributions to redeemable noncontrolling interests | ( | ||||||||||||||||||||||
| Repurchase of noncontrolling interest | ( | ||||||||||||||||||||||
| Noncontrolling interest distributions | ( | ( | |||||||||||||||||||||
| Cash paid for treasury stock acquired for equity-based compensation tax withholding | ( | ||||||||||||||||||||||
| Repurchases of Class A common stock | ( | ||||||||||||||||||||||
| Other | ( | ||||||||||||||||||||||
| Net cash provided by (used in) financing activities | ( | ||||||||||||||||||||||
| Net change in cash, cash equivalents and restricted cash | ( | ( | |||||||||||||||||||||
| Cash, cash equivalents and restricted cash, beginning of period | |||||||||||||||||||||||
| Cash, cash equivalents and restricted cash, end of period | $ | $ | |||||||||||||||||||||
The accompanying notes are an integral part of these condensed consolidated financial statements
10
CRESCENT ENERGY COMPANY
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)
(Except as noted within the context of each footnote disclosure, the dollar amounts presented in the tabular data within these footnote disclosures are stated in thousands of dollars.)
Unless otherwise stated or the context otherwise indicates, all references to “we,” “us,” “our,” “Crescent” and the “Company” or similar expressions refer to Crescent Energy Company (“CEC”) and its subsidiaries.
NOTE 1 – Organization and Basis of Presentation
Organization
Crescent is a differentiated U.S. energy company committed to delivering value through a disciplined, returns-driven growth through acquisition strategy and consistent return of capital. Our long-life, balanced portfolio combines significant cash flow from stable production with deep, high-quality development inventory. Our activities are focused in the Eagle Ford, Permian Basin and Uinta Basin, and we own minerals and royalty interests across premier U.S. oil and natural gas basins, primarily operated by large, well-capitalized companies, with a core focus in the Eagle Ford.
Corporate Structure
Our Class A common stock, par value $0.0001 per share (“Class A Common Stock”), is listed on the New York Stock Exchange (“NYSE”) under the symbol “CRGY”. CEC is a holding company that conducts all of its business operations through its subsidiaries, including Crescent Energy OpCo LLC (“OpCo”) and its subsidiaries. An affiliate of KKR & Co. Inc. (together with its subsidiaries, the “KKR Group”) is the sole holder of Crescent’s non-economic Series I preferred stock, par value $0.0001 per share, which entitles the holder thereof to appoint the Board of Directors of CEC (our “Board of Directors”) and to certain other approval rights.
Corporate Simplification
In April 2025, we announced that our corporate structure had been simplified through the elimination of the Company’s Up-C structure through the exercise by the holders of all then-remaining shares of Class B Common Stock, par value $0.0001 per share (“Class B Common Stock”), of their redemption rights with respect to all of their OpCo Units (the “Corporate Simplification”). Prior to the Corporate Simplification and elimination of the Company’s Up-C structure, holders of Crescent’s then-outstanding Class B Common Stock (which had voting, but no economic, rights with respect to Crescent) held a corresponding number of economic, non-voting units of OpCo (“OpCo Units”), which were generally redeemable or exchangeable for Class A Common Stock or, at our election, cash on the terms and conditions set forth in OpCo’s Amended and Restated Limited Liability Company Agreement. Pursuant to the aforementioned exercise of redemption rights in the Corporate Simplification, all OpCo Units (other than those held by Crescent) were exchanged for an equivalent number of shares of Class A Common Stock and all outstanding shares of Class B Common Stock were cancelled. As a result of the Corporate Simplification, all of the Company’s common stockholders now hold Class A Common Stock. See NOTE 11 – Related Party Transactions for more information.
2025 Equity Transactions
In March 2025, Independence Energy Aggregator L.P. (“Aggregator”), the entity through which certain private investors in affiliated KKR entities hold their interests in us, exercised its redemption right with respect to 2.9 million OpCo Units, and such OpCo Units were exchanged for an equivalent number of shares of Class A Common Stock and a corresponding number of shares of Class B Common Stock were cancelled (the “2025 Class A Redemption”). The shares of Class A Common Stock were sold by Aggregator at a price per share of $9.91 , pursuant to Rule 144, through a broker-dealer. We did not receive any proceeds or incur any material expenses related to the 2025 Class A Redemption.
As a result of the 2025 Class A Redemption and the Corporate Simplification, the total number of shares of our Class A Common Stock increased by 65.9 million shares with a corresponding decrease in the number of shares of our Class B Common Stock, and redeemable noncontrolling interests decreased by $1,210.8 million, while Additional paid-in capital (“APIC”) increased by $1,210.8 million.
11
Treasury Stock
Our Board of Directors authorized a stock repurchase program in March 2024 with an approved limit of $150.0 million and a two-year term. In February 2026, our Board of Directors extended the stock repurchase program indefinitely and increased the approved limit to $400.0 million. We may repurchase shares of our Class A Common Stock under such program. Such repurchases may be made from time to time in the open market, in privately negotiated transactions, through purchases made in accordance with the Rule 10b5-1 of the Exchange Act or by such other means as will comply with applicable state and federal securities laws. The timing of any repurchases under the stock repurchase program will depend on market conditions, contractual limitations and other considerations. The program may be extended, modified, suspended or discontinued at any time, and does not obligate us to repurchase any dollar amount or number of securities. The 1 % U.S. federal excise tax on certain repurchases of stock by publicly traded U.S. corporations enacted as part of the IRA 2022 applies to repurchases of our Class A Common Stock pursuant to our stock repurchase program.
We record treasury stock purchases at cost, which includes incremental direct transaction costs. Amounts are recorded as a reduction to equity on our condensed consolidated balance sheets. For the three and six months ended June 30, 2025, we repurchased 3.6 million and 4.1 million shares of our Class A Common Stock for $28.2 million and $33.5 million, at an average price of $7.88 and $8.21 per share, respectively (the “2025 Class A Repurchases”). In connection therewith, we cancelled a corresponding number of OpCo Units held by us. After the 2025 Class A Repurchases, the remaining amount under the plan (as re-authorized in February 2026) is approximately $336.0 million as of June 30, 2026.
In addition, a portion of our treasury stock shares represent shares we withheld associated with the payroll tax withholding obligations due from employees upon the vesting of stock awards. We include the shares withheld as treasury stock on our consolidated balance sheets and separately pay the payroll tax obligation. These retained shares are not part of a publicly announced program to repurchase shares of our Class A Common Stock and are accounted for at cost.
Basis of Presentation
Our unaudited condensed consolidated financial statements (the “financial statements”) include the accounts of the Company and its subsidiaries after the elimination of intercompany transactions and balances, are presented in accordance with U.S. generally accepted accounting principles (“GAAP”) and reflect all adjustments, consisting of normal recurring adjustments, that are, in the opinion of management, necessary to present fairly the financial position and results of operations for the respective interim periods. We have no elements of other comprehensive income for the periods presented. These financial statements should be read in conjunction with the audited consolidated financial statements and notes thereto included in our Annual Report.
CEC is a holding company that conducts substantially all of its business through its consolidated subsidiaries, including (i) OpCo, which is wholly owned by CEC, and (ii) Crescent Energy Finance LLC (“CEF”) and Crescent Royalty Finance LLC (“CRF”), each of which is wholly owned by OpCo. OpCo has no material operations, cash flows, assets or liabilities other than its investments in CEF and CRF. The assets and liabilities of OpCo represent substantially all of our consolidated assets and liabilities, except for certain parent company items held by CEC such as current and deferred taxes, CEC’s 2031 Convertible Notes (as defined within NOTE 7 – Debt), and certain liabilities under the Management Agreement (as defined within NOTE 11 – Related Party Transactions).
The financial statements include undivided interests in oil and natural gas properties. We account for our share of oil and natural gas properties by reporting our proportionate share of assets, liabilities, revenues, costs and cash flows within the accompanying condensed consolidated balance sheets, condensed consolidated statements of operations, and condensed consolidated statements of cash flows.
NOTE 2 – Summary of Significant Accounting Policies
Use of Estimates
The preparation of financial statements in conformity with GAAP requires management to make use of estimates and assumptions that affect the reported amount of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. We use historical experience and various other assumptions and information that are believed to be reasonable under the circumstances in developing our estimates and judgments. Estimates and assumptions about future events and their effects cannot be predicted with certainty and, accordingly, these estimates may change as new events occur, as more experience is acquired, as additional information is obtained and as our operating environment changes. While we believe that the estimates and assumptions used in
12
the preparation of the financial statements are appropriate, actual results may differ from these estimates. Our significant estimates include the fair value of acquired assets and liabilities, oil and natural gas reserves, impairment of proved and unproved oil and natural gas properties, valuation of derivative instruments and income taxes.
Restricted Cash
Restricted cash consists of funds earmarked for a special purpose and therefore not available for immediate and general use. Our restricted cash is composed of cash that is contractually required to be restricted for a variety of purposes including to fund acquisitions or to pay for the future abandonment of certain wells. Restricted cash is presented separately in current assets while the noncurrent portion is included in Other assets on our condensed consolidated balance sheets.
The following table provides a reconciliation of cash, cash equivalents and restricted cash presented on our balance sheets to amounts shown in our condensed consolidated statements of cash flows:
| As of June 30, | |||||||||||
| 2026 | 2025 | ||||||||||
| (in thousands) | |||||||||||
| Cash and cash equivalents | $ | $ | |||||||||
| Restricted cash – current | |||||||||||
| Restricted cash – noncurrent | |||||||||||
| Total cash, cash equivalents and restricted cash | $ | $ | |||||||||
Income Taxes
For the six months ended June 30, 2026, the effect of various discrete period tax items was a net tax expense of $46.7 million. Significant discrete items included permanent differences recognized in connection with the vesting of the performance stock units granted to our Manager (“Manager PSUs”). Excluding discrete items, our effective tax rate was 25.3 % during the six months ended June 30, 2026. There were no significant discrete tax items affecting our effective tax rate for the three and six months ended June 30, 2025.
In addition to increasing our effective tax rate, the Corporate Simplification and the 2025 Class A Redemption increased our Deferred tax liability by $136.9 million with an offsetting decrease in APIC on the condensed consolidated balance sheets.
We evaluate and update the estimated annual effective income tax rate on a quarterly basis based on current and forecasted operating results and tax laws. Consequently, based upon the mix and timing of our actual earnings compared to annual projections, our effective tax rate may vary quarterly and may make quarterly comparisons not meaningful. The quarterly income tax provision is generally composed of tax expense on income or benefit on loss at the most recent estimated annual effective tax rate. The tax effect of discrete items is recognized in the period in which they occur at the applicable statutory rate.
We continually assess the available positive and negative evidence to determine if sufficient future taxable income will be generated to use the existing deferred tax assets. On the basis of this evaluation, a valuation allowance is recorded to recognize only the portion of the deferred tax assets that are more likely than not to be realized. The amount of the deferred tax asset considered realizable, however, could be adjusted in the future.
We have U.S. federal net operating loss (“NOL”) carryforwards and recognized built-in-loss (“RBIL”) property that are subject to limitation under Section 382 of the U.S. Internal Revenue Code of 1986, as amended (the “IRC”). Pursuant to Sections 382 and 383 of the IRC, utilization of our NOL and RBIL carryforwards is subject to an annual limitation. These annual limitations may result in the expiration of U.S. federal NOL and RBIL carryforwards prior to utilization. Accordingly, we have maintained a valuation allowance related to U.S. federal NOL and RBIL carryforwards that we do not believe are recoverable due to these limitations under Section 382 of the IRC.
13
As of June 30, 2026 and December 31, 2025, we did not have any uncertain tax positions.
Supplemental Cash Flow Disclosures
The following are our supplemental cash flow disclosures for the six months ended June 30, 2026 and 2025:
| Six Months Ended June 30, | |||||||||||||||||||||||
| 2026 | 2025 | ||||||||||||||||||||||
| (in thousands) | |||||||||||||||||||||||
| Supplemental cash flow disclosures: | |||||||||||||||||||||||
| Interest paid, net of amounts capitalized | $ | $ | |||||||||||||||||||||
| Income tax payments (refunds) | |||||||||||||||||||||||
| Non-cash investing and financing activities: | |||||||||||||||||||||||
| Capital expenditures included in accounts payable and accrued liabilities | $ | $ | |||||||||||||||||||||
| Equity consideration for acquisitions | |||||||||||||||||||||||
Vital purchase price allocation adjustment | |||||||||||||||||||||||
| Right-of-use assets obtained in exchange for leases | |||||||||||||||||||||||
NOTE 3 – Acquisitions and Divestitures
Acquisitions
Vital Energy Merger
In December 2025, we consummated the transactions contemplated by the Agreement and Plan of Merger, dated August 24, 2025 (the “Vital Energy Merger Agreement”) (the transactions contemplated within the Vital Energy Merger Agreement, the “Vital Energy Merger”), between CEC, Venus Merger Sub I Inc., Venus Merger Sub II LLC and Vital. The Vital Energy Merger has been accounted for as a business combination using the acquisition method of accounting in accordance with ASC Topic 805, Business Combinations, with Crescent being identified as the accounting acquirer.
In accordance with the terms of the Vital Energy Merger Agreement, each share of Vital common stock issued and outstanding immediately prior to the Effective Time was converted into the right to receive from Crescent 1.9062 shares of Class A Common Stock, with cash paid in lieu of any fractional shares of Class A Common Stock. Each Vital restricted stock award that was outstanding immediately prior to the Vital Energy Merger vested in full and was cancelled and converted into the right to receive, without interest, the merger consideration in respect of each share of Vital common stock subject thereto, with cash paid in lieu of any fractional shares of Class A Common Stock. Each Vital cash-settled performance unit that was outstanding immediately prior to the Effective Time vested in full, with performance conditions deemed to have been satisfied at the target performance level, and was cancelled and converted into the right to receive a lump-sum cash payment equal to the product of (i) the total number of shares of Vital common stock subject to such Vital cash-settled performance unit and (ii) the closing trading price per share of Vital common stock reported on the NYSE on the trading day immediately preceding the closing of the Vital Energy Merger, less applicable tax withholdings.
Certain data necessary to complete the purchase price allocation is not yet available, including final tax returns that provide the underlying tax basis of Vital’s assets and liabilities. We expect to complete the purchase price allocation during the 12 -month period following the acquisition date of the Vital Energy Merger. During the six months ended June 30, 2026, we adjusted the preliminary purchase price for the Vital Energy Merger to reflect certain post-closing adjustments, which included an increase to Oil and gas properties - proved of $12.7 million, an increase to Oil and gas properties - unproved of $0.8 million, a decrease to Accounts receivable, net of $2.8 million, a decrease to Prepaid expenses of $0.3 million, an increase to the Accounts payable and accrued liabilities of $1.8 million, and an increase to Other current liabilities of $8.6 million on the condensed consolidated balance sheet.
Crescent issued 73.3 million shares of Class A Common Stock in the Vital Energy Merger and paid $3.7 million in cash to settle outstanding Vital equity awards.
We reorganized our business as a result of the integration of the assets acquired in the Vital Energy Merger, our acquisition of SilverBow Resources, Inc. (the “SilverBow Merger”) and certain divestitures, which included one-time termination costs and
14
exit costs for the closure of certain legacy corporate offices. As of June 30, 2026, we expected the total amount of one-time employee termination benefits incurred to be $62.7 million and lease termination and other costs of $16.4 million, respectively. The following is a reconciliation of our restructuring liability, which is included within Accounts payable and accrued liabilities on the consolidated balance sheets.
| One-time employee termination benefits | Lease termination and other costs | Total | |||||||||||||||
| (in thousands) | |||||||||||||||||
| December 31, 2025 | $ | $ | $ | ||||||||||||||
| Costs incurred and charged to expense | |||||||||||||||||
| Costs paid | ( | ( | ( | ||||||||||||||
| June 30, 2026 | $ | $ | $ | ||||||||||||||
Ridgemar Acquisition
On January 31, 2025, we acquired all of the outstanding equity interests in Ridgemar (Eagle Ford) LLC (“Ridgemar”) for $807.2 million in cash and 5.5 million shares of our Class A Common Stock (the “Ridgemar Acquisition”). We accounted for the Ridgemar Acquisition as an asset acquisition. In addition, up to $170.0 million in contingent earn-out consideration may be paid in fiscal years 2026 and 2027 if quarterly NYMEX WTI prices of crude oil are above certain thresholds in 2026 and 2027 (collectively, the “Ridgemar Contingent Consideration”). See NOTE 4 – Derivatives - Ridgemar Contingent Consideration.
Other Acquisitions
Minerals Acquisitions
In February 2026, we acquired a portfolio of mineral and royalty interests located in the Eagle Ford from unrelated third-parties for an aggregate consideration of approximately $309.9 million, including transaction costs and certain customary purchase price adjustments (the “February 2026 Minerals Acquisition”).
In January 2026, we acquired a portfolio of mineral and royalty interests located in the Eagle Ford from unrelated third-parties for an aggregate consideration of approximately $47.9 million, including transaction costs and certain customary purchase price adjustments (the “January 2026 Minerals Acquisition” and together with the February 2026 Minerals Acquisition, the “2026 Minerals Acquisitions”).
In July 2025, we acquired a portfolio of oil and natural gas mineral interests located in various U.S. oil and gas basins from an unrelated third-party for total cash consideration of approximately $67.9 million, including transaction costs and certain customary purchase price adjustments (collectively with the 2026 Minerals Acquisitions, the “Minerals Acquisitions”).
Webb Gas Acquisition
In January 2025, we acquired additional interests in Crescent operated oil and gas properties located in Webb County, Texas from unaffiliated third parties for aggregate consideration of approximately $21.2 million, subject to customary post-closing adjustments.
15
Consideration Transferred
The following table summarizes the consideration transferred and the net assets acquired for our acquisitions during 2026 and 2025 that impact the periods presented:
| Asset Acquisitions | Business Combination | ||||||||||||||||||||||||||||||||||
| Acquisition period | 2026 | 2025 | 2025 | ||||||||||||||||||||||||||||||||
January 2026 Minerals Acquisition | February 2026 Minerals Acquisition | 2025 Minerals Acquisition | Ridgemar Acquisition | Webb Gas Acquisition | Vital Energy Merger | ||||||||||||||||||||||||||||||
| (in thousands) | |||||||||||||||||||||||||||||||||||
| Consideration transferred: | |||||||||||||||||||||||||||||||||||
| Cash consideration: | |||||||||||||||||||||||||||||||||||
Cash | $ | $ | $ | $ | $ | $ | |||||||||||||||||||||||||||||
Settlement of Equity Awards in cash | — | ||||||||||||||||||||||||||||||||||
| Equity consideration: | |||||||||||||||||||||||||||||||||||
Fair value of Class A Common Stock issued | — | — | — | — | |||||||||||||||||||||||||||||||
Settlement of Equity Awards in Class A Common Stock | — | — | — | — | — | ||||||||||||||||||||||||||||||
| Fair value of contingent earn-out consideration | — | — | — | — | — | ||||||||||||||||||||||||||||||
| Transaction costs capitalized | — | — | |||||||||||||||||||||||||||||||||
| Total | $ | $ | $ | $ | $ | $ | |||||||||||||||||||||||||||||
| Assets acquired and liabilities assumed: | |||||||||||||||||||||||||||||||||||
| Cash and cash equivalents | $ | $ | $ | $ | $ | $ | |||||||||||||||||||||||||||||
| Accounts receivable, net | |||||||||||||||||||||||||||||||||||
| Derivative assets – current | |||||||||||||||||||||||||||||||||||
| Prepaid expenses | |||||||||||||||||||||||||||||||||||
| Oil and natural gas properties - proved | |||||||||||||||||||||||||||||||||||
| Oil and natural gas properties - unproved | |||||||||||||||||||||||||||||||||||
| Field and other property and equipment | |||||||||||||||||||||||||||||||||||
| Derivative assets – noncurrent | |||||||||||||||||||||||||||||||||||
| Deferred tax asset | |||||||||||||||||||||||||||||||||||
| Other assets | |||||||||||||||||||||||||||||||||||
| Accounts payable and accrued liabilities | ( | ( | ( | ||||||||||||||||||||||||||||||||
| Other current liabilities | ( | ( | |||||||||||||||||||||||||||||||||
| Long-term debt | ( | ||||||||||||||||||||||||||||||||||
| Derivative liabilities – noncurrent | ( | ||||||||||||||||||||||||||||||||||
| Asset retirement obligations | ( | ( | |||||||||||||||||||||||||||||||||
| Other liabilities | ( | ( | |||||||||||||||||||||||||||||||||
| Net assets acquired | $ | $ | $ | $ | $ | $ | |||||||||||||||||||||||||||||
Supplemental Pro Forma Information (Unaudited)
The following table summarizes our unaudited pro forma financial information for the six months ended June 30, 2025 as if the Vital Energy Merger occurred on January 1, 2025:
| Six Months Ended June 30, 2025 | |||||||||||
| (in thousands) | |||||||||||
| Revenues | $ | ||||||||||
| Net income | ( | ||||||||||
16
Divestitures
During 2025, we sold non-core assets as part of our 2025 non-core asset divestiture program for total consideration in excess of $900.0 million. During the three and six months ended June 30, 2026, we received $11.5 13.6
During the six months ended June 30, 2026, we sold additional non-core assets to unrelated third-party buyers for $1.2 million in aggregate net cash proceeds and recorded a loss of $2.9 million.
During the six months ended June 30, 2025, we sold non-core assets to unrelated third-party buyers for $11.1 million in aggregate net cash proceeds and recorded a gain of $1.9 million and $12.8 million on the sale of such assets for the three and six months ended June 30, 2025, respectively.
NOTE 4 – Derivatives
In the normal course of business we are exposed to certain risks, including changes in the prices of oil, natural gas and NGLs which may impact the cash flows associated with the sale of our future oil and natural gas production. We enter into derivative contracts with lenders under our reserves-based revolving credit facility, by and among CEF, as borrower, and Wells Fargo Bank, N.A., as administrative agent for the lenders and letter of credit issuer (as amended, restated or otherwise modified to date, the “Revolving Credit Facility”) that consist of either a single derivative instrument or a combination of instruments to manage our exposure to these risks.
As of June 30, 2026, our commodity derivative instruments consisted of fixed price and basis swaps and collars which are described below:
Fixed Price and Basis Swaps: Fixed price swaps receive a fixed price and pay a floating market price to the counterparty on the notional amount. Our basis swaps fix the basis differentials between the index price at which we sell our production as compared to the index price used in the basis swap. Under a swap contract, we will receive payment if the settlement price is less than the fixed price and will be required to make a payment to the counterparty if the settlement price is greater than the fixed price.
Two-Way and Three-Way Collars: Two-way collars provide a minimum (“fixed floor price”) and maximum (“fixed ceiling price”) price on a notional amount of sales volume. Under a two-way collar, we will receive payment if the settlement price is less than the fixed floor price and make a payment to the counterparty if the settlement price is greater than the fixed ceiling price. We would not be required to make a payment or receive payment if the settlement price falls between the fixed floor price and fixed ceiling price. A three-way collar adds a secondary lower price below the fixed floor price (“fixed subfloor price”). In this structure, if the settlement price falls between the fixed floor price and the fixed subfloor price, we receive payment equal to the difference between the fixed floor price and the settlement price. If the settlement price falls below the fixed subfloor price, we receive payment equal to the difference between the fixed floor price and the fixed subfloor price. We still make a payment to the counterparty if the settlement price is greater than the fixed ceiling price, and we would still not be required to make or receive payment if the settlement price falls between the fixed ceiling price and the fixed floor price.
17
The following table details our net volume positions by commodity as of June 30, 2026:
| Production Period | Volumes | Weighted Average Fixed Price | |||||||||||||||||||||||||||||||||||||||||||||
| (in thousands) | |||||||||||||||||||||||||||||||||||||||||||||||
| Crude oil swaps – WTI (Bbls): | |||||||||||||||||||||||||||||||||||||||||||||||
| 2026 | $ | ||||||||||||||||||||||||||||||||||||||||||||||
| 2027 | $ | ||||||||||||||||||||||||||||||||||||||||||||||
2027 (1) | $ | ||||||||||||||||||||||||||||||||||||||||||||||
| Crude oil two-way collars – WTI (Bbls): | |||||||||||||||||||||||||||||||||||||||||||||||
| 2026 | $ | - | $ | ||||||||||||||||||||||||||||||||||||||||||||
| Crude oil three-way collars – WTI (Bbls): | |||||||||||||||||||||||||||||||||||||||||||||||
| 2026 | $ | - | $ | - | $ | ||||||||||||||||||||||||||||||||||||||||||
| 2027 | $ | - | $ | - | $ | ||||||||||||||||||||||||||||||||||||||||||
2027 (2) | $ | - | $ | - | $ | ||||||||||||||||||||||||||||||||||||||||||
| Crude oil two-way collars – Brent (Bbls): | |||||||||||||||||||||||||||||||||||||||||||||||
| 2026 | $ | - | $ | ||||||||||||||||||||||||||||||||||||||||||||
| Natural gas swaps (MMBtu): | |||||||||||||||||||||||||||||||||||||||||||||||
| 2026 | $ | ||||||||||||||||||||||||||||||||||||||||||||||
| 2027 | $ | ||||||||||||||||||||||||||||||||||||||||||||||
2027 (3) | $ | ||||||||||||||||||||||||||||||||||||||||||||||
| Natural gas two-way collars (MMBtu): | |||||||||||||||||||||||||||||||||||||||||||||||
| 2026 | $ | - | $ | ||||||||||||||||||||||||||||||||||||||||||||
| Crude oil basis swaps (Bbls): | |||||||||||||||||||||||||||||||||||||||||||||||
| 2026 | $ | ||||||||||||||||||||||||||||||||||||||||||||||
| 2027 | $ | ||||||||||||||||||||||||||||||||||||||||||||||
| Natural gas basis swaps (MMBtu): | |||||||||||||||||||||||||||||||||||||||||||||||
| 2026 | $( | ||||||||||||||||||||||||||||||||||||||||||||||
| 2027 | $( | ||||||||||||||||||||||||||||||||||||||||||||||
| Calendar Month Average roll swaps (Bbls): | |||||||||||||||||||||||||||||||||||||||||||||||
| 2026 | $ | ||||||||||||||||||||||||||||||||||||||||||||||
| Natural gas fixed index swaps – Waha (MMBtu): | |||||||||||||||||||||||||||||||||||||||||||||||
| 2026 | $ | ||||||||||||||||||||||||||||||||||||||||||||||
| 2027 | $ | ||||||||||||||||||||||||||||||||||||||||||||||
(1) Represents outstanding crude oil swap options exercisable by the counterparty until December 2026 and June 2027.
(2) Represents outstanding crude oil three-way collar options exercisable by the counterparty until June 2027.
(3) Represents outstanding natural gas swap options exercisable by the counterparty until December 2026.
18
Ridgemar Contingent Consideration: The former owners of Ridgemar are entitled to receive contingent consideration payments from us if the daily average price of NYMEX WTI crude oil exceeds certain thresholds during specified quarterly periods. For each quarterly period in 2026, we will be required to pay $15.0 70 15.0 75 12.5 70 70 per barrel for the first quarter of 2026 and $75 per barrel for the second quarter of 2026. Accordingly, we made payments totaling $45.0 million during the six months ended June 30, 2026.
Vital Contingent Consideration: As part of the Vital Energy Merger, we acquired a contingent consideration arrangement in which we are entitled to receive contingent consideration payments from a third party if certain performance conditions are met related to certain assets previously sold by Vital (the “Vital Contingent Consideration”). We are entitled to up to $9.0 million in 2026, and $58.6 million in 2027 if certain performance conditions are met within those periods. The fair value of the Vital Contingent Consideration is determined by a third-party valuation specialist using a Monte Carlo simulation. The significant inputs used in the valuation include Crescent’s internally developed cash flow projections for the underlying assets and a risk-adjusted discount rate, which is developed by the third-party valuation specialist based on market participant assumptions and prevailing market conditions. We determined that these Level 3 fair value inputs are primarily based on unobservable inputs. As of December 31, 2025, contingent earn-out consideration is included in Other assets, and as of June 30, 2026, it is included in Other assets - current on the condensed consolidated balance sheets.
We use derivative commodity instruments and enter into swap contracts that are governed by International Swaps and Derivatives Association (“ISDA”) master agreements. The following table shows the effects of master netting arrangements on the fair value of our derivative contracts and contingent earn-out consideration as of June 30, 2026 and December 31, 2025:
19
| Gross Fair Value | Effect of Counterparty Netting | Net Carrying Value | |||||||||||||||
| (in thousands) | |||||||||||||||||
| June 30, 2026 | |||||||||||||||||
| Assets: | |||||||||||||||||
| Derivative assets – current | $ | $ | ( | $ | |||||||||||||
| Other assets – current | |||||||||||||||||
| Derivative assets – noncurrent | ( | ||||||||||||||||
| Total assets | $ | $ | ( | $ | |||||||||||||
| Liabilities: | |||||||||||||||||
| Derivative liabilities – current | $ | ( | $ | $ | ( | ||||||||||||
| Other current liabilities | ( | ( | |||||||||||||||
| Derivative liabilities – noncurrent | ( | ( | |||||||||||||||
| Other liabilities | ( | ( | |||||||||||||||
| Total liabilities | $ | ( | $ | $ | ( | ||||||||||||
| December 31, 2025 | |||||||||||||||||
| Assets: | |||||||||||||||||
| Derivative assets – current | $ | $ | ( | $ | |||||||||||||
| Derivative assets – noncurrent | ( | ||||||||||||||||
Other assets | |||||||||||||||||
| Total assets | $ | $ | ( | $ | |||||||||||||
| Liabilities: | |||||||||||||||||
| Derivative liabilities – current | $ | ( | $ | $ | |||||||||||||
| Other current liabilities | ( | ( | |||||||||||||||
| Derivative liabilities – noncurrent | ( | ( | |||||||||||||||
| Other liabilities | ( | ( | |||||||||||||||
| Total liabilities | $ | ( | $ | $ | ( | ||||||||||||
See NOTE 5 – Fair Value Measurements for more information.
The amounts of gain (loss) recognized in gain (loss) on derivatives in our condensed consolidated statements of operations were as follows for the three and six months ended June 30, 2026 and 2025:
| Three Months Ended June 30, | Six Months Ended June 30, | ||||||||||||||||||||||
| 2026 | 2025 | 2026 | 2025 | ||||||||||||||||||||
| (in thousands) | |||||||||||||||||||||||
| Derivatives not designated as hedging instruments: | |||||||||||||||||||||||
| Realized gain (loss) on oil positions | $ | ( | $ | $ | ( | $ | |||||||||||||||||
| Realized gain (loss) on natural gas positions | ( | ( | |||||||||||||||||||||
| Realized gain (loss) on NGL positions | ( | ( | |||||||||||||||||||||
| Realized gain (loss) on contingent earn-out consideration | ( | ( | |||||||||||||||||||||
| Total realized gain (loss) on derivatives | ( | ( | |||||||||||||||||||||
| Unrealized gain (loss) on commodity derivatives | ( | ||||||||||||||||||||||
| Unrealized gain (loss) on contingent earn-out consideration | ( | ( | |||||||||||||||||||||
| Total unrealized gain (loss) on derivatives | ( | ||||||||||||||||||||||
| Gain (loss) on derivatives | $ | $ | $ | ( | $ | ||||||||||||||||||
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NOTE 5 – Fair Value Measurements
GAAP defines fair value as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date (exit price). Generally, the determination of fair value requires the use of significant judgment and different approaches and models under varying circumstances. Under a market-based approach, we consider prices of similar assets, consult with brokers and experts or employ other valuation techniques. Under an income-based approach, we generally estimate future cash flows and then discount them at a risk-adjusted rate. We classify the inputs used to measure the fair value of our financial assets and liabilities into the following hierarchy:
Level 1: Quoted prices (unadjusted) in active markets for identical assets or liabilities as of the reporting date. Active markets are those in which transactions for the asset or liability occur in sufficient frequency and volume to provide pricing information on an ongoing basis.
Level 2: Quoted market prices for similar assets or liabilities in active markets, quoted prices for identical or similar assets and liabilities in markets that are not active or other than quoted prices that are observable, either directly or indirectly, and can be corroborated by observable market data.
Level 3: Unobservable inputs that reflect management’s best estimates and assumptions of what market participants would use in measuring the fair value of an asset or liability.
Financial assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. Our assessment of significance for a particular input to the fair value measurement requires judgment and may affect our valuation of the fair value assets and liabilities within the fair value hierarchy levels.
Recurring Fair Value Measurements
The following table presents the fair value of our derivative assets and liabilities that were accounted for at fair value on a recurring basis as of June 30, 2026 and December 31, 2025 by level within the fair value hierarchy:
| Fair Value Measurement Using | |||||||||||||||||||||||
| Level 1 | Level 2 | Level 3 | Total | ||||||||||||||||||||
| (in thousands) | |||||||||||||||||||||||
| June 30, 2026 | |||||||||||||||||||||||
| Financial assets: | |||||||||||||||||||||||
| Derivative assets | $ | $ | $ | $ | |||||||||||||||||||
Vital contingent earn-out consideration | |||||||||||||||||||||||
| Financial liabilities: | |||||||||||||||||||||||
| Derivative liabilities | $ | $ | ( | $ | $ | ( | |||||||||||||||||
| Ridgemar contingent earn-out consideration | ( | ( | |||||||||||||||||||||
| December 31, 2025 | |||||||||||||||||||||||
| Financial assets: | |||||||||||||||||||||||
| Derivative assets | $ | $ | $ | $ | |||||||||||||||||||
Vital contingent earn-out consideration | |||||||||||||||||||||||
| Financial liabilities: | |||||||||||||||||||||||
| Derivative liabilities | $ | $ | ( | $ | $ | ( | |||||||||||||||||
Ridgemar contingent earn-out consideration | ( | ( | |||||||||||||||||||||
| As of June 30, 2026 | |||||
| (in thousands) | |||||
Rollforward of Recurring Level 3 Fair Value Measurements: | |||||
Beginning balance | $ | ||||
Unrealized gain (loss) on Vital contingent earn-out consideration | |||||
Ending balance | $ | ||||
21
Non-Recurring Fair Value Measurements
Certain nonfinancial assets and liabilities are measured at fair value on a non-recurring basis. We utilize fair value measurements on a non-recurring basis to value our oil and natural gas properties when events and circumstances indicate a possible decline in the recoverability of the carrying amount of such property. When a triggering event is identified, we compare the carrying amount of our oil and natural gas properties to the estimated undiscounted cash flows our oil and natural gas properties will generate to determine if the carrying amount is recoverable. We perform this analysis on an asset pool basis. If the carrying amount exceeds the estimated undiscounted cash flows, we will write-down the carrying amount of the oil and natural gas properties to fair value. The Level 3 inputs used to determine such fair value are primarily based upon internally developed cash flow models and estimated net proceeds upon the potential sale of an asset pool and are classified within Level 3. Significant Level 3 assumptions associated with discounted cash flows include, but are not limited to, estimates of reserves, future commodity prices, future production estimates, and discount rates commensurate with the risk associated with realizing the projected cash flows.
Our other non-recurring fair value measurements include the estimates of the fair value of assets and liabilities acquired through business combinations. Our business combinations are accounted for using the acquisition method under GAAP, which requires all assets acquired and liabilities assumed in the acquisitions to be recorded at fair values at the acquisition date of each transaction. Oil and natural gas properties are valued based on an income approach using a discounted cash flow model utilizing Level 3 inputs, including internally generated development and production profiles and price and cost assumptions. Net derivative liabilities assumed in acquisitions are valued based on Level 2 inputs similar to the Company’s other commodity price derivatives. See NOTE 3 – Acquisitions and Divestitures.
Other Fair Value Measurements
The carrying value of cash and cash equivalents, accounts receivable, accounts payable and accrued liabilities approximate their fair values due to the short-term maturities of these instruments. Our long-term debt obligations under our Revolving Credit Facility also have approximate fair value because the associated variable rates of interest are market based. The fair value of the Company’s outstanding senior notes (collectively, “Senior Notes”) as of June 30, 2026 and December 31, 2025 was approximately $5.0 billion and $4.7 billion, respectively, based on quoted market prices or Level 1 inputs.
NOTE 6 – Accounts Payable and Accrued Liabilities
Accounts payable and accrued liabilities consisted of the following as of June 30, 2026 and December 31, 2025:
| June 30, 2026 | December 31, 2025 | ||||||||||
| (in thousands) | |||||||||||
| Accounts payable and accrued liabilities: | |||||||||||
| Accounts payable | $ | $ | |||||||||
| Accrued lease and asset operating expense | |||||||||||
| Accrued capital expenditures | |||||||||||
| Accrued general and administrative expense | |||||||||||
| Accrued gathering, processing and transportation expense | |||||||||||
| Accrued revenue and royalties payable | |||||||||||
| Accrued interest expense | |||||||||||
| Accrued severance taxes | |||||||||||
| Other | |||||||||||
| Total accounts payable and accrued liabilities | $ | $ | |||||||||
22
NOTE 7 – Debt
Crescent Energy Company
Senior Notes
2031 Convertible Notes
In March 2026, we issued $690.0 million aggregate principal amount of 2.750 % Convertible Senior Notes due 2031 (the “2031 Convertible Notes”) at par. The 2031 Convertible Notes bear interest at an annual rate of 2.750 %, which is payable on March 15 and September 15 of each year, beginning on September 15, 2026, and mature on March 15, 2031, unless earlier converted or redeemed or purchased by the Company. The net proceeds of the 2031 Convertible Notes were approximately $671.0 million after deducting the initial purchasers’ discount and offering expenses. The net proceeds of the 2031 Convertible Notes were used in part to redeem all of our outstanding 2028 Notes (as defined below) as discussed below.
Prior to December 15, 2030, the 2031 Convertible Notes are convertible only in certain circumstances and during specified periods. Thereafter, they are convertible at the noteholders’ election until shortly before the maturity date. Upon conversion, we may settle the conversions by paying or delivering, as applicable, in cash, shares of Class A Common Stock, or a combination thereof, at our election. The 2031 Convertible Notes have an initial conversion rate of 67.1456 shares of Class A Common Stock per each $1,000 principal amount, which represents an initial conversion price of approximately $14.89 per share of Class A Common Stock. In connection with the issuance of the 2031 Convertible Notes, we paid $56.6 million to enter into capped call transactions with certain financial institution counterparties designed to reduce potential dilution upon conversion of the 2031 Convertible Notes and/or offset cash payments in excess of the principal amount of the converted notes, in each case subject to the initial cap price of $22.48 per share of Class A Common Stock. The capped call transactions reduced APIC.
The 2031 Convertible Notes are the Company’s senior, unsecured obligations and are (i) equal in right of payment with CEC’s, as the issuer of the 2031 Convertible Notes, senior unsecured indebtedness; (ii) senior in right of payment to the issuer’s indebtedness that is expressly subordinated to the 2031 Convertible Notes; and (iii) effectively subordinated to the issuer’s secured indebtedness, to the extent of the value of the collateral securing that indebtedness. The 2031 Convertible Notes are not guaranteed by any of the Company’s subsidiaries, and the Company’s subsidiaries do not have any obligations under the 2031 Convertible Notes. Because the 2031 Convertible Notes are not guaranteed by any of the Company’s subsidiaries, the 2031 Convertible Notes are structurally subordinated to all indebtedness and other liabilities, including the Revolving Credit Facility, the CRF Credit Facility (as defined below), other series of our Senior Notes, trade payables and (to the extent the Company is not a holder thereof) preferred equity, if any, of the Company’s subsidiaries.
Crescent Energy Finance LLC
Senior Notes
2028 Notes
At December 31, 2025, we had $500.0 million outstanding aggregate principal amount of 9.250 % senior notes due 2028 (the “2028 Notes”). In March 2026, we elected to redeem all of the remaining 2028 Notes (the “2028 Notes Redemption”), at a price of 102.3125 %. As a result of the 2028 Notes Redemption, we incurred a loss on the extinguishment of debt of approximately $17.0 million, including $5.4 million related to the non-cash write-off of outstanding deferred financing costs, discounts, and premiums.
2029 Notes
At December 31, 2025, we had $298.2 million outstanding aggregate principal amount of 7.750 % senior notes due 2029 (the “2029 Notes”). In March 2026, we repurchased $39.1 million of our outstanding 2029 Notes in open market transactions, at an average price of 101.014 %. As a result of the repurchases, we incurred a loss on the extinguishment of debt of approximately $0.4 million. In July 2026, we elected to redeem all of the remaining 2029 Notes (the “2029 Notes Redemption”) at a redemption price equal to 100.000 % of the outstanding principal amount, or $258.7 million, plus accrued and unpaid interest to, but excluding, the redemption date.
23
Revolving Credit Facility
Overview
We are party to a senior secured reserve-based revolving credit agreement with Wells Fargo Bank, N.A., as administrative agent for the lenders and letter of credit issuer, and the lenders from time to time party thereto.
On May 18, 2026, we entered into the Fifteenth Amendment (the “CEF Credit Agreement Amendment”) to the credit agreement governing our Revolving Credit Facility. Among other things, the CEF Credit Agreement Amendment (i) decreased our borrowing base from $3.9 billion to $3.5 billion, which constitutes the April 1, 2026 scheduled redetermination, (ii) extended our maturity date from October 22, 2030 to May 19, 2031 and (iii) provided that the incurrence of up to $600.0 million of certain additional indebtedness during the period beginning on May 18, 2026 and ending on the scheduled redetermination date for the October 1, 2026 scheduled redetermination will be excluded from the requirement for the borrowing base to be reduced by 0.25 x of the principal amount of such new debt incurrences, so long as such debt is incurred during such period and does not exceed the $600.0 million aggregate threshold. The CEF Credit Agreement Amendment maintained the aggregate elected commitments at $2.0 billion.
Our Revolving Credit Facility matures on May 19, 2031, but contains terms that if certain conditions regarding our outstanding 2029 Notes or our 9.750 % Senior Notes due 2030 exist 91 days prior to their stated maturity, it will mature on such date. At June 30, 2026, we were in compliance with each of the covenants under the Revolving Credit Facility and expect to remain in compliance with these covenants for the foreseeable future.
Interest
Borrowings under the Revolving Credit Facility bear interest at either (i) a U.S. dollar alternative base rate based on the prime rate, the federal funds effective rate or an adjusted secured overnight financing rate (“SOFR”), plus an applicable margin or (ii) SOFR, plus an applicable margin, at the election of the borrowers. The applicable margin varies based upon our borrowing base utilization then in effect. The fee payable for unused revolving commitments at June 30, 2026 is 0.375 % per year and fees incurred are included within interest expense on our condensed consolidated statements of operations. Our weighted average interest rate on loan amounts outstanding as of December 31, 2025 was 5.56 %. We had no borrowings outstanding under the Revolving Credit Facility at June 30, 2026.
Crescent Royalty Finance LLC
Crescent Royalty Finance Credit Facility
Overview
In February 2026, one of our subsidiaries, CRF, entered into a senior secured reserve-based revolving credit agreement with Wells Fargo Bank, N.A., as administrative agent for the lenders and letter of credit issuer, and the lenders from time to time party thereto (the “CRF Credit Facility”). The CRF Credit Facility provides for a $1.0 billion aggregate maximum credit amount senior secured reserve-based revolving credit facility, with an initial borrowing base and aggregate elected commitment amount of $365.0 million, consisting of $230.0 million under the revolving facility and a $135.0 million term loan (“CRF Term Loan”). As of June 30, 2026, $45.5 million remained outstanding under the CRF Term Loan. Revolving loans under the CRF Credit Facility mature on February 23, 2031, and initial term loans under the CRF Credit Facility mature on February 23, 2029. The borrowing base is subject to semi-annual scheduled redeterminations on or about April 1st and October 1st of each year.
The obligations under the CRF Credit Facility are secured by liens on collateral granted by CRF, as borrower, and the guarantors under the related security documents, including, without limitation, oil and gas properties and related assets, as-extracted collateral in the form of production and proceeds attributable to mortgaged properties, equity interests in restricted subsidiaries owned by the borrower or subsidiary guarantors, certain indebtedness owed to the borrower or subsidiary guarantors, and deposit and securities accounts, in each case subject to permitted liens, excluded assets and other exceptions. The security documents include the security agreement, pledge agreement, mortgages, account control agreements and other instruments executed to secure or perfect the obligations under the facility. In connection with each redetermination of the borrowing base, the borrower must maintain mortgages on properties sufficient to satisfy the collateral coverage minimum, which requires that mortgaged properties represent at least 85 % of the PV-9 of the credit parties’ total proved reserves included in the initial reserve report and, thereafter, the most recent reserve report. The borrower’s domestic subsidiaries are required to be guarantors under the CRF Credit Facility, subject to certain exceptions.
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Interest
Borrowings under the CRF Credit Facility bear interest at either (i) a U.S. dollar alternative base rate based on the prime rate, the federal funds effective rate or an adjusted SOFR, plus an applicable margin or (ii) SOFR, plus an applicable margin, at the election of CRF. The applicable margin and fee payable for the unused revolving commitments varies based upon CRF’s borrowing base utilization then in effect. The weighted average interest rates on the CRF Credit Facility and the CRF Term Loan amounts outstanding as of June 30, 2026 were 6.446 % and 6.946 %, respectively.
Covenants
The CRF Credit Facility contains certain covenants that restrict the payment of cash dividends, certain borrowings, sales of assets, loans to others, investments, merger activity and commodity swap agreements, liens and other transactions without the prior consent of our lenders. We are subject to (i) maximum leverage ratio and (ii) current ratio financial covenants calculated as of the last day of each fiscal quarter, beginning with the fiscal quarter ending on June 30, 2026. The CRF Credit Facility also contains representations, warranties, indemnifications and affirmative and negative covenants, including events of default relating to nonpayment of principal, interest or fees, inaccuracy of representations or warranties in any material respect when made or when deemed made, violation of covenants, bankruptcy and insolvency events, certain unsatisfied judgments and a change of control. If an event of default occurs and we are unable to cure such event of default, the lenders will be able to accelerate maturity and exercise other rights and remedies. As of June 30, 2026, we were in compliance with each of the covenants under the CRF Credit Facility and expect to remain in compliance with these covenants for the foreseeable future.
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Total Debt Outstanding
The following table summarizes our debt balances as of June 30, 2026 and December 31, 2025:
| Debt Outstanding | Letters of Credit Issued | Borrowing Base | Maturity | ||||||||||||||||||||
| (in thousands) | |||||||||||||||||||||||
| June 30, 2026 | |||||||||||||||||||||||
Crescent Energy Company | |||||||||||||||||||||||
| $ | $ | — | $ | — | 3/15/2031 | ||||||||||||||||||
| Less: Unamortized discount, premium and issuance costs | ( | ||||||||||||||||||||||
Crescent Energy Finance LLC | |||||||||||||||||||||||
| Revolving Credit Facility | 5/19/2031 | ||||||||||||||||||||||
| — | — | 7/31/2029 | |||||||||||||||||||||
| — | — | 10/15/2030 | |||||||||||||||||||||
| — | — | 4/15/2032 | |||||||||||||||||||||
| — | — | 4/1/2032 | |||||||||||||||||||||
| — | — | 1/15/2033 | |||||||||||||||||||||
| — | — | 1/15/2034 | |||||||||||||||||||||
| Less: Unamortized discount, premium and issuance costs | ( | ||||||||||||||||||||||
Crescent Royalty Finance LLC | |||||||||||||||||||||||
CRF Term Loan | — | — | 2/23/2029 | ||||||||||||||||||||
CRF Credit Facility | — | $ | 2/23/2031 | ||||||||||||||||||||
| Less: Unamortized discount, premium and issuance costs | ( | ||||||||||||||||||||||
| Total long-term debt | $ | ||||||||||||||||||||||
| December 31, 2025 | |||||||||||||||||||||||
Crescent Energy Finance LLC | |||||||||||||||||||||||
| Revolving Credit Facility | $ | $ | $ | 10/22/2030 | |||||||||||||||||||
| — | — | 2/15/2028 | |||||||||||||||||||||
| — | — | 7/31/2029 | |||||||||||||||||||||
| — | — | 10/15/2030 | |||||||||||||||||||||
| — | — | 4/15/2032 | |||||||||||||||||||||
| — | — | 4/1/2032 | |||||||||||||||||||||
| — | — | 1/15/2033 | |||||||||||||||||||||
| — | — | 1/15/2034 | |||||||||||||||||||||
| Less: Unamortized discount, premium and issuance costs | ( | ||||||||||||||||||||||
| Total long-term debt | $ | ||||||||||||||||||||||
(1) Represents the borrowing base as of June 30, 2026, consisting of a $230.0 million conforming borrowing base and a $45.5 million non-conforming borrowing base.
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NOTE 8 – Asset Retirement Obligations
Our ARO liabilities are based on our net ownership in wells and facilities and management’s estimate of the costs to abandon and remediate those wells and facilities together with management’s estimate of the future timing of the costs to be incurred. The following table summarizes activity related to our ARO liabilities for the six months ended June 30, 2026:
| As of June 30, 2026 | |||||
| (in thousands) | |||||
| Balance at beginning of period | $ | ||||
Additions | |||||
| Retirements | ( | ||||
Divestitures | ( | ||||
| Accretion expense | |||||
| Balance at end of period | |||||
| Less: current portion | ( | ||||
| Balance at end of period, noncurrent portion | $ | ||||
NOTE 9 – Commitments and Contingencies
From time to time, we may be a plaintiff or defendant in a pending or threatened legal proceeding arising in the normal course of business. In accordance with ASC 450, Contingencies, an accrual is recorded for a material loss contingency when its occurrence is probable and damages are reasonably estimable based on the anticipated most likely outcome or the minimum amount within a range of possible outcomes.
Legal proceedings are inherently unpredictable, and unfavorable resolutions can occur. Assessing contingencies is highly subjective and requires judgment about uncertain future events. When evaluating contingencies related to legal proceedings, we may be unable to estimate losses due to a number of factors, including potential defenses, the procedural status of the matter in question, the presence of complex legal and/or factual issues, and the ongoing discovery and/or development of information important to the matter. We are unable to make an estimate of the range of reasonably possible losses related to our contingencies, but we are currently unaware of any proceedings that, in the opinion of management, will individually or in the aggregate have a material adverse effect on our financial position, results of operations or cash flows.
We are subject to extensive federal, state and local environmental laws and regulations. These laws and regulations regulate the discharge of materials into the environment and may require us to remove or mitigate the environmental effects of the disposal or release of petroleum or chemical substances at various sites. We believe we are currently in compliance with all applicable federal, state and local regulations. Accordingly, no significant liability or loss associated with environmental remediation was recognized as of June 30, 2026.
NOTE 10 – Equity-Based Compensation Awards
Overview
We and certain of our subsidiaries have entered into incentive compensation award agreements to grant profits interests, restricted stock units (“RSUs”), performance stock units (“PSUs”) and other incentive awards to our employees, our Manager, as defined within NOTE 11 – Related Party Transactions, and non-employee directors. The following table summarizes compensation cost we recognized in connection with our equity-based compensation awards for the periods indicated:
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| Three Months Ended June 30, | Six Months Ended June 30, | |||||||||||||||||||||||||
| 2026 | 2025 | 2026 | 2025 | |||||||||||||||||||||||
Equity-based compensation expense: | (in thousands) | |||||||||||||||||||||||||
| Liability-classified profits interest awards | $ | $ | $ | $ | ||||||||||||||||||||||
| Equity-classified profits interest awards | ||||||||||||||||||||||||||
| Equity-classified LTIP RSU awards | ||||||||||||||||||||||||||
| Equity-classified LTIP PSU awards | ||||||||||||||||||||||||||
| Equity-classified Manager PSUs | ||||||||||||||||||||||||||
| Total equity-based compensation expense | $ | $ | $ | $ | ||||||||||||||||||||||
| Tax benefit related to equity-based compensation awards | $ | $ | $ | $ | ||||||||||||||||||||||
Our incentive compensation awards may contain certain service-based, performance-based, and market-based vesting conditions, which are further discussed below.
Equity-classified LTIP RSU Awards
During the three and six months ended June 30, 2026, we granted a total of 1.8 one 12.73 three years 0.4
Equity-classified LTIP PSU Awards
During the three and six months ended June 30, 2026, we granted a total of 0.5 0 240 22.75
Equity-classified Manager PSU Awards
In March 2026, the certification of the Company’s level of achievement with respect to the Target PSU (as defined below) for the first and second three-year performance period, or tranches, of the incentive compensation granted to the Manager under the Crescent Energy Company 2021 Manager Incentive Plan (the “Incentive Compensation”) was completed. As a result, such tranches were settled and the number of shares of our Class A Common Stock outstanding increased by 2.1 million shares accordingly. Additionally, the number of equity-classified PSU target shares of Class A Common Stock related to the Incentive Compensation increased by approximately 0.1 million shares for the six months ended June 30, 2026. We accounted for this increase as a change in estimate and recognized additional expense of $0.4 million and $2.4 million for the three and six months ended June 30, 2026, respectively. For more information on the Incentive Compensation, including the performance-based vesting criteria applicable thereto, see NOTE 11 – Related Party Transactions - Management Agreement.
NOTE 11 – Related Party Transactions
KKR Group
Management Agreement
Crescent Energy Company has a management agreement (the “Management Agreement”) with KKR Energy Assets Manager LLC (the “Manager”). Pursuant to the Management Agreement, the Manager provides the Company with members of its executive management team and certain management services. The Management Agreement has a term of three years , with automatic three-year renewals, unless the Company or the Manager elects not to renew the Management Agreement. The
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current term automatically renewed in December 2024 for an additional three-year term ending December 7, 2027 and will have automatic three-year renewals thereafter, unless the Company or the Manager elects not to renew the Management Agreement.
As consideration for the services rendered pursuant to the Management Agreement and the Manager’s overhead, including compensation of members of its executive management team, the Manager is entitled to receive compensation from the Company equal to $78.5 million per annum (“Manager Compensation”), as of June 30, 2026, which is included in General and administrative expenses on our condensed consolidated statements of operations. As the Company’s business and assets expand, Manager Compensation will increase by an amount equal to 1.5 % per annum of the net proceeds from all future issuances of our primary equity securities by the Company (including in connection with acquisitions). See NOTE 3 – Acquisitions and Divestitures for more information.
Prior to the Corporate Simplification, the Manager Compensation was reduced proportionally by the percentage of OpCo Units held as redeemable noncontrolling interests, with such amount distributed concurrently to the holders of redeemable noncontrolling interests. This cash distribution to the holders of redeemable noncontrolling interests did not represent additional Manager Compensation; rather, it represented an ordinary cash distribution to the holders of redeemable noncontrolling interests. In certain instances in our financial statements and other disclosures, we clarify the underlying event that requires us to make such distributions.
During the three and six months ended June 30, 2026, we recorded General and administrative expense of $19.6 million and $39.2 million, respectively, related to the Manager Compensation. After the Corporate Simplification, there are no longer any outstanding redeemable noncontrolling interests in OpCo, and as such, we no longer make cash distributions to the holders of redeemable noncontrolling interests. During the three and six months ended June 30, 2025, we recorded General and administrative expense of $17.3 million and $30.5 million, respectively, related to the Manager Compensation and made cash distributions of $4.2 million and $8.8 million, respectively, to our redeemable noncontrolling interests related to the Management Agreement. At both June 30, 2026 and December 31, 2025, we had $19.6
Additionally, the Manager is entitled to receive Incentive Compensation under which the Manager is targeted to receive Class A Common Stock based on the achievement of certain performance-based measures. Initially, the Incentive Compensation consisted of five tranches, each of which featured a separate three-year performance period and relates to a target number of shares of Class A Common Stock equal to 2 % of the outstanding Class A Common Stock as of the time such tranche is settled (each, a “Target PSU”). The first two tranches have vested and were fully expensed as of December 31, 2025. So long as the Manager continuously provides services to us until the end of the performance period applicable to a tranche, the Manager is entitled to settlement of such tranche with respect to a number of shares of Class A Common Stock ranging from 0 % to 4.8 % of the outstanding Class A Common Stock at the time each tranche is settled. Accordingly, as our Class A Common Stock share count increases, the number of equity-classified Manager PSU target shares of our Class A Common Stock granted under the Crescent Energy Company 2021 Manager Incentive Plan increases. During the three and six months ended June 30, 2026, we recorded non-cash general and administrative expense of $19.7 million and $40.8 million, respectively, related to Incentive Compensation. During the three and six months ended June 30, 2025, we recorded non-cash general and administrative expense of $91.5 million and $116.9 million, respectively, related to Incentive Compensation. See NOTE 10 – Equity-Based Compensation Awards for more information.
KKR Funds
From time to time, we may invest in upstream oil and gas assets alongside EIGF II and/or other KKR funds (“KKR Funds”) pursuant to the terms of the Management Agreement. In these instances, certain of our consolidated subsidiaries enter into Master Service Agreements (“MSA”) with entities owned by KKR Funds, pursuant to which our subsidiaries provide certain services to such KKR Funds, including the allocation of the production and sale of oil, natural gas and NGLs, collection and disbursement of revenues, operating expenses and general and administrative expenses in the respective oil and natural gas properties, and the payment of all capital costs associated with the ongoing operations of the oil and natural gas assets. Our subsidiaries settle balances due to or due from KKR Funds on a quarterly basis. The administrative costs associated with these MSAs are allocated by us to KKR Funds based on (i) an actual basis for direct expenses we may incur on their behalf or (ii) an allocation of such charges between the various KKR Funds based on the estimated use of such services by each party. As of June 30, 2026 and December 31, 2025, we had a related party receivable of $0.1 million and $1.2 million, respectively, included within Accounts receivable – affiliates and a related party payable of $1.3 million and $25.1 million, respectively, included within Accounts payable – affiliates on our condensed consolidated balance sheets associated with KKR Funds transactions.
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KKR Capital Markets LLC (“KCM”)
We may engage KCM, an affiliate of KKR Group, for capital market transactions primarily including notes offerings, credit facility structuring and equity offerings. In March 2026, in connection with our offering of 2031 Convertible Notes, we paid fees to our underwriting syndicate, of which $5.0 million was paid to KCM. The following table summarizes fees, discounts and commissions paid to KCM by Crescent in connection with our debt and equity transactions:
| Three Months Ended June 30, | Six Months Ended June 30, | ||||||||||||||||||||||
| 2026 | 2025 | 2026 | 2025 | ||||||||||||||||||||
(in thousands) | |||||||||||||||||||||||
| Amounts paid to KCM | $ | $ | $ | $ | |||||||||||||||||||
We recorded these fees to debt issuance costs within Long-term debt (notes offerings) and Other assets (credit facility structuring) or APIC (equity offerings).
Other Transactions
During the three and six months ended June 30, 2025, we made cash distributions of $0.2 million and $7.8 million, respectively, to our redeemable noncontrolling interests related to their pro rata share of cash distributions made to CEC to pay dividends and income taxes. As a result of the Corporate Simplification, such pro rata distributions to holders of redeemable noncontrolling interests were eliminated.
In addition, during the three and six months ended June 30, 2026 and 2025, we reimbursed KKR $1.9 million and $2.4 million, $1.1 million and $1.7 million, respectively, for costs incurred on our behalf. At December 31, 2025, we had $0.7 million accrued within Accounts payable - affiliates on the condensed consolidated balance sheet for reimbursable costs that was subsequently paid during the six months ended June 30, 2026.
Other
We were previously required to fund certain workover costs and plugging and abandonment costs related to producing assets held by Chama Energy LLC (“Chama”), an Investment in equity affiliates on our condensed consolidated balance sheets. John Goff, the Chairman of our Board of Directors, holds an approximate interest of 17.5 % in Chama, and the remaining interests are held by other investors. During the six months ended June 30, 2025, we funded $2.0 million to Chama associated with plugging and abandonment costs. During the six months ended June 30, 2026, we received $1.3 million from Chama in connection with the cessation of its operations and the closure of its bank accounts.
NOTE 12 – Earnings Per Share
We have two classes of common stock in the form of Class A Common Stock and Class B Common Stock. Our shares of Class A Common Stock are entitled to dividends. Shares of Class B Common Stock do not participate in dividends or undistributed earnings, but holders of such shares receive pro rata distributions from OpCo through their ownership of corresponding OpCo Units. After the Corporate Simplification, there are no shares of Class B Common Stock outstanding. We apply the two-class method for purposes of calculating earnings per share (“EPS”). The two-class method determines earnings per share of Common Stock and participating securities according to dividends or dividend equivalents declared during the period and each security’s respective participation rights in undistributed earnings and losses. The dilutive effect of the 2031 Convertible Notes was determined under the if-converted method and the two-class method using the more dilutive method of the two.
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The following table sets forth the computation of basic and diluted net income (loss) per share:
| Three Months Ended June 30, | Six Months Ended June 30, | ||||||||||||||||||||||
| 2026 | 2025 | 2026 | 2025 | ||||||||||||||||||||
| (in thousands, except per share amounts) | |||||||||||||||||||||||
| Numerator: | |||||||||||||||||||||||
| Net income (loss) | $ | $ | $ | $ | |||||||||||||||||||
| Less: net (income) loss attributable to noncontrolling interests | ( | ( | ( | ( | |||||||||||||||||||
| Less: net (income) loss attributable to redeemable noncontrolling interests | ( | ( | |||||||||||||||||||||
| Net income (loss) attributable to Crescent Energy - basic | $ | $ | $ | $ | |||||||||||||||||||
| Add: Reallocation of net income attributable to redeemable noncontrolling interest for the dilutive effect of RSUs | ( | ( | |||||||||||||||||||||
| Add: Reallocation of net income attributable to redeemable noncontrolling interest for the dilutive effect of PSUs | ( | ( | |||||||||||||||||||||
Add: Interest expense, net of taxes, of 2031 Convertible Notes | |||||||||||||||||||||||
| Net income (loss) attributable to Crescent Energy - diluted | $ | $ | $ | $ | |||||||||||||||||||
| Denominator: | |||||||||||||||||||||||
| Weighted-average Class A Common Stock outstanding - basic | |||||||||||||||||||||||
| Add: dilutive effect of RSUs | |||||||||||||||||||||||
| Add: dilutive effect of PSUs | |||||||||||||||||||||||
| Add: dilutive effect of 2031 Convertible Notes | |||||||||||||||||||||||
| Weighted-average Class A Common Stock outstanding – diluted | |||||||||||||||||||||||
| Weighted-average Class B Common Stock outstanding – basic and diluted | |||||||||||||||||||||||
| Net income (loss) per share: | |||||||||||||||||||||||
| Class A Common Stock – basic | $ | $ | $ | $ | |||||||||||||||||||
| Class A Common Stock – diluted | $ | $ | $ | $ | |||||||||||||||||||
| Class B Common Stock – basic and diluted | $ | $ | $ | $ | |||||||||||||||||||
NOTE 13 – Segment Information
We have evaluated how we are organized and managed and have identified one reportable segment, which is our interests related to the exploration and production of crude oil, natural gas and NGLs from operated and non-operated wells. We consider our gathering, processing and marketing functions as ancillary to our oil and gas producing activities. Substantially all of our operations and assets are located onshore in the United States, and substantially all of our revenues are attributable to United States customers.
The Company’s Chief Operating Decision Maker (“CODM”) is the Chief Executive Officer. The CODM uses measures of profitability including Net income (loss) on the condensed consolidated statement of operations to assess performance and determine resource allocation. The CODM uses these metrics to make key operating decisions, including the determination of allocation of capital between development of existing oil and gas properties and the acquisition of additional oil and gas properties, and the identification and divestiture of non-core assets. The measure of segment assets is reported on the Consolidated balance sheets as Total assets. We do not have intra-entity sales or transfers.
The table below provides information about the Company’s single reportable segment:
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| Three Months Ended June 30, | Six Months Ended June 30, | ||||||||||||||||||||||
| 2026 | 2025 | 2026 | 2025 | ||||||||||||||||||||
| (in thousands) | |||||||||||||||||||||||
| Total revenues | $ | $ | $ | $ | |||||||||||||||||||
Less: | |||||||||||||||||||||||
| Lease and asset operating expense | |||||||||||||||||||||||
| Workover expense | |||||||||||||||||||||||
| Gathering, processing and transportation | |||||||||||||||||||||||
| Production and other taxes | |||||||||||||||||||||||
| Depreciation, depletion and amortization | |||||||||||||||||||||||
| Impairment expense | |||||||||||||||||||||||
| Midstream and other operating expense | |||||||||||||||||||||||
| General and administrative expense excluding equity-based compensation | |||||||||||||||||||||||
| Equity-based compensation expense | |||||||||||||||||||||||
| Interest expense | |||||||||||||||||||||||
| Other segment items | ( | ( | ( | ||||||||||||||||||||
| Net income (loss) | $ | $ | $ | $ | |||||||||||||||||||
| Total development of oil and natural gas properties | $ | $ | $ | $ | |||||||||||||||||||
Other segment items include Exploration expense, Gain (loss) on derivatives, (Gain) loss on sale of assets and Loss from extinguishment of debt from our condensed consolidated statements of operations.
NOTE 14 – Subsequent Events
Dividend
On August 3, 2026, the Board of Directors approved a quarterly cash dividend of $0.12 0.48 per share on an annualized basis, to be paid to shareholders of our Class A Common Stock with respect to the second quarter of 2026. The quarterly dividend is payable on August 31, 2026 to shareholders of record as of the close of business on August 17, 2026.
The payment of quarterly cash dividends is subject to management’s evaluation of our financial condition, results of operations and cash flows in connection with such payments and approval by our Board of Directors. Management and the Board of Directors will evaluate any future changes in cash dividends on a quarterly basis.
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Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations
Management’s Discussion and Analysis of Financial Condition and Results of Operations (“MD&A”) is intended to provide the reader of the financial statements with a narrative from the perspective of management on the financial condition, results of operations, liquidity and certain other factors that may affect the Company’s operating results. The following discussion and analysis should be read in conjunction with Management’s Discussion and Analysis of Financial Condition and Results of Operations in our Annual Report on Form 10-K for the year ended December 31, 2025 (“Annual Report”), our Quarterly Report on Form 10-Q for the period ended March 31, 2026, as well as our unaudited condensed consolidated financial statements for the three and six months ended June 30, 2026 and 2025. The following information updates the discussion of our financial condition provided in our previous filings, and analyzes the changes in the results of operations between the three and six months ended June 30, 2026 and 2025. The following discussion contains forward-looking statements that reflect our future plans, estimates, beliefs and expected performance. The forward-looking statements are dependent upon events, risks and uncertainties that may be outside our control. Our actual results could differ materially from those discussed in these forward-looking statements. Factors that could cause or contribute to such differences include, but are not limited to, commodity price volatility, capital requirements and uncertainty of obtaining additional funding on terms acceptable to the Company, realized oil, natural gas and NGL prices, the timing and amount of future production of oil, natural gas and NGLs, shortages of equipment, supplies, services and qualified personnel, as well as those factors discussed below and elsewhere in this Quarterly Report and in our Annual Report, particularly under “Risk Factors” and “Cautionary Statement Regarding Forward Looking Statements,” all of which are difficult to predict. In light of these risks, uncertainties and assumptions, the forward-looking events discussed may not occur. We do not undertake any obligation to publicly update any forward-looking statements except as otherwise required by applicable law. Unless otherwise stated or the context otherwise indicates, all references to “we,” “us,” “our,” “Crescent” and the “Company” or similar expressions refer to Crescent Energy Company (“CEC”) and its subsidiaries.
Business
Crescent is a differentiated U.S. energy company committed to delivering value through a disciplined, returns-driven growth through acquisition strategy and consistent return of capital. Our long-life, balanced portfolio combines significant cash flow from stable production with deep, high-quality development inventory. Our activities are focused in the Eagle Ford, Permian Basin and Uinta Basin, and we own minerals and royalty interests across premier U.S. oil and natural gas basins, primarily operated by large, well-capitalized companies, with a core focus in the Eagle Ford.
Geopolitical developments and economic environment
During the last several years, prices of crude oil, natural gas and NGLs have experienced periodic downturns and sustained volatility, impacted by geopolitical events, such as Russia’s invasion of Ukraine and the related sanctions imposed on Russia, Hamas’ attack against Israel and the ensuing conflict and escalation of tensions in the Middle East. For example, the ongoing military conflict with Iran, which began in February 2026, has heightened geopolitical risk in key global energy markets and contributed to increased volatility in oil and gas commodity prices. The conflict has resulted in disruptions and constraints on maritime transit, supply chains, and energy infrastructure in the Middle East, including in and around the Strait of Hormuz, a critical choke point for global oil and liquefied natural gas shipments. These developments have led to elevated risk premiums in energy commodity prices and greater short‑term price uncertainty, causing global crude oil prices to surpass $100 per Bbl at times. Commodity prices and broader market conditions have also been affected by developments in Venezuela, supply chain constraints, elevated interest rates, U.S. international trade and tariff policies and responses thereto and costs of capital and political and regulatory uncertainties. Furthermore, the United States has experienced, and may continue to experience, a significant inflationary environment, which began in 2022 that, along with international geopolitical risks and market responses to the announcement of certain tariff policies by the Trump Administration, has contributed to concerns of a potential recession in the United States that has created further volatility. For example, actions taken by OPEC+ with respect to production levels, and announcements of potential changes in such levels, including production adjustments during 2025 and the first half of 2026, and changes in participation by member countries have contributed, and may continue to contribute, to volatility in commodity prices and in the oil and natural gas industry generally. Such volatility may lead to a more difficult investing and planning environment for us and our customers. While we use derivative instruments to partially mitigate the impact of commodity price volatility, our revenues and operating results depend significantly upon the prevailing prices for oil and natural gas.
There were no impairment charges recognized during the three and six months ended June 30, 2026. During the three and six months ended June 30, 2025, we recorded an impairment expense of $3.0 million and $48.6 million, respectively, to write down the value of certain assets classified as held for sale to expected net proceeds. A decline of future commodity prices or a decrease in estimates of oil and natural gas reserves for our assets would likely result in an impairment charge. The actual amount of impairment incurred, if any, for these properties will depend on a variety of factors including, but not limited to,
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subsequent forward price curve changes, weighted-average cost of capital, operating cost estimates and future capital expenditures estimates. An estimate of the sensitivity to changes in assumptions in our fair value calculations is not practicable, given the numerous assumptions (e.g. reserves, pace and timing of development plans, commodity prices, capital expenditures, operating costs, drilling and development costs, inflation and discount rates) that can materially affect our estimates. Unfavorable adjustments to some of the above listed assumptions would likely be offset by favorable adjustments in other assumptions. For example, the impact of sustained reduced commodity prices would likely be partially offset by lower costs.
Due to the cyclical nature of the oil and gas industry, fluctuating demand for oilfield goods and services can put pressure on the pricing structure within our industry. As commodity prices rise, the cost of oilfield goods and services generally also increase, while during periods of commodity price declines, oilfield costs typically lag and do not adjust downward as fast as oil prices do. The U.S. inflation rate remained relatively stable through 2024, 2025 and thus far through 2026, after an extended period of elevation; however, the full impact of recent geopolitical actions (including the conflict with Iran) on inflation cannot be fully determined at this time. Inflationary pressures have resulted in and may result in additional increases to the costs of our oilfield goods, services and personnel, which in turn cause our capital expenditures and operating costs to rise. Recently announced tariffs and any further tariffs may also increase our operating costs. Although the U.S. Federal Reserve made cuts to benchmark interest rates in 2024 and 2025, the Federal Reserve’s Board of Governors has, so far in 2026, kept rates steady. Although the financial health of the oil and gas industry has shown improvement as compared to prior periods, to the extent elevated interest rates and inflation remain, we may experience further cost increases for our operations, including oilfield services, labor costs and equipment. Higher oil and natural gas prices may cause the costs of materials and services to continue to rise. We cannot predict any future trends in the rate of inflation, any subsequent monetary policy changes (including as a result of recent changes to the composition of the Federal Reserve’s Board of Governors), and a significant increase in inflation, to the extent we are unable to recover higher costs through higher oil and natural gas prices and revenues, would negatively impact our business, financial condition and results of operations. See Part I. Item 1A. Risk Factors—“Risks related to the oil and natural gas industry—Inflationary issues and associated changes in monetary policy previously have resulted in and such issues, as well as certain proposed tariffs, may in the future result in additional increases to the cost of our goods, services and personnel, which in turn cause our capital expenditures and operating costs to rise” in our Annual Report.
Capital market transactions
2031 Convertible Notes
In March 2026, we issued $690.0 million aggregate principal amount of 2.750% Convertible Senior Notes due 2031 (the “2031 Convertible Notes”) at par. The 2031 Convertible Notes bear interest at an annual rate of 2.750%, which is payable on March 15 and September 15 of each year, beginning on September 15, 2026, and mature on March 15, 2031, unless earlier converted or redeemed or purchased by the Company. The net proceeds of the 2031 Convertible Notes were approximately $671.0 million after deducting the initial purchasers’ discount and offering expenses. The net proceeds of the 2031 Convertible Notes were used in part to redeem all of our outstanding 2028 Notes (as defined below) as discussed below.
Prior to December 15, 2030, the 2031 Convertible Notes are convertible only in certain circumstances and during specified periods. Thereafter, they are convertible at the noteholders’ election until shortly before the maturity date. Upon conversion, we may settle the conversions by paying or delivering, as applicable, in cash, shares of Class A Common Stock, or a combination thereof, at our election. The 2031 Convertible Notes have an initial conversion rate of 67.1456 shares of Class A Common Stock per each $1,000 principal amount, which represents an initial conversion price of approximately $14.89 per share of Class A Common Stock. In connection with the issuance of the 2031 Convertible Notes, we paid $56.6 million to enter into capped call transactions with certain financial institution counterparties designed to reduce potential dilution upon conversion of the 2031 Convertible Notes and/or offset cash payments in excess of the principal amount of the converted notes, in each case subject to the initial cap price of $22.48 per share of Class A Common Stock.
The 2031 Convertible Notes are the Company’s senior, unsecured obligations and are (i) equal in right of payment with CEC’s, as the issuer of the 2031 Convertible Notes, senior unsecured indebtedness; (ii) senior in right of payment to the issuer’s indebtedness that is expressly subordinated to the 2031 Convertible Notes; and (iii) effectively subordinated to the issuer’s secured indebtedness, to the extent of the value of the collateral securing that indebtedness. The 2031 Convertible Notes are not guaranteed by any of the Company’s subsidiaries, and the Company’s subsidiaries do not have any obligations under the 2031 Convertible Notes. Because the 2031 Convertible Notes are not guaranteed by any of the Company’s subsidiaries, the 2031 Convertible Notes are structurally subordinated to all indebtedness and other liabilities, including the Revolving Credit Facility, the CRF Credit Facility (as defined below), other series of our Senior Notes, trade payables and (to the extent the Company is not a holder thereof) preferred equity, if any, of the Company’s subsidiaries.
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2028 Notes
At December 31, 2025, we had $500.0 million outstanding aggregate principal amount of 9.250% senior notes due 2028 (the “2028 Notes”). In March 2026, we elected to redeem all of the remaining 2028 Notes (the “2028 Notes Redemption”), at a price of 102.3125%. As a result of the 2028 Notes Redemption, we incurred a loss on the extinguishment of debt of approximately $17.0 million, including $5.4 million related to the non-cash write-off of outstanding deferred financing costs, discounts, and premiums.
2029 Notes
At December 31, 2025, we had $298.2 million outstanding aggregate principal amount of 7.750% senior notes due 2029 (the “2029 Notes”). In March 2026, we repurchased $39.1 million of our outstanding 2029 Notes in open market transactions, at an average price of 101.014%. As a result of the repurchases, we incurred a loss on the extinguishment of debt of approximately $0.4 million. In July 2026, we elected to redeem all of the remaining 2029 Notes (the “2029 Notes Redemption”) at a redemption price equal to 100.000% of the outstanding principal amount, or $258.7 million, plus accrued and unpaid interest to, but excluding, the redemption date.
Acquisitions and divestitures
Acquisitions
Vital Energy Merger
In December 2025, we consummated the Vital Energy Merger. Immediately following the Vital Energy Merger, the Company completed a series of internal transactions following which the assets of Vital and its subsidiary became held by subsidiaries of CEF (as defined below). In connection with the Vital Energy Merger, Crescent issued 73.3 million shares of Class A Common Stock and paid $3.7 million in cash to settle outstanding Vital equity awards. In connection with the closing of the Vital Energy Merger, we repaid outstanding borrowings of $890.0 million and terminated the Vital revolving credit facility. See Notes to condensed consolidated financial statements, NOTE 3 – Acquisitions and Divestitures included in Part I. Item 1. Financial Statements of this Quarterly Report for additional information.
Ridgemar Acquisition
On January 31, 2025, we acquired all of the outstanding equity interests in Ridgemar (Eagle Ford) LLC (“Ridgemar”) for $807.2 million in cash and 5.5 million shares of our Class A Common Stock (the “Ridgemar Acquisition”). We accounted for the Ridgemar Acquisition as an asset acquisition. In addition, up to $170.0 million in contingent earn-out consideration may be paid in fiscal years 2026 and 2027 if quarterly NYMEX WTI prices of crude oil are above certain thresholds in 2026 and 2027 (collectively, the “Ridgemar Contingent Consideration”). See Notes to condensed consolidated financial statements, NOTE 3 – Acquisitions and Divestitures included in Part I. Item 1. Financial Statements of this Quarterly Report for additional information.
Other Acquisitions
Minerals Acquisitions
In February 2026, we acquired a portfolio of mineral and royalty interests located in the Eagle Ford from unrelated third-parties for an aggregate consideration of approximately $309.9 million, including transaction costs and certain customary purchase price adjustments (the “February 2026 Minerals Acquisition”).
In January 2026, we acquired a portfolio of mineral and royalty interests located in the Eagle Ford from unrelated third-parties for an aggregate consideration of approximately $47.9 million, including transaction costs and certain customary purchase price adjustments (the “January 2026 Minerals Acquisition” and together with the February 2026 Minerals Acquisition, the “2026 Minerals Acquisitions”).
In July 2025, we acquired a portfolio of oil and natural gas mineral interests located in various U.S. oil and gas basins from an unrelated third-party for total cash consideration of approximately $67.9 million, including transaction costs and certain customary purchase price adjustments (collectively with the 2026 Minerals Acquisitions, the “Minerals Acquisitions”).
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Webb Gas Acquisition
In January 2025, we acquired additional interests in Crescent operated oil and gas properties located in Webb County, Texas from unaffiliated third parties for aggregate consideration of approximately $21.2 million, subject to customary post-closing adjustments.
Divestitures
During 2025, we sold non-core assets as part of our 2025 non-core asset divestiture program for total consideration in excess of $900.0 million. During the three and six months ended June 30, 2026, we received $11.5 million in additional net cash proceeds and recorded a gain of $13.6 million as part of the customary purchase price adjustments.
During the six months ended June 30, 2026, we sold additional non-core assets to unrelated third-party buyers for $1.2 million in aggregate net cash proceeds and recorded a loss of $2.9 million.
During the six months ended June 30, 2025, we sold non-core assets to unrelated third-party buyers for $11.1 million in aggregate net cash proceeds and recorded a gain of $1.9 million and $12.8 million on the sale of such assets for the three and six months ended June 30, 2025, respectively.
Stewardship
We seek to improve the assets we own and acquire to deliver enhanced financial returns, operations and stewardship. We believe that being a responsible operator will produce better outcomes, creating a net benefit for society and the environment, while delivering attractive returns for our investors. We view exceptional sustainability performance as an opportunity to differentiate Crescent from its peers, mitigate risks and strengthen operational performance as well as benefit our stakeholders and the communities in which we operate.
We are members of the Oil & Gas Methane Partnership 2.0 Initiative, or OGMP 2.0, and in 2025, following consecutive years on OGMP 2.0 Gold Standard pathway, we achieved the OGMP 2.0 Gold Standard Reporting designation for our credible plan to more accurately measure our methane emissions. OGMP 2.0 is the United Nations Environment Programme’s flagship oil and gas reporting and mitigation program and the leading industry standard for methane emissions reporting. We previously established a Sustainability Advisory Council, an outside council comprising leading experts across key sustainability topics, to advise management and our Board of Directors on sustainability-related issues. See additional materials on our website at www.crescentenergyco.com/sustainability. However, please note that the contents and other materials on our website in general are not intended or deemed to be incorporated by reference in this Quarterly Report.
How we evaluate our operations
We use a variety of financial and operational metrics to assess the performance of our oil, natural gas and NGL operations, including:
•Production volumes sold,
•Commodity prices and differentials,
•Operating expenses,
•Adjusted EBITDAX (non-GAAP), and
•Levered Free Cash Flow (non-GAAP)
Development program and capital budget
Our development program, which consists of expenditures for drilling, completion and recompletion activities, and related facilities, is designed to prioritize the generation of attractive risk-adjusted returns and meaningful free cash flow and is inherently flexible, with the ability to modify our capital program as necessary to react to the current market environment.
We expect to fund our 2026 capital program through cash flow from operations. Due to the flexible nature of our capital program and the fact that the majority of our acreage is held by production, we could choose to defer a portion or all of these planned capital expenditures depending on a variety of factors, including, but not limited to, the success of our drilling
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activities, prevailing and anticipated prices for oil, natural gas and NGLs and resulting well economics, the availability of necessary equipment, infrastructure and capital, the receipt and timing of required regulatory permits and approvals, seasonal conditions, drilling and acquisition costs and the level of participation by other interest owners.
Management Agreement
Crescent Energy Company has a management agreement (the “Management Agreement”) with KKR Energy Assets Manager LLC (the “Manager”). Pursuant to the Management Agreement, the Manager provides the Company with members of its executive management team and certain management services. The Management Agreement has a term of three years, with automatic three-year renewals, unless the Company or the Manager elects not to renew the Management Agreement. The current term automatically renewed in December 2024 for an additional three-year term ending December 7, 2027 and will have automatic three-year renewals thereafter, unless the Company or the Manager elects not to renew the Management Agreement.
As consideration for the services rendered pursuant to the Management Agreement and the Manager’s overhead, including compensation of members of its executive management team, the Manager is entitled to receive compensation from the Company equal to $78.5 million per annum (“Manager Compensation”), as of June 30, 2026, which is included in General and administrative expenses on our condensed consolidated statements of operations. As the Company’s business and assets expand, Manager Compensation will increase by an amount equal to 1.5% per annum of the net proceeds from all future issuances of our primary equity securities by the Company (including in connection with acquisitions). See NOTE 3 – Acquisitions and Divestitures included in Part I. Item 1. Financial Statements of this Quarterly Report for more information.
Prior to the Corporate Simplification, the Manager Compensation was reduced proportionally by the percentage of OpCo Units held as redeemable noncontrolling interests, with such amount distributed concurrently to the holders of redeemable noncontrolling interests. This cash distribution to the holders of redeemable noncontrolling interests did not represent additional Manager Compensation; rather, it represented an ordinary cash distribution to the holders of redeemable noncontrolling interests. In certain instances in our financial statements and other disclosures, we clarify the underlying event that requires us to make such distributions.
Additionally, the Manager is entitled to receive Incentive Compensation under which the Manager is targeted to receive Class A Common Stock based on the achievement of certain performance-based measures. Initially, the Incentive Compensation consisted of five tranches, each of which featured a separate three-year performance period and relates to a target number of shares of Class A Common Stock equal to 2% of the outstanding Class A Common Stock as of the time such tranche is settled (each, a “Target PSU”). The first two tranches have vested and were fully expensed as of December 31, 2025. So long as the Manager continuously provides services to us until the end of the performance period applicable to a tranche, the Manager is entitled to settlement of such tranche with respect to a number of shares of Class A Common Stock ranging from 0% to 4.8% of the outstanding Class A Common Stock at the time each tranche is settled. Accordingly, as our Class A Common Stock share count increases, the number of equity-classified Manager PSU target shares of our Class A Common Stock granted under the Crescent Energy Company 2021 Manager Incentive Plan increases.
Sources of revenues
Our revenues are primarily derived from the sale of our oil, natural gas and NGL production and are influenced by production volumes and realized prices, excluding the effect of our commodity derivative contracts. Commodity prices are subject to supply and demand as well as seasonal, political and other conditions that we generally cannot control. Our revenues may vary significantly from period to period as a result of changes in volumes of production sold or changes in commodity prices. The following table illustrates our production revenue mix for each of the periods presented:
| Three Months Ended June 30, | Six Months Ended June 30, | ||||||||||||||||||||||
| 2026 | 2025 | 2026 | 2025 | ||||||||||||||||||||
| Oil | 89 | % | 71 | % | 83 | % | 68 | % | |||||||||||||||
| Natural gas | 2 | % | 18 | % | 7 | % | 20 | % | |||||||||||||||
| NGLs | 9 | % | 11 | % | 10 | % | 12 | % | |||||||||||||||
In addition, revenue from our midstream assets is supported by commercial agreements that have established minimum volume commitments. These midstream revenues, as well as revenue associated with crude oil blending, comprise the majority of our midstream and other revenue. Midstream and other revenue accounts for 4% or less of our total revenues for the three and six months ended June 30, 2026 and 2025.
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Production volumes sold
The following table presents historical sales volumes for our properties:
| Three Months Ended June 30, | Six Months Ended June 30, | ||||||||||||||||||||||
| 2026 | 2025 | 2026 | 2025 | ||||||||||||||||||||
Total consolidated | |||||||||||||||||||||||
| Oil (MBbls) | 12,699 | 9,801 | 25,281 | 18,962 | |||||||||||||||||||
| Natural gas (MMcf) | 65,022 | 58,572 | 131,882 | 117,526 | |||||||||||||||||||
| NGLs (MBbls) | 6,929 | 4,345 | 13,859 | 8,576 | |||||||||||||||||||
| Total (MBoe) | 30,465 | 23,908 | 61,120 | 47,125 | |||||||||||||||||||
| Daily average (MBoe/d) | 335 | 263 | 338 | 260 | |||||||||||||||||||
| Working interest (CEF) | |||||||||||||||||||||||
| Oil (MBbls) | 12,142 | 9,604 | 24,359 | 18,570 | |||||||||||||||||||
| Natural gas (MMcf) | 62,307 | 56,997 | 126,431 | 114,469 | |||||||||||||||||||
| NGLs (MBbls) | 6,722 | 4,230 | 13,474 | 8,354 | |||||||||||||||||||
| Total (MBoe) | 29,249 | 23,334 | 58,905 | 46,002 | |||||||||||||||||||
| Daily average (MBoe/d) | 322 | 257 | 326 | 254 | |||||||||||||||||||
Minerals and royalties (CRF) | |||||||||||||||||||||||
| Oil (MBbls) | 557 | 197 | 922 | 392 | |||||||||||||||||||
| Natural gas (MMcf) | 2,715 | 1,575 | 5,451 | 3,057 | |||||||||||||||||||
| NGLs (MBbls) | 207 | 115 | 385 | 222 | |||||||||||||||||||
| Total (MBoe) | 1,216 | 574 | 2,215 | 1,123 | |||||||||||||||||||
| Daily average (MBoe/d) | 13 | 6 | 12 | 6 | |||||||||||||||||||
Total consolidated sales volumes increased 6,557 MBoe and increased 13,995 MBoe during the three and six months ended June 30, 2026, respectively, compared to the three and six months ended June 30, 2025. Our Working interest sales volumes increased 5,915 MBoe and increased 12,903 MBoe during the three and six months ended June 30, 2026, respectively, primarily due to the Vital Energy Merger, partially offset by our 2025 divestitures. Our Minerals and royalties sales volumes increased 642 MBoe and increased 1,092 MBoe during the three and six months ended June 30, 2026, respectively, due to our 2026 Minerals Acquisitions.
Commodity prices and differentials
Our results of operations depend upon many factors, particularly the price of commodities and our ability to market our production effectively.
The oil and natural gas industry is cyclical and commodity prices can be highly volatile. In recent years, commodity prices have been subject to significant fluctuations, either as a result of geopolitical events, such as developments in Venezuela, Russia’s invasion of Ukraine and the associated sanctions imposed on Russia, the Israel-Hamas conflict and the broader conflict in the Middle East, including the conflict with Iran and the disruption of shipments of crude oil and liquefied natural gas through the Strait of Hormuz, actions taken by OPEC+ and other major producing countries, sustained levels of inflation and increased U.S. drilling activity or otherwise. Uncertainty persists regarding OPEC+’s actions, changes in participation by member countries, increased U.S. drilling, proposed tariffs, inflation and the armed conflicts in Ukraine and the Middle East, including with Iran, and the potential for related supply disruptions and impacts on global energy markets. Additionally, recessionary concerns and broader macroeconomic conditions contributed, among other factors, to increased volatility in the price for oil and natural gas.
In order to reduce the impact of fluctuations in oil and natural gas prices on revenues, we regularly enter into derivative contracts with respect to a portion of the estimated oil, natural gas and NGL production through various transactions that fix the future prices received. We plan to continue the practice of entering into economic hedging arrangements to reduce near-term exposure to commodity prices, protect cash flow and corporate returns and maintain our liquidity.
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The following table presents the percentages of our production that was economically hedged through the use of derivative contracts:
| Three Months Ended June 30, | Six Months Ended June 30, | ||||||||||||||||||||||
| 2026 | 2025 | 2026 | 2025 | ||||||||||||||||||||
| Oil | 66 | % | 56 | % | 67 | % | 57 | % | |||||||||||||||
| Natural gas | 52 | % | 59 | % | 54 | % | 58 | % | |||||||||||||||
| NGLs | — | % | 8 | % | — | % | 8 | % | |||||||||||||||
The following table sets forth the average NYMEX oil and natural gas prices and our average realized prices for the periods presented:
| Three Months Ended June 30, | Six Months Ended June 30, | ||||||||||||||||||||||
| 2026 | 2025 | 2026 | 2025 | ||||||||||||||||||||
| Oil (Bbl): | |||||||||||||||||||||||
| Average NYMEX | $ | 92.79 | $ | 63.74 | $ | 82.36 | $ | 67.58 | |||||||||||||||
| Realized price (excluding derivative settlements) | 96.61 | 61.47 | 83.86 | 64.45 | |||||||||||||||||||
Realized price (including derivative settlements) (1) | 73.33 | 64.27 | 68.56 | 65.67 | |||||||||||||||||||
| Natural Gas (Mcf): | |||||||||||||||||||||||
| Average NYMEX | $ | 2.90 | $ | 3.44 | $ | 3.97 | $ | 3.55 | |||||||||||||||
| Realized price (excluding derivative settlements) | 0.52 | 2.71 | 1.46 | 2.95 | |||||||||||||||||||
Realized price (including derivative settlements) (1) | 1.74 | 2.60 | 1.99 | 2.84 | |||||||||||||||||||
| NGLs (Bbl): | |||||||||||||||||||||||
| Realized price (excluding derivative settlements) | $ | 18.67 | $ | 22.59 | $ | 18.36 | $ | 23.99 | |||||||||||||||
Realized price (including derivative settlements) (1) | 18.67 | 22.48 | 18.36 | 23.78 | |||||||||||||||||||
(1) The realized price presented above does not include $62.1 million or $122.6 million received from the settlement of acquired oil, gas and NGL derivative contracts for the three and six months ended June 30, 2026, respectively, and does not include $17.0 million or $34.9 million received from the settlement of acquired oil, gas and NGL derivative contracts for the three and six months ended June 30, 2025, respectively.
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Results of operations:
Three Months Ended June 30, 2026 Compared to Three Months Ended June 30, 2025
Revenues
The following table provides the components of our revenues, respective average realized prices and net sales volumes for the periods indicated:
| Three Months Ended June 30, | |||||||||||||||||||||||||||||||||||||||||||||||
| 2026 | 2025 | $ Change | % Change | ||||||||||||||||||||||||||||||||||||||||||||
| Revenues (in thousands): | |||||||||||||||||||||||||||||||||||||||||||||||
| Oil | $ | 1,226,826 | $ | 602,488 | $ | 624,338 | 104 | % | |||||||||||||||||||||||||||||||||||||||
| Natural gas | 33,776 | 159,001 | (125,225) | (79) | % | ||||||||||||||||||||||||||||||||||||||||||
| Natural gas liquids | 129,371 | 98,142 | 31,229 | 32 | % | ||||||||||||||||||||||||||||||||||||||||||
| Midstream and other | 4,981 | 38,352 | (33,371) | (87) | % | ||||||||||||||||||||||||||||||||||||||||||
| Total revenues | $ | 1,394,954 | $ | 897,983 | $ | 496,971 | 55 | % | |||||||||||||||||||||||||||||||||||||||
| Average realized prices, before effects of derivative settlements: | |||||||||||||||||||||||||||||||||||||||||||||||
| Oil ($/Bbl) | $ | 96.61 | $ | 61.47 | $ | 35.14 | 57 | % | |||||||||||||||||||||||||||||||||||||||
| Natural gas ($/Mcf) | 0.52 | 2.71 | (2.19) | (81) | % | ||||||||||||||||||||||||||||||||||||||||||
| NGLs ($/Bbl) | 18.67 | 22.59 | (3.92) | (17) | % | ||||||||||||||||||||||||||||||||||||||||||
| Total ($/Boe) | 45.63 | 35.96 | 9.67 | 27 | % | ||||||||||||||||||||||||||||||||||||||||||
| Net sales volumes: | |||||||||||||||||||||||||||||||||||||||||||||||
| Oil (MBbls) | 12,699 | 9,801 | 2,898 | 30 | % | ||||||||||||||||||||||||||||||||||||||||||
| Natural gas (MMcf) | 65,022 | 58,572 | 6,450 | 11 | % | ||||||||||||||||||||||||||||||||||||||||||
| NGLs (MBbls) | 6,929 | 4,345 | 2,584 | 59 | % | ||||||||||||||||||||||||||||||||||||||||||
| Total (MBoe) | 30,465 | 23,908 | 6,557 | 27 | % | ||||||||||||||||||||||||||||||||||||||||||
| Average daily net sales volumes: | |||||||||||||||||||||||||||||||||||||||||||||||
| Oil (MBbls/d) | 140 | 108 | 32 | 30 | % | ||||||||||||||||||||||||||||||||||||||||||
| Natural gas (MMcf/d) | 715 | 644 | 71 | 11 | % | ||||||||||||||||||||||||||||||||||||||||||
| NGLs (MBbls/d) | 76 | 48 | 28 | 58 | % | ||||||||||||||||||||||||||||||||||||||||||
| Total (MBoe/d) | 335 | 263 | 72 | 27 | % | ||||||||||||||||||||||||||||||||||||||||||
Oil revenue. Oil revenue increased $624.3 million, or 104%, in the three months ended June 30, 2026, compared to the three months ended June 30, 2025. This was driven by higher realized oil prices that resulted in an increase of $446.2 million (an increase of 57% per Bbl) and a $178.1 million increase from higher sales volume (32 MBbls/d, or 30%). The increase in sales volumes was primarily driven by the Vital Energy Merger, partially offset by our 2025 divestitures. The increase in realized oil prices was due to higher index pricing and more favorable price differentials.
Natural gas revenue. Natural gas revenue decreased $125.2 million, or 79%, in the three months ended June 30, 2026, compared to the three months ended June 30, 2025. This was driven by lower natural gas prices that resulted in a decrease of $142.4 million (a decrease of 81% per Mcf), partially offset by a $17.2 million increase from higher sales volume (71 MMcf/d, or 11%). The increase in sales volumes was primarily due to the Vital Energy Merger, partially offset by our 2025 divestitures. The decrease in realized natural gas prices was due to lower index pricing and a decrease in our price differentials due to the Vital Energy Merger and resulting differentials in the Permian Basin.
NGL revenue. NGL revenue increased $31.2 million, or 32%, in the three months ended June 30, 2026, compared to the three months ended June 30, 2025. This was driven primarily by a $58.4 million increase from higher sales volume (28 MBbls/d, or 58%), partially offset by lower realized NGL prices that resulted in a decrease of $27.2 million (a decrease of 17% per Bbl). The increase in sales volumes was primarily driven by the Vital Energy Merger, partially offset by our 2025 divestitures.
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Midstream and other revenue. Midstream and other revenue decreased $33.4 million, or 87%, in the three months ended June 30, 2026, compared to the three months ended June 30, 2025, driven primarily by our 2025 divestitures.
Expenses
The following table summarizes our expenses for the periods indicated and includes a presentation on a per Boe basis, as we use this information to evaluate our performance relative to our peers and to identify and measure trends we believe may require additional analysis:
| Three Months Ended June 30, | |||||||||||||||||||||||||||||||||||||||||||||||
| 2026 | 2025 | $ Change | % Change | ||||||||||||||||||||||||||||||||||||||||||||
| Expenses (in thousands): | |||||||||||||||||||||||||||||||||||||||||||||||
| Operating expense | $ | 407,672 | $ | 390,031 | $ | 17,641 | 5 | % | |||||||||||||||||||||||||||||||||||||||
| Depreciation, depletion and amortization | 358,004 | 297,056 | 60,948 | 21 | % | ||||||||||||||||||||||||||||||||||||||||||
| Impairment of oil and natural gas properties | — | 2,985 | (2,985) | NM* | |||||||||||||||||||||||||||||||||||||||||||
| General and administrative expense | 61,494 | 124,612 | (63,118) | (51) | % | ||||||||||||||||||||||||||||||||||||||||||
| Other operating costs | (13,202) | 3,664 | (16,866) | NM* | |||||||||||||||||||||||||||||||||||||||||||
| Total expenses | $ | 813,968 | $ | 818,348 | $ | (4,380) | (1) | % | |||||||||||||||||||||||||||||||||||||||
| Selected expenses per Boe: | |||||||||||||||||||||||||||||||||||||||||||||||
| Operating expense | $ | 13.38 | $ | 16.31 | $ | (2.93) | (18) | % | |||||||||||||||||||||||||||||||||||||||
| Depreciation, depletion and amortization | 11.75 | 12.42 | (0.67) | (5) | % | ||||||||||||||||||||||||||||||||||||||||||
* NM = Not meaningful.
Operating expense. Operating expense increased $17.6 million, or 5%, in the three months ended June 30, 2026, compared to the three months ended June 30, 2025, driven primarily by the following factors:
(i)Lease and asset operating expense increased $26.7 million, or 15%, in the three months ended June 30, 2026, compared to the three months ended June 30, 2025, and decreased $0.75 per Boe, or 10%, to $6.80 per Boe. This $26.7 million increase was driven primarily by higher production from the Vital Energy Merger, which was more than offset on a per Boe basis with the additional acquired volumes and 2025 divestitures.
(ii)Gathering, processing and transportation expense decreased $11.6 million, or 11%, in the three months ended June 30, 2026, compared to the three months ended June 30, 2025, and decreased $1.34 per Boe, or 30%, to $3.10 per Boe. These per Boe decreases were driven primarily by the Vital Energy Merger and our 2025 divestitures.
(iii)Production and other taxes increased $13.9 million, or 25%, in the three months ended June 30, 2026, compared to the three months ended June 30, 2025, and decreased $0.03 per Boe, or 1%, to $2.27 per Boe. This increase was driven primarily by the additional production from the Vital Energy Merger and higher oil prices.
(iv)Workover expense increased $13.5 million, or 70%, in the three months ended June 30, 2026, compared to the three months ended June 30, 2025, and increased $0.27 per Boe, or 33%, to $1.08 per Boe. This increase was primarily driven by the Vital Energy Merger.
(v)Midstream and other operating expense decreased $24.9 million, or 86%, in the three months ended June 30, 2026, compared to the three months ended June 30, 2025, primarily due to our 2025 divestitures.
Depreciation, depletion and amortization. In the three months ended June 30, 2026, depreciation, depletion and amortization increased $60.9 million, or 21%, compared to the three months ended June 30, 2025, driven primarily by increased production from the Vital Energy Merger.
Impairment expense. During the three months ended June 30, 2025, we recorded an impairment of $3.0 million to write down the value of certain assets to expected net proceeds. We did not recognize impairment expense during the three months ended June 30, 2026.
General and administrative expense. General and administrative expense decreased $63.1 million, or 51%, for the three months ended June 30, 2026, compared to the three months ended June 30, 2025. The decrease was driven by a decrease in equity-based compensation expense of $72.1 million (2026 and 2025 include an additional true-up expense of $0.4 million and $69.3 million due to changes in estimate) partially offset by (i) higher recurring General and administrative expense primarily due to
41
an increase in Manager Compensation as a result of the Vital Energy Merger and (ii) $0.1 million higher transaction and nonrecurring related expenses.
| Three Months Ended June 30, | |||||||||||||||||||||||||||||||||||||||||||||||
| 2026 | 2025 | $ Change | % Change | ||||||||||||||||||||||||||||||||||||||||||||
| General and administrative expense (in thousands): | |||||||||||||||||||||||||||||||||||||||||||||||
| Recurring general and administrative expense | $ | 38,120 | $ | 29,275 | $ | 8,845 | 30 | % | |||||||||||||||||||||||||||||||||||||||
| Transaction and nonrecurring expenses | 1,867 | 1,769 | 98 | 6 | % | ||||||||||||||||||||||||||||||||||||||||||
| Equity-based compensation | 21,507 | 93,568 | (72,061) | (77) | % | ||||||||||||||||||||||||||||||||||||||||||
| Total general and administrative expense | $ | 61,494 | $ | 124,612 | $ | (63,118) | (51) | % | |||||||||||||||||||||||||||||||||||||||
| General and administrative expense per Boe: | |||||||||||||||||||||||||||||||||||||||||||||||
| Recurring general and administrative expense | $ | 1.25 | $ | 1.22 | $ | 0.03 | 2 | % | |||||||||||||||||||||||||||||||||||||||
| Transaction and nonrecurring expenses | 0.06 | 0.07 | (0.01) | (14) | % | ||||||||||||||||||||||||||||||||||||||||||
| Equity-based compensation | 0.71 | 3.91 | (3.20) | (82) | % | ||||||||||||||||||||||||||||||||||||||||||
Other operating costs. Other operating costs include exploration expense and gain on sale of assets. Other operating costs decreased by $16.9 million, compared to the three months ended June 30, 2025, primarily driven by $5.2 million lower exploration expense recognized during the three months ended June 30, 2026 and a $11.7 million change in the gain or loss from the sale of assets.
Interest expense. In the three months ended June 30, 2026, we incurred interest expense of $99.8 million, as compared to $75.2 million in the three months ended June 30, 2025, a 33% increase. This increase was driven primarily by higher average debt balances as a result of the Vital Energy Merger.
Gain (loss) on derivatives. We have entered into derivative contracts to manage our exposure to commodity price risks that impact our revenues and have derivative gains and losses related to our contingent earn-out consideration. Our gain on derivatives during the three months ended June 30, 2026 decreased by $16.7 million, primarily due to changes in commodity prices relative to our strike price.
Income tax benefit (expense). We are a corporation that is subject to U.S. federal and state income taxes on our allocable share of any taxable income from OpCo. OpCo is a partnership and is generally not subject to U.S. federal and certain state taxes. For the three months ended June 30, 2026 and 2025, we recognized income tax expense of $169.9 million and income tax expense of $41.1 million, respectively, for an effective tax rate of 25.6% and 20.2%, respectively. Our effective tax rate for the three months ended June 30, 2026 was higher than the statutory rate primarily due to the permanent difference recognized in conjunction with the performance stock units granted to our Manager (“Manager PSUs”).
Adjusted EBITDAX (non-GAAP) and Levered Free Cash Flow (non-GAAP)
Adjusted EBITDAX and Levered Free Cash Flow are supplemental non-GAAP financial measures used by our management to assess our operating results and liquidity. See “—Non-GAAP financial measures” section below for their definitions and application.
The following table presents a reconciliation of Adjusted EBITDAX (non-GAAP) and Levered Free Cash Flow (non-GAAP) to net income (loss) and Levered Free Cash Flow (non-GAAP) to Net cash provided by operating activities, the most directly comparable financial measures, respectively, calculated in accordance with GAAP:
42
| Three Months Ended June 30, | |||||||||||||||||||||||||||||||||||||||||||||||
| 2026 | 2025 | $ Change | % Change | ||||||||||||||||||||||||||||||||||||||||||||
(in thousands, except percentages) | |||||||||||||||||||||||||||||||||||||||||||||||
| Net income (loss) | $ | 493,704 | $ | 162,498 | $ | 331,206 | 204 | % | |||||||||||||||||||||||||||||||||||||||
| Adjustments to reconcile to Adjusted EBITDAX: | |||||||||||||||||||||||||||||||||||||||||||||||
| Interest expense | 99,823 | 75,219 | |||||||||||||||||||||||||||||||||||||||||||||
| Income tax expense (benefit) | 169,920 | 41,057 | |||||||||||||||||||||||||||||||||||||||||||||
| Depreciation, depletion and amortization | 358,004 | 297,056 | |||||||||||||||||||||||||||||||||||||||||||||
| Exploration expense | 366 | 5,574 | |||||||||||||||||||||||||||||||||||||||||||||
| Non-cash (gain) loss on derivatives | (419,080) | (178,592) | |||||||||||||||||||||||||||||||||||||||||||||
| Impairment expense | — | 2,985 | |||||||||||||||||||||||||||||||||||||||||||||
| Non-cash equity-based compensation expense | 21,280 | 93,268 | |||||||||||||||||||||||||||||||||||||||||||||
| (Gain) loss on sale of assets | (13,568) | (1,910) | |||||||||||||||||||||||||||||||||||||||||||||
| Other (income) expense | (471) | (115) | |||||||||||||||||||||||||||||||||||||||||||||
Transaction and nonrecurring expenses (1) | 25,893 | (193) | |||||||||||||||||||||||||||||||||||||||||||||
| Settlement of acquired derivative contracts | 62,069 | 17,007 | |||||||||||||||||||||||||||||||||||||||||||||
| Adjusted EBITDAX (non-GAAP) | $ | 797,940 | $ | 513,854 | $ | 284,086 | 55 | % | |||||||||||||||||||||||||||||||||||||||
| Adjustments to reconcile to Levered Free Cash Flow: | |||||||||||||||||||||||||||||||||||||||||||||||
| Interest expense, excluding non-cash amortization of deferred financing costs, discounts, and premiums | (95,576) | (71,430) | |||||||||||||||||||||||||||||||||||||||||||||
| Current income tax benefit (expense) | (562) | (6,673) | |||||||||||||||||||||||||||||||||||||||||||||
| Tax-related redeemable noncontrolling interest distributions made by OpCo | — | (165) | |||||||||||||||||||||||||||||||||||||||||||||
| Development of oil and natural gas properties | (284,124) | (264,711) | |||||||||||||||||||||||||||||||||||||||||||||
| Levered Free Cash Flow (non-GAAP) | $ | 417,678 | $ | 170,875 | $ | 246,803 | 144 | % | |||||||||||||||||||||||||||||||||||||||
(1)Transaction and nonrecurring expenses of $25.9 million for the three months ended June 30, 2026 were primarily related to earn-out payments for the Ridgemar Acquisition, and divestiture and restructuring costs. Transaction and nonrecurring expense credits of $0.2 million for the three months ended June 30, 2025 were primarily related to proceeds from a legal settlement mostly offset by uncapitalized transaction costs related to the Ridgemar Acquisition and transaction costs related to our divestitures.
| Three Months Ended June 30, | |||||||||||||||||||||||
| 2026 | 2025 | $ Change | % Change | ||||||||||||||||||||
| (in thousands, except percentages) | |||||||||||||||||||||||
| Net cash provided by operating activities | $ | 706,788 | $ | 498,966 | $ | 207,822 | 42 | % | |||||||||||||||
| Changes in operating assets and liabilities | (34,710) | (73,544) | |||||||||||||||||||||
| Tax-related redeemable noncontrolling interest contributions (distributions) made by OpCo | — | (165) | |||||||||||||||||||||
Transaction and nonrecurring expenses (1) | 25,893 | (193) | |||||||||||||||||||||
| Exploration expense | 366 | 5,574 | |||||||||||||||||||||
| Other adjustments and operating activities | 3,465 | 4,948 | |||||||||||||||||||||
| Development of oil and natural gas properties | (284,124) | (264,711) | |||||||||||||||||||||
| Levered Free Cash Flow (non-GAAP) | $ | 417,678 | $ | 170,875 | $ | 246,803 | 144 | % | |||||||||||||||
(1)Transaction and nonrecurring expenses of $25.9 million for the three months ended June 30, 2026 were primarily related to earn-out payments for the Ridgemar Acquisition, and divestiture and restructuring costs. Transaction and nonrecurring expense credits of $0.2 million for the three months ended June 30, 2025 were primarily related to proceeds from a legal settlement mostly offset by uncapitalized transaction costs related to the Ridgemar Acquisition and transaction costs related to our divestitures.
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Adjusted EBITDAX (non-GAAP) increased by $284.1 million, or 55%, in the three months ended June 30, 2026, compared to the three months ended June 30, 2025, primarily driven by additional production from the Vital Energy Merger and increased oil pricing.
Levered Free Cash Flow (non-GAAP) increased by $246.8 million, or 144%, in the three months ended June 30, 2026 compared to the three months ended June 30, 2025, primarily driven by increased Adjusted EBITDAX, partially offset by $19.4 million of increased development of oil and natural gas properties expenditures and additional interest expense.
Six Months Ended June 30, 2026 Compared to Six Months Ended June 30, 2025
Revenues
The following table provides the components of our revenues, respective average realized prices and net sales volumes for the periods indicated:
| Six Months Ended June 30, | |||||||||||||||||||||||||||||||||||||||||||||||
| 2026 | 2025 | $ Change | % Change | ||||||||||||||||||||||||||||||||||||||||||||
| Revenues (in thousands): | |||||||||||||||||||||||||||||||||||||||||||||||
| Oil | $ | 2,120,146 | $ | 1,222,147 | $ | 897,999 | 73 | % | |||||||||||||||||||||||||||||||||||||||
| Natural gas | 192,141 | 346,441 | (154,300) | (45) | % | ||||||||||||||||||||||||||||||||||||||||||
| Natural gas liquids | 254,478 | 205,717 | 48,761 | 24 | % | ||||||||||||||||||||||||||||||||||||||||||
| Midstream and other | 11,019 | 73,851 | (62,832) | (85) | % | ||||||||||||||||||||||||||||||||||||||||||
| Total revenues | $ | 2,577,784 | $ | 1,848,156 | $ | 729,628 | 39 | % | |||||||||||||||||||||||||||||||||||||||
| Average realized prices, before effects of derivative settlements: | |||||||||||||||||||||||||||||||||||||||||||||||
| Oil ($/Bbl) | $ | 83.86 | $ | 64.45 | $ | 19.41 | 30 | % | |||||||||||||||||||||||||||||||||||||||
| Natural gas ($/Mcf) | 1.46 | 2.95 | (1.49) | (51) | % | ||||||||||||||||||||||||||||||||||||||||||
| NGLs ($/Bbl) | 18.36 | 23.99 | (5.63) | (23) | % | ||||||||||||||||||||||||||||||||||||||||||
| Total ($/Boe) | 42.00 | 37.65 | 4.35 | 12 | % | ||||||||||||||||||||||||||||||||||||||||||
| Net sales volumes: | |||||||||||||||||||||||||||||||||||||||||||||||
| Oil (MBbls) | 25,281 | 18,962 | 6,319 | 33 | % | ||||||||||||||||||||||||||||||||||||||||||
| Natural gas (MMcf) | 131,882 | 117,526 | 14,356 | 12 | % | ||||||||||||||||||||||||||||||||||||||||||
| NGLs (MBbls) | 13,859 | 8,576 | 5,283 | 62 | % | ||||||||||||||||||||||||||||||||||||||||||
| Total (MBoe) | 61,120 | 47,125 | 13,995 | 30 | % | ||||||||||||||||||||||||||||||||||||||||||
| Average daily net sales volumes: | |||||||||||||||||||||||||||||||||||||||||||||||
| Oil (MBbls/d) | 140 | 105 | 35 | 33 | % | ||||||||||||||||||||||||||||||||||||||||||
| Natural gas (MMcf/d) | 729 | 649 | 80 | 12 | % | ||||||||||||||||||||||||||||||||||||||||||
| NGLs (MBbls/d) | 77 | 47 | 30 | 64 | % | ||||||||||||||||||||||||||||||||||||||||||
| Total (MBoe/d) | 338 | 260 | 78 | 30 | % | ||||||||||||||||||||||||||||||||||||||||||
Oil revenue. Oil revenue increased $898.0 million, or 73%, in the six months ended June 30, 2026, compared to the six months ended June 30, 2025. This was driven by a $407.3 million increase from higher sales volume (35 MBbls/d, or 33%), and higher realized oil prices that resulted in an increase of $490.7 million (an increase of 30% per Bbl). The increase in sales volumes was primarily driven by the Vital Energy Merger, partially offset by our 2025 divestitures. The increase in realized oil prices was due to higher index pricing and more favorable price differentials.
Natural gas revenue. Natural gas revenue decreased $154.3 million, or 45%, in the six months ended June 30, 2026, compared to the six months ended June 30, 2025. The decrease was driven by lower natural gas prices that resulted in a decrease of $196.5 million (a decrease of 51% per Mcf), partially offset by a $42.2 million increase from higher sales volume (80 MMcf/d, or 12%). The increase in sales volumes was primarily due to the Vital Energy Merger, partially offset by our 2025 divestitures. The decrease in realized natural gas prices was due to a decrease in our price differentials due to the Vital Energy Merger and resulting differentials in the Permian Basin.
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NGL revenue. NGL revenue increased $48.8 million, or 24%, in the six months ended June 30, 2026, compared to the six months ended June 30, 2025. This was driven primarily by a $126.8 million increase from higher sales volume (30 MBbls/d, or 64%), partially offset by lower realized NGL prices that resulted in a decrease of $78.0 million (a decrease of 23% per Bbl). The increase in sales volumes was primarily driven by the Vital Energy Merger, partially offset by our 2025 divestitures.
Midstream and other revenue. Midstream and other revenue decreased $62.8 million, or 85%, in the six months ended June 30, 2026, compared to the six months ended June 30, 2025, driven primarily by our 2025 divestitures.
Expenses
The following table summarizes our expenses for the periods indicated and includes a presentation on a per Boe basis, as we use this information to evaluate our performance relative to our peers and to identify and measure trends we believe may require additional analysis:
| Six Months Ended June 30, | |||||||||||||||||||||||||||||||||||||||||||||||
| 2026 | 2025 | $ Change | % Change | ||||||||||||||||||||||||||||||||||||||||||||
| Expenses (in thousands): | |||||||||||||||||||||||||||||||||||||||||||||||
| Operating expense | $ | 836,688 | $ | 793,542 | $ | 43,146 | 5 | % | |||||||||||||||||||||||||||||||||||||||
| Depreciation, depletion and amortization | 712,129 | 579,629 | 132,500 | 23 | % | ||||||||||||||||||||||||||||||||||||||||||
| Impairment of oil and natural gas properties | — | 48,632 | (48,632) | NM* | |||||||||||||||||||||||||||||||||||||||||||
| General and administrative expense | 124,294 | 181,382 | (57,088) | (31) | % | ||||||||||||||||||||||||||||||||||||||||||
| Other operating costs | (3,805) | (6,892) | 3,087 | NM* | |||||||||||||||||||||||||||||||||||||||||||
| Total expenses | $ | 1,669,306 | $ | 1,596,293 | $ | 73,013 | 5 | % | |||||||||||||||||||||||||||||||||||||||
| Selected expenses per Boe: | |||||||||||||||||||||||||||||||||||||||||||||||
| Operating expense | $ | 13.69 | $ | 16.84 | $ | (3.15) | (19) | % | |||||||||||||||||||||||||||||||||||||||
| Depreciation, depletion and amortization | 11.65 | 12.30 | (0.65) | (5) | % | ||||||||||||||||||||||||||||||||||||||||||
* NM = Not meaningful.
Operating expense. Operating expense increased $43.1 million, or 5%, in the six months ended June 30, 2026, compared to the six months ended June 30, 2025, driven primarily by the following factors:
(i)Lease and asset operating expense increased $68.8 million, or 18%, in the six months ended June 30, 2026, compared to the six months ended June 30, 2025, and decreased $0.68 per Boe, or 9%, to $7.22 per Boe. This $68.8 million increase was driven primarily by higher production from the Vital Energy Merger, which was more than offset on a per Boe basis with the additional acquired volumes and our 2025 divestitures.
(ii)Gathering, processing and transportation expense decreased $14.8 million, or 7%, in the six months ended June 30, 2026, compared to the six months ended June 30, 2025, and decreased $1.27 per Boe, or 28%, to $3.22 per Boe. The decrease was driven primarily by the Vital Energy Merger and our 2025 divestitures.
(iii)Production and other taxes increased $9.2 million, or 8%, in the six months ended June 30, 2026, compared to the six months ended June 30, 2025, and decreased $0.41 per Boe, or 17%, to $2.04 per Boe. This increase was driven primarily by production from the Vital Energy Merger and higher oil prices, partially offset by our 2025 divestitures that were subject to higher production tax rates.
(iv)Workover expense increased $27.9 million, or 79%, in the six months ended June 30, 2026, compared to the six months ended June 30, 2025, and increased $0.28 per Boe, or 37%, to $1.03 per Boe. This increase was primarily driven by the Vital Energy Merger.
(v)Midstream and other operating expense decreased $47.9 million, or 81%, in the six months ended June 30, 2026, compared to the six months ended June 30, 2025, primarily due to our 2025 divestitures.
Depreciation, depletion and amortization. In the six months ended June 30, 2026, depreciation, depletion and amortization increased $132.5 million, or 23%, compared to the six months ended June 30, 2025, driven primarily by increased production from the Vital Energy Merger.
Impairment expense. During the six months ended June 30, 2025, we recorded an impairment of $48.6 million to write down the value of certain assets to expected net proceeds. We did not have impairment expense during the six months ended June 30, 2026.
45
General and administrative expense. General and administrative expense decreased $57.1 million, or 31%, for the six months ended June 30, 2026, compared to the six months ended June 30, 2025. The decrease was driven by a decrease in equity-based compensation expense of $74.2 million, (2026 and 2025 include an additional true-up expense of $2.4 million and $77.9 million, respectively, due to changes in estimate), partially offset by (i) higher recurring General and administrative expense primarily due to an increase in Manager Compensation as a result of the Vital Energy Merger and (ii) $5.2 million higher transaction and nonrecurring related expenses.
| Six Months Ended June 30, | |||||||||||||||||||||||||||||||||||||||||||||||
| 2026 | 2025 | $ Change | % Change | ||||||||||||||||||||||||||||||||||||||||||||
| General and administrative expense (in thousands): | |||||||||||||||||||||||||||||||||||||||||||||||
| Recurring general and administrative expense | $ | 68,992 | $ | 57,087 | $ | 11,905 | 21 | % | |||||||||||||||||||||||||||||||||||||||
| Transaction and nonrecurring expenses | 9,295 | 4,089 | 5,206 | 127 | % | ||||||||||||||||||||||||||||||||||||||||||
| Equity-based compensation | 46,007 | 120,206 | (74,199) | (62) | % | ||||||||||||||||||||||||||||||||||||||||||
| Total general and administrative expense | $ | 124,294 | $ | 181,382 | $ | (57,088) | (31) | % | |||||||||||||||||||||||||||||||||||||||
| General and administrative expense per Boe: | |||||||||||||||||||||||||||||||||||||||||||||||
| Recurring general and administrative expense | $ | 1.13 | $ | 1.21 | $ | (0.08) | (7) | % | |||||||||||||||||||||||||||||||||||||||
| Transaction and nonrecurring expenses | 0.15 | 0.09 | 0.06 | 67 | % | ||||||||||||||||||||||||||||||||||||||||||
| Equity-based compensation | 0.75 | 2.55 | (1.80) | (71) | % | ||||||||||||||||||||||||||||||||||||||||||
Other operating costs. Other operating costs include exploration expense and gain on sale of assets. Other operating costs increased by $3.1 million, compared to the six months ended June 30, 2025, primarily driven by a $2.1 million lower gain on sale of assets and $1.0 million higher exploration expense recognized during the six months ended June 30, 2026.
Interest expense. In the six months ended June 30, 2026, we incurred interest expense of $204.4 million, as compared to $148.4 million in the six months ended June 30, 2025. This increase was driven primarily by higher average debt balances as a result of the Vital Energy Merger.
Loss on extinguishment of debt. During the six months ended June 30, 2026, we incurred a loss on extinguishment of debt of
$17.4 million related to $12.0 million premium for the 2028 Notes Redemption and our repurchases of the 2029 Notes, and $5.4 million related to the non-cash write-off of outstanding deferred financing costs, discounts, and premiums. During the six months ended June 30, 2025, we did not incur a loss on the extinguishment of debt.
Gain (loss) on derivatives. We have entered into derivative contracts to manage our exposure to commodity price risks that impact our revenues and have derivative gains and losses related to our contingent earn-out consideration. Our loss on derivatives during the six months ended June 30, 2026 changed by $632.3 million, from a comparable gain during the six months ended June 30, 2025 primarily due to changes in commodity prices relative to our strike prices.
Income tax benefit (expense). We are a corporation that is subject to U.S. federal and state income taxes on our allocable share of any taxable income from OpCo. OpCo is a partnership and is generally not subject to U.S. federal and certain state taxes. For the six months ended June 30, 2026 and 2025, we recognized income tax expense of $87.6 million and income tax expense of $43.7 million, respectively, for an effective tax rate of 54.0% and 20.6%, respectively. Historically, our effective tax rate has typically been lower than the U.S. federal statutory income tax rate of 21% primarily due to effects of removing income and losses related to our noncontrolling interests and redeemable noncontrolling interests. However, as part of our Corporate Simplification, we expect our effective rate to be more in line with the U.S. federal statutory income tax rate plus our blended state income tax rate. Our effective tax rate for the six months ended June 30, 2026 was higher than the statutory rate primarily due to the significant discrete items, including permanent differences recognized in connection with the Manager PSUs that vested during the six months ended June 30, 2026.
Adjusted EBITDAX (non-GAAP) and Levered Free Cash Flow (non-GAAP)
Adjusted EBITDAX and Levered Free Cash Flow are supplemental non-GAAP financial measures used by our management to assess our operating results and liquidity. See “—Non-GAAP financial measures” section below for their definitions and application.
46
The following table presents a reconciliation of Adjusted EBITDAX (non-GAAP) and Levered Free Cash Flow (non-GAAP) to net income (loss) and Levered Free Cash Flow (non-GAAP) to Net cash provided by operating activities, the most directly comparable financial measures, respectively calculated in accordance with GAAP:
| Six Months Ended June 30, | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| 2026 | 2025 | $ Change | % Change | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| (in thousands, except percentages) | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Net income (loss) | $ | 74,528 | $ | 168,412 | $ | (93,884) | (56) | % | |||||||||||||||||||||||||||||||||||||||||||||||||||
| Adjustments to reconcile to Adjusted EBITDAX: | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Interest expense | 204,397 | 148,400 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Loss from extinguishment of debt | 17,397 | — | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Income tax expense (benefit) | 87,648 | 43,670 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Depreciation, depletion and amortization | 712,129 | 579,629 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Exploration expense | 6,885 | 5,880 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Non-cash (gain) loss on derivatives | 181,539 | (98,362) | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Impairment expense | — | 48,632 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Non-cash equity-based compensation expense | 44,709 | 119,493 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| (Gain) loss on sale of assets | (10,690) | (12,772) | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Other (income) expense | (144) | (231) | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Certain redeemable noncontrolling interest distributions made by OpCo (1) | — | (4,242) | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Transaction and nonrecurring expenses (2) | 46,641 | 9,906 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Settlement of acquired derivative contracts | 122,632 | 34,895 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Adjusted EBITDAX (non-GAAP) | $ | 1,487,671 | $ | 1,043,310 | $ | 444,361 | 43 | % | |||||||||||||||||||||||||||||||||||||||||||||||||||
| Adjustments to reconcile to Levered Free Cash Flow: | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Interest expense, excluding non-cash amortization of deferred financing costs, discounts, and premiums | (196,164) | (140,859) | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Loss from extinguishment of debt, excluding non-cash write-off of deferred financing costs, discounts, and premiums | (11,963) | — | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Current income tax benefit (expense) | (1,179) | (17,486) | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Tax-related redeemable noncontrolling interest distributions made by OpCo | — | (260) | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Development of oil and natural gas properties | (668,848) | (472,253) | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Levered Free Cash Flow (non-GAAP) | $ | 609,517 | $ | 412,452 | $ | 197,065 | 48 | % | |||||||||||||||||||||||||||||||||||||||||||||||||||
(1)In our calculation of Adjusted EBITDAX and Levered Free Cash Flow, we reflected Manager Compensation as if 100% of OpCo were owned and managed by the Company, to reflect consistent earnings and liquidity measures not impacted by the amount of OpCo’s ownership under management. After giving effect to the Corporate Simplification, the Company owns 100% of outstanding OpCo Units and no longer makes distributions to the holders of redeemable noncontrolling interests in OpCo.
(2)Transaction and nonrecurring expenses of $46.6 million for the six months ended June 30, 2026 were primarily related to earn-out payments for the Ridgemar Acquisition, Vital Energy Merger transaction costs, capital markets transactions and divestiture and restructuring costs. Transaction and nonrecurring expenses of $9.9 million for the six months ended June 30, 2025 were primarily related to uncapitalized transaction costs related to the Ridgemar Acquisition and transaction costs related to our divestitures and the SilverBow Merger, partially offset by proceeds from a legal settlement.
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| Six Months Ended June 30, | |||||||||||||||||||||||
| 2026 | 2025 | $ Change | % Change | ||||||||||||||||||||
| (in thousands, except percentages) | |||||||||||||||||||||||
| Net cash provided by operating activities | $ | 1,115,979 | $ | 836,080 | $ | 279,899 | 33 | % | |||||||||||||||
| Changes in operating assets and liabilities | 107,557 | 21,758 | |||||||||||||||||||||
Certain redeemable noncontrolling interest distributions made by OpCo (1) | — | (4,242) | |||||||||||||||||||||
| Tax-related redeemable noncontrolling interest contributions (distributions) made by OpCo | — | (260) | |||||||||||||||||||||
Transaction and nonrecurring expenses (2) | 46,641 | 9,906 | |||||||||||||||||||||
| Loss from extinguishment of debt, excluding non-cash write-off of deferred financing costs, discounts, and premiums | (11,963) | — | |||||||||||||||||||||
| Exploration expense | 6,885 | 5,880 | |||||||||||||||||||||
| Other adjustments and operating activities | 13,266 | 15,583 | |||||||||||||||||||||
| Development of oil and natural gas properties | (668,848) | (472,253) | |||||||||||||||||||||
| Levered Free Cash Flow (non-GAAP) | $ | 609,517 | $ | 412,452 | $ | 197,065 | 48 | % | |||||||||||||||
(1)In our calculation of Adjusted EBITDAX and Levered Free Cash Flow, we reflected Manager Compensation as if 100% of OpCo were owned and managed by the Company, to reflect consistent earnings and liquidity measures not impacted by the amount of OpCo’s ownership under management. After giving effect to the Corporate Simplification, the Company owns 100% of outstanding OpCo Units and no longer makes distributions to the holders of redeemable noncontrolling interests in OpCo.
(2)Transaction and nonrecurring expenses of $46.6 million for the six months ended June 30, 2026 were primarily related to earn-out payments for the Ridgemar Acquisition, Vital Energy Merger transaction costs, capital markets transactions and divestiture and restructuring costs. Transaction and nonrecurring expenses of $9.9 million for the six months ended June 30, 2025 were primarily related to uncapitalized transaction costs related to the Ridgemar Acquisition and transaction costs related to our divestitures and the SilverBow Merger, partially offset by proceeds from a legal settlement.
Adjusted EBITDAX (non-GAAP) increased by $444.4 million, or 43%, in the six months ended June 30, 2026, compared to the six months ended June 30, 2025, primarily driven by additional production from the Vital Energy Merger and increased oil pricing.
Levered Free Cash Flow (non-GAAP) increased by $197.1 million, or 48%, in the six months ended June 30, 2026 compared to the six months ended June 30, 2025, primarily driven by increased Adjusted EBITDAX, partially offset by $196.6 million of increased development of oil and natural gas properties expenditures and additional interest expense.
Liquidity and capital resources
Our primary sources of liquidity are cash on hand, cash flow from operations, proceeds from equity and debt offerings and borrowings under our senior secured reserve-based revolving credit agreements. Our primary expected uses of capital are for dividends to shareholders, our share repurchase program, debt repayment, including open market repurchases of our Senior Notes, development of our existing assets and acquisitions.
Our development program is designed to prioritize the generation of meaningful free cash flow and attractive risk-adjusted returns and is inherently flexible, with the ability to scale our capital program as necessary to react to the existing market environment and ongoing asset performance. See “—Development program and capital budget” above for additional discussion of our capital program.
We plan to continue our practice of entering into economic hedging arrangements to reduce the impact of the near-term volatility of commodity prices and the resulting impact on our cash flow from operations. A key tenet of our focused risk management efforts is an active economic hedge strategy to mitigate near-term price volatility while maintaining long-term exposure to underlying commodity prices. Our commodity derivative program focuses on entering into forward commodity contracts when investment decisions regarding reinvestment in existing assets or new acquisitions are finalized, targeting economic hedges for a portion of expected production generated by the capital investment as well as adding incremental derivatives to our production base over time. Our active derivative program allows us to protect margins and corporate returns through commodity cycles.
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The following table presents our cash balances and outstanding borrowings at the end of each period presented:
| June 30, 2026 | December 31, 2025 | ||||||||||
| (in thousands) | |||||||||||
| Cash and cash equivalents | $ | 264,882 | $ | 10,157 | |||||||
| Long-term debt | 5,166,022 | 5,524,128 | |||||||||
Based on our planned capital spending, our forecasted cash flows and projected levels of indebtedness, we expect to maintain compliance with the covenants under our debt agreements. Further, based on current market indications, we expect to meet in the ordinary course of business other contractual cash commitments to third parties pursuant to the various agreements described under the heading “Contractual obligations” in our Annual Report, recognizing we may be required to meet such commitments even if our business plan assumptions were to change.
Cash flows
The following table summarizes our cash flows for the periods indicated:
| Six Months Ended June 30, | |||||||||||||||||||||||
| 2026 | 2025 | ||||||||||||||||||||||
| (in thousands) | |||||||||||||||||||||||
| Net cash provided by operating activities | $ | 1,115,979 | $ | 836,080 | |||||||||||||||||||
| Net cash used in investing activities | (1,003,650) | (1,269,111) | |||||||||||||||||||||
| Net cash provided by (used in) financing activities | (576,492) | 213,380 | |||||||||||||||||||||
Net cash provided by operating activities. Net cash provided by operating activities for the six months ended June 30, 2026 increased by $279.9 million, or 33%, compared to the six months ended June 30, 2025 primarily due to higher net income after adjusting for non-cash items.
Net cash used in investing activities. Net cash used in investing activities for the six months ended June 30, 2026 decreased by $265.5 million, or 21%, compared to the six months ended June 30, 2025, primarily due to $529.9 million lower acquisitions of oil and natural gas properties in 2026 partially offset by $175.3 million additional cash used in our development capital expenditures.
Net cash provided by (used in) financing activities. Net cash used in financing activities for the six months ended June 30, 2026 was $576.5 million, primarily a result of net repayments of our long-term debt balances and our dividend payments. Net cash provided by financing activities for the six months ended June 30, 2025 was $213.4 million, primarily a result of net cash received in Revolving Credit Facility borrowings, partially offset by our dividend payments and cash distributions to our redeemable noncontrolling interests.
Debt agreements
Senior Notes
2031 Convertible Notes
In March 2026, we issued $690.0 million aggregate principal amount of 2.750% Convertible Senior Notes due 2031 (the “2031 Convertible Notes”) at par. The 2031 Convertible Notes bear interest at an annual rate of 2.750%, which is payable on March 15 and September 15 of each year, beginning on September 15, 2026, and mature on March 15, 2031, unless earlier converted or redeemed or purchased by the Company. The net proceeds of the 2031 Convertible Notes were approximately $671.0 million after deducting the initial purchasers’ discount and offering expenses. The net proceeds of the 2031 Convertible Notes were used in part to redeem all of our outstanding 2028 Notes (as defined below) as discussed below.
Prior to December 15, 2030, the 2031 Convertible Notes are convertible only in certain circumstances and during specified periods. Thereafter, they are convertible at the noteholders’ election until shortly before the maturity date. Upon conversion, we may settle the conversions by paying or delivering, as applicable, in cash, shares of Class A Common Stock, or a combination
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thereof, at our election. The 2031 Convertible Notes have an initial conversion rate of 67.1456 shares of Class A Common Stock per each $1,000 principal amount, which represents an initial conversion price of approximately $14.89 per share of Class A Common Stock. In connection with the issuance of the 2031 Convertible Notes, we paid $56.6 million to enter into capped call transactions with certain financial institution counterparties designed to reduce potential dilution upon conversion of the 2031 Convertible Notes and/or offset cash payments in excess of the principal amount of the converted notes, in each case subject to the initial cap price of $22.48 per share of Class A Common Stock.
The 2031 Convertible Notes are the Company’s senior, unsecured obligations and are (i) equal in right of payment with CEC’s, as the issuer of the 2031 Convertible Notes, senior unsecured indebtedness; (ii) senior in right of payment to the issuer’s indebtedness that is expressly subordinated to the 2031 Convertible Notes; and (iii) effectively subordinated to the issuer’s secured indebtedness, to the extent of the value of the collateral securing that indebtedness. The 2031 Convertible Notes are not guaranteed by any of the Company’s subsidiaries, and the Company’s subsidiaries do not have any obligations under the 2031 Convertible Notes. Because the 2031 Convertible Notes are not guaranteed by any of the Company’s subsidiaries, the 2031 Convertible Notes are structurally subordinated to all indebtedness and other liabilities, including the Revolving Credit Facility, the CRF Credit Facility (as defined below), other series of our Senior Notes, trade payables and (to the extent the Company is not a holder thereof) preferred equity, if any, of the Company’s subsidiaries.
2028 Notes
At December 31, 2025, we had $500.0 million outstanding aggregate principal amount of 9.250% senior notes due 2028 (the “2028 Notes”). In March 2026, we elected to redeem all of the remaining 2028 Notes (the “2028 Notes Redemption”), at a price of 102.3125%. As a result of the 2028 Notes Redemption, we incurred a loss on the extinguishment of debt of approximately $17.0 million, including $5.4 million related to the non-cash write-off of outstanding deferred financing costs, discounts, and premiums.
2029 Notes
At December 31, 2025, we had $298.2 million outstanding aggregate principal amount of 7.750% senior notes due 2029 (the “2029 Notes”). In March 2026, we repurchased $39.1 million of our outstanding 2029 Notes in open market transactions, at an average price of 101.014%. As a result of the repurchases, we incurred a loss on the extinguishment of debt of approximately $0.4 million. In July 2026, we elected to redeem all of the remaining 2029 Notes (the “2029 Notes Redemption”) at a redemption price equal to 100.000% of the outstanding principal amount, or $258.7 million, plus accrued and unpaid interest to, but excluding, the redemption date.
Revolving Credit Facility
We are party to a Revolving Credit Facility with Wells Fargo Bank, N.A., as administrative agent for the lenders and letter of credit issuer, and the lenders from time to time party thereto. On May 18, 2026, we entered into the Fifteenth Amendment (the “CEF Credit Agreement Amendment”) to the credit agreement governing our Revolving Credit Facility, pursuant to which, among other things, the maturity date was extended to May 19, 2031. The borrowing base under the Revolving Credit Facility was $3.5 billion and $3.9 billion as of June 30, 2026 and December 31, 2025, respectively. At June 30, 2026, our elected commitment amount was approximately $2.0 billion and we had no outstanding borrowings, $16.6 million in outstanding letters of credit and approximately $2.0 billion of available borrowings.
Borrowings under the Revolving Credit Facility bear interest at either a (i) U.S. dollar alternative base rate based on the prime rate, the federal funds effective rate or an adjusted SOFR, plus an applicable margin, or (ii) SOFR, plus an applicable margin, at the election of the borrowers. The applicable margin varies based upon our borrowing base utilization then in effect. The fee payable for the unused revolving commitments at June 30, 2026 is 0.375% per year. Our weighted average interest rate on loan amounts outstanding as of December 31, 2025 was 5.56%. We had no borrowings outstanding under the Revolving Credit Facility at June 30, 2026.
At June 30, 2026, we were in compliance with each of the covenants under the Revolving Credit Facility and expect to remain in compliance with these covenants for the foreseeable future.
Crescent Royalty Finance Credit Facility
In February 2026, one of our subsidiaries, CRF, entered into a senior secured reserve-based revolving credit agreement with Wells Fargo Bank, N.A., as administrative agent for the lenders and letter of credit issuer, and the lenders from time to time party thereto (the “CRF Credit Facility”). The CRF Credit Facility provides for a $1.0 billion aggregate maximum credit
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amount senior secured reserve-based revolving credit facility, with an initial borrowing base and aggregate elected commitment amount of $365.0 million consisting of $230.0 million under the revolving facility and a $135.0 million term loan (“CRF Term Loan”). As of June 30, 2026, $45.5 million remained outstanding under the CRF Term Loan. Revolving loans under the CRF Credit Facility mature on February 23, 2031, and initial term loans under the CRF Credit Facility mature on February 23, 2029. The borrowing base is subject to semi-annual scheduled redeterminations on or about April 1st and October 1st of each year.
The obligations under the CRF Credit Facility are secured by liens on collateral granted by CRF, as borrower, and the guarantors under the related security documents, including, without limitation, oil and gas properties and related assets, as-extracted collateral in the form of production and proceeds attributable to mortgaged properties, equity interests in restricted subsidiaries owned by the borrower or subsidiary guarantors, certain indebtedness owed to the borrower or subsidiary guarantors, and deposit and securities accounts, in each case subject to permitted liens, excluded assets and other exceptions. The security documents include the security agreement, pledge agreement, mortgages, account control agreements and other instruments executed to secure or perfect the obligations under the facility. In connection with each redetermination of the borrowing base, the borrower must maintain mortgages on properties sufficient to satisfy the collateral coverage minimum, which requires that mortgaged properties represent at least 85% of the PV-9 of the credit parties’ total proved reserves included in the initial reserve report and, thereafter, the most recent reserve report. The borrower’s domestic subsidiaries are required to be guarantors under the CRF Credit Facility, subject to certain exceptions.
Interest
Borrowings under the CRF Credit Facility bear interest at either (i) a U.S. dollar alternative base rate based on the prime rate, the federal funds effective rate or an adjusted SOFR, plus an applicable margin or (ii) SOFR, plus an applicable margin, at the election of CRF. The applicable margin and fee payable for the unused revolving commitments varies based upon CRF’s borrowing base utilization then in effect. The weighted average interest rates on the CRF Credit Facility and the CRF Term Loan amounts outstanding as of June 30, 2026 were 6.446% and 6.946%, respectively.
Covenants
The CRF Credit Facility contains certain covenants that restrict the payment of cash dividends, certain borrowings, sales of assets, loans to others, investments, merger activity and commodity swap agreements, liens and other transactions without the prior consent of our lenders. We are subject to (i) maximum leverage ratio and (ii) current ratio financial covenants calculated as of the last day of each fiscal quarter, beginning with the fiscal quarter ending on June 30, 2026. The CRF Credit Facility also contains representations, warranties, indemnifications and affirmative and negative covenants, including events of default relating to nonpayment of principal, interest or fees, inaccuracy of representations or warranties in any material respect when made or when deemed made, violation of covenants, bankruptcy and insolvency events, certain unsatisfied judgments and a change of control. If an event of default occurs and we are unable to cure such event of default, the lenders will be able to accelerate maturity and exercise other rights and remedies. As of June 30, 2026, we were in compliance with each of the covenants under the CRF Credit Facility and expect to remain in compliance with these covenants for the foreseeable future.
Capital expenditures
Our acquisition and development expenditures consist of acquisitions of proved and unproved property, expenditures associated with the development of our oil and natural gas properties and other asset additions. Cash expenditures for drilling, completion and recompletion activities and related facilities are presented as “Development of oil and natural gas properties” in investing activities on our condensed consolidated statements of cash flows.
We expect to fund our 2026 capital program, excluding acquisitions, through cash flow from operations. The amount and timing of capital expenditures on development of oil and natural gas properties is substantially within our control due to the held-by-production nature of our assets. We regularly review our capital expenditures throughout the year and could choose to adjust our investments based on a variety of factors, including but not limited to the success of our drilling activities, prevailing and anticipated prices for oil, natural gas and NGLs, the availability of necessary equipment, infrastructure and capital, the receipt and timing of required regulatory permits and approvals, seasonal conditions, drilling and acquisition costs and the level of participation by other interest owners. Any postponement or elimination of our development drilling program could result in a reduction of proved reserve volumes and the related Standardized Measure. These risks could materially affect our business, financial condition and results of operations.
The table below presents our capital expenditures and related metrics that we use to evaluate our business for the periods presented:
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| Six Months Ended June 30, | |||||||||||||||||||||||
| 2026 | 2025 | ||||||||||||||||||||||
| (in thousands) | |||||||||||||||||||||||
| Total development of oil and natural gas properties | $ | 668,848 | $ | 472,253 | |||||||||||||||||||
| Change in accruals or other non-cash adjustments | (17,514) | 3,799 | |||||||||||||||||||||
| Cash used in development of oil and natural gas properties | 651,334 | 476,052 | |||||||||||||||||||||
Cash used in acquisition of oil and natural gas properties (1) | 354,423 | 884,366 | |||||||||||||||||||||
| Non-cash acquisition of oil and natural gas properties | 13,528 | 82,145 | |||||||||||||||||||||
| Total expenditures on acquisition and development of oil and natural gas properties | $ | 1,019,285 | $ | 1,442,563 | |||||||||||||||||||
(1)Excludes $14.1 million of accounts receivable related to the Ridgemar Acquisition customary purchase price adjustments as of June 30, 2025.
Our cash used in the development of oil and natural gas properties was higher during the six months ended June 30, 2026, compared to the six months ended June 30, 2025. The increase is related to an increase in our operations. We used cash of $354.4 million in the six months ended June 30, 2026 for the acquisition of oil and natural gas properties, primarily related to the 2026 Minerals Acquisitions, as compared to $884.4 million in 2025 for the acquisition of oil and natural gas properties, primarily related to the Ridgemar Acquisition (see Notes to condensed consolidated financial statements, NOTE 3 – Acquisitions and Divestitures included in Part I. Item 1. Financial Statements of this Quarterly Report).
Contractual obligations
As of June 30, 2026, there have been no material changes to the contractual obligations previously disclosed in our Annual Report.
Dividends
Our future dividends depend on our level of earnings, financial requirements and other factors and will be subject to approval by our Board of Directors, applicable law and the terms of our existing debt documents, including the Revolving Credit Facility and the indentures governing the Senior Notes.
We paid cash dividends of $0.24 per share of our Class A Common Stock to shareholders during the six months ended June 30, 2026.
On August 3, 2026, the Board of Directors approved a quarterly cash dividend of $0.12 per share, or $0.48 per share on an annualized basis, to be paid to shareholders of our Class A Common Stock with respect to the second quarter of 2026. The quarterly dividend is payable on August 31, 2026 to shareholders of record as of the close of business on August 17, 2026.
The payment of quarterly cash dividends is subject to management’s evaluation of our financial condition, results of operations and cash flows in connection with such payments and approval by our Board of Directors. In light of current economic conditions, management will evaluate any future increases in cash dividends on a quarterly basis.
Summarized Supplemental Subsidiary Financial Information (UNAUDITED)
CEC is a holding company that conducts substantially all of its business through its consolidated subsidiaries, including (i) OpCo, which is wholly owned by CEC, and (ii) Crescent Energy Finance LLC (“CEF”) and Crescent Royalty Finance LLC (“CRF”), each of which is wholly owned by OpCo. OpCo has no material operations, cash flows, assets or liabilities other than its investments in CEF and CRF. The assets and liabilities of OpCo represent substantially all of our consolidated assets and liabilities, except for certain parent company items held by CEC such as current and deferred taxes, CEC’s 2031 Convertible Notes (as defined within NOTE 7 – Debt), and certain liabilities under the Management Agreement (as defined within NOTE 11 – Related Party Transactions). Crescent’s consolidated balance sheets and consolidated statement of operations are materially the same as CEF with the exception of the below information.
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Selected Summarized Balance Sheet Information:
As of | |||||||||||
| June 30, 2026 | |||||||||||
| (in thousands) | |||||||||||
| Minerals and royalties (CRF) | |||||||||||
Assets: | |||||||||||
Current assets | $ | 54,803 | |||||||||
Property and equipment, net | 665,758 | ||||||||||
Other noncurrent assets | 4,054 | ||||||||||
Liabilities: | |||||||||||
Current liabilities | 11,462 | ||||||||||
Long-term debt | 273,861 | ||||||||||
| Equity: | |||||||||||
| Total equity | 438,395 | ||||||||||
| Other entities (CEF and CEC) | |||||||||||
Debt: | |||||||||||
CEF long-term debt | 4,220,767 | ||||||||||
CEC long-term debt | 671,394 | ||||||||||
Selected Summarized Statement of Operations:
| Three Months Ended | Six Months Ended | ||||||||||
| June 30, 2026 | |||||||||||
| (in thousands) | |||||||||||
| Minerals and royalties (CRF) | |||||||||||
Revenues | $ | 62,569 | $ | 107,078 | |||||||
| Operating expense | 5,175 | 9,401 | |||||||||
| Gain (loss) on derivatives | 8,372 | (14,705) | |||||||||
| Interest expense | (5,653) | (8,265) | |||||||||
| Net income (loss) | 42,332 | 42,861 | |||||||||
Critical accounting policies and estimates
This discussion and analysis of our financial condition and results of operations are based upon our unaudited condensed consolidated financial statements. A complete list of our significant accounting policies is described in NOTE 2 – Summary of Significant Accounting Policies in our audited financial statements as of and for the year ended December 31, 2025 in our Annual Report. Refer also to “Critical accounting estimates” in Part II. Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations of our Annual Report. There have been no changes to our significant accounting policies and critical accounting estimates as of June 30, 2026.
Non-GAAP financial measures
Our MD&A includes financial and liquidity measures that have not been calculated in accordance with U.S. GAAP. These non-GAAP measures include the following:
•Adjusted EBITDAX; and
•Levered Free Cash Flow
These are supplemental non-GAAP financial and liquidity measures used by our management to assess our operating results and assist us to make our investment decisions. We believe that the presentation of these non-GAAP financial measures provides investors with greater transparency with respect to our results of operations, as well as liquidity and capital resources, and that these measures are useful for period-to-period comparison of results.
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We define Adjusted EBITDAX as net income (loss) before interest expense, loss from extinguishment of debt, income tax expense (benefit), depreciation, depletion and amortization, exploration expense, non-cash gain (loss) on derivatives, impairment expense, equity-based compensation, (gain) loss on sale of assets, other (income) expense and transaction and nonrecurring expenses. Additionally, we further adjust for certain redeemable noncontrolling interest distributions made by OpCo and settlement of acquired derivative contracts. We included “Certain redeemable noncontrolling interest distributions made by OpCo” to reflect Manager Compensation as if 100% of OpCo were owned and managed by the Company, to reflect consistent earnings and liquidity measures not impacted by the amount of OpCo’s ownership under management. After giving effect to the Corporate Simplification, the Company owns 100% of outstanding OpCo Units and no longer makes distributions to the holders of redeemable noncontrolling interests in OpCo.
Adjusted EBITDAX is not a measure of performance as determined by GAAP. We believe Adjusted EBITDAX is a useful performance measure because it allows for an effective evaluation of our operating performance when compared against our peers, without regard to our financing methods, corporate form or capital structure. We exclude the items listed above from net income (loss) in arriving at Adjusted EBITDAX because these amounts can vary substantially within our industry depending upon accounting methods and book values of assets, capital structures and the method by which the assets were acquired. Adjusted EBITDAX should not be considered as an alternative to, or more meaningful than, net income (loss) as determined in accordance with GAAP, of which such measure is the most comparable GAAP measure. Certain items excluded from Adjusted EBITDAX are significant components in understanding and assessing a company’s financial performance, such as a company’s cost of capital and tax burden, as well as the historic costs of depreciable assets, none of which are reflected in Adjusted EBITDAX. Our presentation of Adjusted EBITDAX should not be construed as an inference that our results will be unaffected by unusual or nonrecurring items. Our computations of Adjusted EBITDAX may not be identical to other similarly titled measures of other companies. In addition, the Revolving Credit Facility and Senior Notes include a calculation of Adjusted EBITDAX for purposes of covenant compliance.
We define Levered Free Cash Flow as Adjusted EBITDAX less interest expense, excluding non-cash amortization of deferred financing costs, discounts, and premiums, loss from extinguishment of debt, excluding non-cash write-off of deferred financing costs, discounts and premiums, current income tax benefit (expense), tax-related redeemable noncontrolling interest distributions made by OpCo and development of oil and natural gas properties. Levered Free Cash Flow does not take into account amounts incurred on acquisitions.
Levered Free Cash Flow is not a measure of liquidity as determined by GAAP. Levered Free Cash Flow is a supplemental non-GAAP liquidity measure that is used by our management and external users of our financial statements, such as industry analysts, investors, lenders and rating agencies. We believe Levered Free Cash Flow is a useful liquidity measure because it allows for an effective evaluation of our operating and financial performance and the ability of our operations to generate cash flow that is available to reduce leverage or distribute to our equity holders. Levered Free Cash Flow should not be considered as an alternative to, or more meaningful than, Net cash flow provided by operating activities as determined in accordance with GAAP, of which such measure is the most comparable GAAP measure, or as an indicator of actual liquidity, operating performance or investing activities. Our computations of Levered Free Cash Flow may not be comparable to other similarly titled measures of other companies.
Adjusted EBITDAX and Levered Free Cash Flow should be read in conjunction with the information contained in our condensed consolidated financial statements prepared in accordance with GAAP. For a reconciliation of these non-GAAP measures to the nearest comparable GAAP measures, see “—Results of Operations—Adjusted EBITDAX (non-GAAP) and Levered Free Cash Flow (non-GAAP)” above.
Item 3. Quantitative and Qualitative Disclosures About Market Risk
We are exposed to market risk, including the effects of adverse changes in commodity prices and interest rates as described below. The primary objective of the following information is to provide quantitative and qualitative information about our potential exposure to market risks. The term “market risk” refers to the risk of loss arising from adverse changes in commodity prices and interest rates. The disclosures are not meant to be precise indicators of expected future losses but rather indicators of reasonably possible losses.
Commodity price risk
Our major market risk exposure is in the pricing that we receive for our oil, natural gas and NGLs production.
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Pricing for oil, natural gas and NGLs has been volatile and unpredictable for several years, and we expect this volatility to continue in the future. The prices we receive for our production depend on many factors outside of our control, such as the strength of the global economy and global supply and demand for the commodities we produce.
To reduce the impact of fluctuations in oil, natural gas and NGLs prices on our cash flows, we regularly enter into commodity derivative contracts with respect to certain of our oil, natural gas and NGL production through various transactions that limit the risks of fluctuations of future prices. A key tenet of our focused risk management effort is an active economic hedge strategy to mitigate near-term price volatility while maintaining long-term exposure to underlying commodity prices. Our hedging program allows us to preserve capital and protect margins and corporate returns through commodity cycles and return capital to investors. Future transactions may include price swaps whereby we will receive a fixed price for our production and pay a variable market price to the contract counterparty. Additionally, we may enter into collars, whereby we receive the excess, if any, of the fixed floor over the floating rate or pay the excess, if any, of the floating rate over the fixed ceiling. These economic hedging activities are intended to limit our near-term exposure to product price volatility and to maintain stable cash flows, a strong balance sheet and attractive corporate returns.
As of June 30, 2026, our derivative portfolio had an aggregate notional value of approximately $2.6 billion, and the fair market value of our commodity derivative contracts was a net asset of $37.6 million. We determine the fair value of our oil and natural gas commodity derivatives using valuation techniques that utilize market quotes and pricing analysis. Inputs include publicly available prices and forward price curves generated from a compilation of data gathered from third parties.
Based upon our open commodity derivative positions at June 30, 2026, a hypothetical 10% increase or decrease in the NYMEX WTI, Brent price, Henry Hub Index price, NGL prices and basis prices would change our net commodity derivative position. If prices increased by 10%, our derivative position would change by approximately $179.1 million. If prices decreased by 10%, our derivative position would change by approximately $168.4 million. The hypothetical change in fair value could be a gain or a loss depending on whether commodity prices decrease or increase.
We use derivative instruments and enter into swap contracts which are governed by ISDA master agreements. Amounts not offset on our condensed consolidated balance sheets represent positions that do not meet all of the conditions to be netted on such balance sheet, such as the legally enforceable right of offset or the execution of a master netting arrangement. See Notes to condensed consolidated financial statements, NOTE 4 – Derivatives included in Part I. Item 1. Financial Statements of this Quarterly Report for additional discussion.
Counterparty and customer credit risk
Our cash and cash equivalents are exposed to concentrations of credit risk. We manage and control this risk by investing these funds with major financial institutions. We often have balances in excess of the federally insured limits.
We sell oil, natural gas and NGLs to various types of customers. Credit is extended based on an evaluation of our customer’s financial conditions and historical payment record. The future availability of a ready market for oil, natural gas and NGLs depends on numerous factors outside of our control, none of which can be predicted with certainty.
We do not believe the loss of any single customer would materially impact our operating results because oil, natural gas and NGLs are fungible products with well-established markets and numerous purchasers.
To minimize the credit risk in derivative instruments, it is our policy to enter into derivative contracts only with counterparties that are creditworthy financial institutions deemed by our management as competent and competitive market makers. Additionally, our ISDAs allow us to net positions with the same counterparty to minimize credit risk exposure. The creditworthiness of our counterparties is subject to periodic review.
Interest rate risk
At June 30, 2026, we had no variable rate borrowings outstanding under the Revolving Credit Facility. At June 30, 2026, we had $275.5 million of variable rate borrowings outstanding under the CRF Credit Facility. Assuming no change in the amounts outstanding, the impact on interest expense of a 1% increase or decrease in the average interest rate would be an approximate $1.0 million increase or decrease in interest expense on our variable rate debt outstanding for the six months ended June 30, 2026.
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Item 4. Controls and Procedures
Limitations on effectiveness of controls and procedures
We maintain disclosure controls and procedures (“Disclosure Controls”) within the meaning of Rules 13a-15(e) and 15d-15(e) of the Exchange Act. Our Disclosure Controls are designed to ensure that information required to be disclosed by us in the reports we file or submit under the Exchange Act, such as this Quarterly Report, is recorded, processed, summarized and reported within the time periods specified in the Securities and Exchange Commission’s rules and forms.
Our Disclosure Controls are also designed to ensure that such information is accumulated and communicated to our management, including our Chief Executive Officer and Chief Financial Officer, as appropriate, to allow timely decisions regarding required disclosure. In designing and evaluating our Disclosure Controls, management recognizes that any controls and procedures, no matter how well designed and operated, can provide only reasonable assurance of achieving the desired control objectives.
Evaluation of disclosure controls and procedures
As required by Rules 13a-15 and 15d-15 under the Exchange Act, our Chief Executive Officer and Chief Financial Officer carried out an evaluation of the effectiveness of the design and operation of our disclosure controls and procedures as of June 30, 2026. Based upon their evaluation, our Chief Executive Officer and Chief Financial Officer concluded that our Disclosure Controls were effective.
Changes in internal control over financial reporting
There has been no change in our internal control over financial reporting (as defined in Rules 13a-15(f) and 15d-15(f) under the Exchange Act), during the three months ended June 30, 2026 that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.
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Part II – Other Information
Item 1. Legal Proceedings
The Company may, from time to time, be involved in litigation and claims arising out of its operations in the normal course of business. We are currently unaware of any proceedings that, in the opinion of management, will individually or in the aggregate have a material adverse effect on our financial position, results of operations or cash flows. Additional information required for this Item is provided in Notes to condensed consolidated financial statements, Note 9 – Commitments and Contingencies included in Part I. Item 1. Financial Statements of this Quarterly Report, which is incorporated by reference into this Item.
Item 1A. Risk Factors
There are a number of risks that we believe are applicable to our business and the oil and gas industry in which we operate. These risks are described elsewhere in this report or our other filings with the Securities and Exchange Commission, including the section entitled “Item 1A. Risk Factors” beginning on page 32 in our Annual Report. If any of the risks and uncertainties described within our Annual Report, our other filings with the Securities and Exchange Commission or elsewhere in this Quarterly Report actually occur, our business, financial condition or results of operations could be materially and adversely affected.
The issuance of shares of our Class A Common Stock upon conversion of the 2031 Convertible Notes may dilute the ownership interests of our stockholders and could depress the trading price of our Class A Common Stock.
Upon conversion of the 2031 Convertible Notes, we may satisfy part or all of our conversion obligations in shares of our Class A Common Stock, unless we elect to settle conversions solely in cash. The issuance of shares of our Class A Common Stock upon conversion of the 2031 Convertible Notes may dilute the ownership interests of our stockholders, which could depress the trading price of our Class A Common Stock. In addition, the market’s expectation that conversions may occur could depress the trading price of our Class A Common Stock even in the absence of actual conversions. Moreover, the expectation of conversions could encourage the short selling of our Class A Common Stock, which could place further downward pressure on the trading price of our Class A Common Stock.
The accounting method for the 2031 Convertible Notes could adversely affect our reported financial condition and results.
The accounting method for the 2031 Convertible Notes on our consolidated balance sheet, accruing interest expense for the 2031 Convertible Notes and reflecting the underlying shares of our Class A Common Stock in our reported diluted earnings per share may adversely affect our reported earnings and financial condition.
The 2031 Convertible Notes are reflected as a liability on our consolidated balance sheets, with the initial carrying amount equal to the principal amount of the 2031 Convertible Notes, net of issuance costs. The issuance costs are treated as deferred financing cost, which is amortized into interest expense over the term of the 2031 Convertible Notes. As a result of this amortization, the interest expense that we recognize is greater than the cash interest payments we make for the 2031 Convertible Notes.
In addition, the contingent shares of Class A Common Stock underlying the 2031 Convertible Notes are reflected in our diluted earnings per share using the “if converted” method, in accordance with ASU 2020-06. Under that method, diluted earnings per share is generally calculated assuming that all of the 2031 Convertible Notes were converted solely into shares of Class A Common Stock at the beginning of the reporting period, unless the result would be anti-dilutive. The application of the if-converted method may reduce our reported diluted earnings per share to the extent we are profitable in the future, and accounting standards may change in the future in a manner that may adversely affect our diluted earnings per share.
Furthermore, if any of the conditions to the convertibility of the 2031 Convertible Notes are satisfied, then we may be required under applicable accounting standards to reclassify the liability carrying value of the 2031 Convertible Notes as a current, rather than a long-term, liability. This reclassification could be required even if no holders convert their 2031 Convertible Notes and could materially reduce our reported working capital.
We cannot be certain whether other changes may be made to the current accounting standards related to the 2031 Convertible Notes, or otherwise, that could have a material effect on our operating results.
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Item 2. Unregistered Sales of Equity Securities and Use of Proceeds
The following table sets forth information with respect to our repurchases of shares of Class A Common Stock during the quarter ended June 30, 2026.
| Period | Total number of shares purchased | Average price paid per share | Total number of shares purchased as part of publicly announced plans or programs | Approximate dollar value of shares that may yet be purchased under the plans or programs. (in thousands) | ||||||||||
| 4/1/2026 - 4/30/2026 | — | $— | — | $335,984 | ||||||||||
| 5/1/2026 - 5/31/2026 | — | — | — | $335,984 | ||||||||||
| 6/1/2026 - 6/30/2026 | — | — | — | $335,984 | ||||||||||
Our Board of Directors authorized a stock repurchase program on March 4, 2024 with an approved limit of $150.0 million and a two-year term. In February 2026, our Board of Directors extended the stock repurchase program indefinitely and increased the approved limit to $400.0 million. As of June 30, 2026, we had approximately $336.0 million of repurchase authorization remaining under such program. We may repurchase our Class A Common Stock under such program. Such repurchases may be made from time to time in the open market, in privately negotiated transactions, through purchases made in accordance with the Rule 10b5-1 of the Exchange Act or by such other means as will comply with applicable state and federal securities laws. The timing of any repurchases under the stock repurchase program will depend on market conditions, contractual limitations and other considerations. The program may be extended, modified, suspended or discontinued at any time, and does not obligate us to repurchase any dollar amount or number of securities.
Item 3. Defaults Upon Senior Securities
None.
Item 4. Mine Safety Disclosures
Not applicable.
Item 5. Other Information
Rule 10b5-1 Trading Arrangements
During the three months ended June 30, 2026, no director or officer of the Company adopted terminated
Item 6. Exhibits
Exhibit No. | Description | ||||
| 2.1# | Agreement and Plan of Merger, dated May 15, 2024, by and among Crescent Energy Company, Artemis Acquisition Holdings Inc., Artemis Merger Sub Inc., Artemis Merger Sub II LLC and SilverBow Resources, Inc. (incorporated by reference to Exhibit 2.1 to the Company’s Current Report on Form 8-K, filed with the Securities and Exchange Commission on May 16, 2024). | ||||
2.2# | Membership Interest Purchase Agreement, dated as of December 3, 2024, by and between Crescent Energy Finance LLC, Crescent Energy Company, Ridgemar Energy Operating, LLC and Ridgemar (Eagle Ford) LLC (incorporated by reference to Exhibit 2.1 to the Company’s Current Report on Form 8-K, filed with the Securities and Exchange Commission on December 3, 2024). | ||||
2.3# | Closing Agreement, dated as of January 31, 2025, by and among Crescent Energy Finance LLC, Crescent Energy Company, Ridgemar Energy Operating, LLC and Ridgemar (Eagle Ford) LLC (incorporated by reference to Exhibit 2.2 to the Company’s Current Report on Form 8-K, filed with the Securities and Exchange Commission on January 31, 2025). | ||||
2.4# | Agreement and Plan of Merger, dated as of August 24, 2025, by and among Crescent Energy Company, Vital Energy, Inc., Venus Merger Sub I Inc. and Merger Sub II LLC (incorporated by reference to Exhibit 2.1 to the Company’s Current Report on Form 8-K, filed with the Securities and Exchange Commission on August 25, 2025). | ||||
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3.1 | Amended and Restated Certificate of Incorporation of Registrant (incorporated by reference to Exhibit 3.1 to the Company’s Current Report on Form 8-K, filed with the Securities and Exchange Commission on December 7, 2021). | ||||
3.2 | Amended and Restated Bylaws of Registrant (incorporated by reference to Exhibit 3.2 to the Company’s Current Report on Form 8-K, filed with the Securities and Exchange Commission on December 7, 2021). | ||||
| 4.1 | Indenture (7.625% Senior Notes due 2032), dated as of March 26, 2024, among Crescent Energy Finance LLC, the guarantors named therein, and U.S. Bank Trust Company, National Association, as trustee (incorporated by reference to Exhibit 4.1 to the Company’s Current Report on Form 8-K, filed with the Securities and Exchange Commission on March 28, 2024). | ||||
| 4.2 | First Supplemental Indenture, dated as of September 3, 2024, among Crescent Energy Finance LLC, the guarantors named therein, and U.S. Bank Trust Company, National Association, as trustee (incorporated by reference to Exhibit 4.16 to the Company’s Quarterly Report on Form 10-Q, filed with the Securities and Exchange Commission on November 4, 2024). | ||||
| 4.3 | Second Supplemental Indenture, dated as of November 7, 2024, among Crescent Energy Finance LLC, the guarantors named therein, and U.S. Bank Trust Company, National Association, as trustee (incorporated by reference to Exhibit 4.3 to the Company’s Current Report on Form 8-K, filed with the Securities and Exchange Commission on December 13, 2024). | ||||
| 4.4 | Third Supplemental Indenture, dated as of December 11, 2024, among Crescent Energy Finance LLC, the guarantors named therein, and U.S. Bank Trust Company, National Association, as trustee (incorporated by reference to Exhibit 4.4 to the Company’s Current Report on Form 8-K, filed with the Securities and Exchange Commission on December 13, 2024). | ||||
| 4.5 | Fourth Supplemental Indenture, dated as of March 24, 2025, among Crescent Energy Finance LLC, the guarantors named therein, and U.S. Bank Trust Company, National Association, as trustee (incorporated by reference to Exhibit 4.19 to the Company’s Quarterly Report on Form 10-Q, filed with the Securities and Exchange Commission on May 5, 2025). | ||||
| 4.6 | Fifth Supplemental Indenture, dated as of July 7, 2025, among Crescent Energy Finance LLC, the guarantors named therein, and U.S. Bank Trust Company, National Association, as trustee (incorporated by reference to Exhibit 4.21 to the Company’s Quarterly Report on Form 10-Q, filed with the Securities and Exchange Commission on August 4, 2025). | ||||
| 4.7 | Sixth Supplemental Indenture, dated as of December 15, 2025, among Vital Midstream Services, LLC, Crescent Energy Finance LLC, the guarantors named therein, and U.S. Bank Trust Company, National Association, as trustee (incorporated by reference to Exhibit 4.25 to the Company’s Annual Report on Form 10-K for the year ended December 31, 2025, filed with the Securities and Exchange Commission on February 25, 2026). | ||||
| 4.8 | Indenture (7.375% Senior Notes due 2033), dated as of June 14, 2024, among Crescent Energy Finance LLC, the guarantors named therein, and U.S. Bank Trust Company, National Association, as trustee (incorporated by reference to Exhibit 4.1 to the Company’s Current Report on Form 8-K, filed with the Securities and Exchange Commission on June 18, 2024). | ||||
| 4.9 | First Supplemental Indenture, dated as of September 3, 2024, among Crescent Energy Finance LLC, the guarantors named therein, and U.S. Bank Trust Company, National Association, as trustee (incorporated by reference to Exhibit 4.2 to the Company’s Current Report on Form 8-K, filed with the Securities and Exchange Commission on September 9, 2024). | ||||
| 4.10 | Second Supplemental Indenture, dated as of September 9, 2024, among Crescent Energy Finance LLC, the guarantors named therein, and U.S. Bank Trust Company, National Association, as trustee (incorporated by reference to Exhibit 4.3 to the Company’s Current Report on Form 8-K, filed with the Securities and Exchange Commission on September 9, 2024). | ||||
| 4.11 | Third Supplemental Indenture, dated as of November 7, 2024, among Crescent Energy Finance LLC, the guarantors named therein, and U.S. Bank Trust Company, National Association, as trustee (incorporated by reference to Exhibit 4.23 to the Company’s Annual Report on Form 10-K for the year ended December 31, 2024, filed with the Securities and Exchange Commission on February 26, 2025). | ||||
| 4.12 | Fourth Supplemental Indenture, dated as of March 24, 2025, among Crescent Energy Finance LLC, the guarantors named therein, and U.S. Bank Trust Company, National Association, as trustee (incorporated by reference to Exhibit 4.24 to the Company’s Quarterly Report on Form 10-Q, filed with the Securities and Exchange Commission on May 5, 2025). | ||||
| 4.13 | Fifth Supplemental Indenture, dated as of July 7, 2025, among Crescent Energy Finance LLC, the guarantors named therein, and U.S. Bank Trust Company, National Association, as trustee (incorporated by reference to Exhibit 4.27 to the Company’s Quarterly Report on Form 10-Q, filed with the Securities and Exchange Commission on August 4, 2025). | ||||
| 4.14 | Sixth Supplemental Indenture, dated as of December 15, 2025, among Vital Midstream Services, LLC, Crescent Energy Finance LLC, the guarantors named therein, and U.S. Bank Trust Company, National Association, as trustee (incorporated by reference to Exhibit 4.32 to the Company’s Annual Report on Form 10-K for the year ended December 31, 2025, filed with the Securities and Exchange Commission on February 25, 2026). | ||||
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| 4.15 | Indenture (8.375% Senior Notes due 2034), dated as of July 8, 2025, among Crescent Energy Finance LLC, the guarantors named therein, and U.S. Bank Trust Company, National Association, as trustee (incorporated by reference to Exhibit 4.1 to the Company’s Current Report on Form 8-K, filed with the Securities and Exchange Commission on July 11, 2025). | ||||
| 4.16 | First Supplemental Indenture, dated as of December 15, 2025, among Vital Midstream Services, LLC, Crescent Energy Finance LLC, the guarantors named therein, and U.S. Bank Trust Company, National Association, as trustee (incorporated by reference to Exhibit 4.34 to the Company’s Annual Report on Form 10-K for the year ended December 31, 2025, filed with the Securities and Exchange Commission on February 25, 2026). | ||||
| 4.17 | Indenture (7.75% Senior Notes due 2029), dated as of July 16, 2021, among Laredo Petroleum, Inc., Laredo Midstream Services, LLC, Garden City Minerals, LLC and Wells Fargo Bank, National Association, as trustee (incorporated by reference to Exhibit 4.1 to Vital Energy, Inc.’s Current Report on Form 8-K (File No. 001-35380), filed with the Securities and Exchange Commission on July 16, 2021). | ||||
| 4.18 | First Supplemental Indenture, dated as of December 5, 2023, among Vital Energy, Inc. (formerly known as Laredo Petroleum, Inc.), the guarantors named therein, and Computershare Trust Company, National Association (incorporated by reference to Exhibit 4.2 to the Company’s Current Report on Form 8-K, filed with the Securities and Exchange Commission on December 15, 2025). | ||||
| 4.19 | Second Supplemental Indenture, dated as of December 12, 2025, among Vital Energy, Inc., the guarantors named therein, and Computershare Trust Company, National Association (incorporated by reference to Exhibit 4.3 to the Company’s Current Report on Form 8-K, filed with the Securities and Exchange Commission on December 15, 2025). | ||||
| 4.20 | Third Supplemental Indenture, dated as of December 15, 2025, among Crescent Energy Finance, LLC, the guarantors named therein, and Computershare Trust Company, National Association (incorporated by reference to Exhibit 4.4 to the Company’s Current Report on Form 8-K, filed with the Securities and Exchange Commission on December 15, 2025). | ||||
| 4.21 | Indenture, dated as of March 18, 2015, among Laredo Petroleum, Inc., Laredo Midstream Services, LLC, Garden City Minerals, LLC and Wells Fargo Bank, National Association, as trustee (incorporated by reference to Exhibit 4.1 to Vital Energy, Inc.’s Current Report on Form 8-K (File No. 001-35380) filed with the Securities and Exchange Commission on March 24, 2015). | ||||
| 4.22 | Fifth Supplemental Indenture (9.750% Senior Notes due 2030), dated as of September 25, 2023, among Vital Energy, Inc., Vital Midstream Services, LLC and U.S. Bank Trust Company, National Association, as trustee (incorporated by reference to Exhibit 4.2 to Vital Energy, Inc.’s Current Report on Form 8-K (File No. 001-35380), filed with the Securities and Exchange Commission on September 25, 2023). | ||||
| 4.23 | Sixth Supplemental Indenture, dated as of December 12, 2025, among Vital Energy, Inc., the guarantors named therein, and U.S. Bank Trust Company, National Association (incorporated by reference to Exhibit 4.7 to the Company’s Current Report on Form 8-K, filed with the Securities and Exchange Commission on December 15, 2025). | ||||
| 4.24 | Seventh Supplemental Indenture, dated as of December 15, 2025, among Crescent Energy Finance, LLC, the guarantors named therein, and U.S. Bank Trust Company, National Association (incorporated by reference to Exhibit 4.8 to the Company’s Current Report on Form 8-K, filed with the Securities and Exchange Commission on December 15, 2025). | ||||
| 4.25 | Indenture (7.87% Senior Notes due 2032), dated as of March 28, 2024, among Vital Energy, Inc., Vital Midstream Services, LLC and U.S. Bank Trust Company, National Association, as trustee (incorporated by reference to Exhibit 4.1 to Vital Energy, Inc.’s Current Report on Form 8-K (File No. 001-35380), filed with the Securities and Exchange Commission on March 28, 2024). | ||||
| 4.26 | First Supplemental Indenture, dated as of December 15, 2025, among Crescent Energy Finance, LLC, the guarantors named therein, and U.S. Bank Trust Company, National Association (incorporated by reference to Exhibit 4.10 to the Company’s Current Report on Form 8-K, filed with the Securities and Exchange Commission on December 15, 2025). | ||||
| 4.27 | Indenture (7.75% Senior Notes due 2029), dated as of January 2, 2026, among Crescent Energy Finance LLC, the guarantors named therein and U.S. Bank Trust Company, National Association, as trustee (incorporated by reference to Exhibit 4.3 to the Company’s Current Report on Form 8-K, filed with the Securities and Exchange Commission on January 2, 2026). | ||||
| 4.28 | Indenture (9.750% Senior Notes due 2030), dated as of January 2, 2026, among Crescent Energy Finance LLC, the guarantors named therein and U.S. Bank Trust Company, National Association, as trustee (incorporated by reference to Exhibit 4.5 to the Company’s Current Report on Form 8-K, filed with the Securities and Exchange Commission on January 2, 2026). | ||||
| 4.29 | Indenture (2.75% Convertible Senior Notes due 2031), dated as of March 6, 2026, between Crescent Energy Company and U.S. Bank Trust Company, National Association, as trustee (incorporated by reference to Exhibit 4.1 to the Company’s Current Report on Form 8-K, filed with the Securities and Exchange Commission on March 9, 2026). | ||||
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| 10.1# | Fifteenth Amendment to Credit Agreement, dated May 18, 2026, by and among Crescent Energy Finance LLC, certain subsidiaries of Crescent Energy Finance LLC, as guarantors, Wells Fargo Bank, National Association, as administrative agent, collateral agent and a letter of credit issuer, and the other lenders and letter of credit issuers party thereto (incorporated by reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K, filed with the Securities and Exchange Commission on May 22, 2026). | ||||
31.1* | Certification of Chief Executive Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002. | ||||
31.2* | Certification of Chief Financial Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002. | ||||
32.1** | Certification of Chief Executive Officer and Chief Financial Officer pursuant to 18 U.S.C. § 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002. | ||||
101* | Interactive data files (formatted as Inline XBRL). | ||||
104* | Cover Page Interactive Data File (contained in Exhibit 101). | ||||
* Filed herewith
** Furnished herewith.
# Certain annexes, schedules and exhibits have been omitted pursuant to Item 601(a)(5) of Regulation S-K. The Company hereby undertakes to furnish supplemental copies of any of the omitted annexes, schedules and exhibits upon request by the Securities and Exchange Commission.
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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.
| CRESCENT ENERGY COMPANY | ||||||||
| (Registrant) | ||||||||
| August 3, 2026 | /s/ David Rockecharlie | |||||||
| David Rockecharlie | ||||||||
| Chief Executive Officer | ||||||||
| (Principal Executive Officer) | ||||||||
| August 3, 2026 | /s/ Brandi Kendall | |||||||
| Brandi Kendall | ||||||||
| Chief Financial Officer | ||||||||
| (Principal Financial Officer) | ||||||||
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