crgy-20260331

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

(Mark One)


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

For the quarterly period ended March 31, 2026


☐			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

Crescent Energy Company

(Exact name of registrant as specified in its charter)


Delaware						87-1133610
(State or other jurisdiction of incorporation or organization)						(I.R.S. Employer Identification Number)

600 Travis Street, Suite 7200

Houston, Texas 77002

(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

Class A Common Stock, par value $0.0001

CRGY

New York Stock Exchange

Indicate by check mark whether the Registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the Registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes ☒ No ☐

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

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


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

If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 7(a)(2)(B) of the Securities 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 April 30, 2026, there were approximately 330,251,628 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			32
Item 3 . Quantitative and Qualitative Disclosures About Market Risk			49
Item 4. Controls and Procedures			51
Part II - Other Information
Item 1. Legal Proceedings			52
Item 1A. Risk Factors			52
Item 2. Unregistered Sales of Equity Securities and Use of Proceeds			53
Item 3. Defaults Upon Senior Securities			53
Item 4. Mine Safety Disclosures			53
Item 5. Other Information			53
Item 6. Exhibits			54
Signatures			57

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%.

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 (“NGL”) 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 Crescent’s earnings per share, which may negatively affect the market price of our Class A Common Stock;

•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 in South America, including most recently in Venezuela, Central America and 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 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;

•our ability to retain key members of our senior management and key technical employees;

•risks relating to managing our growth, particularly in connection with the integration of significant acquisitions;

•our ability to successfully execute our growth strategies;

•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 ("OPEC") and agreements to set and maintain production levels, including as a result of recent production cuts by OPEC, which may be exacerbated by the continued hostilities in the Middle East, including the conflict with Iran, and recent developments in Venezuela;

•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") and our reports and registration statements filed from time to time with the SEC.

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.

Part I – Financial Information

Item 1. Financial Statements


CRESCENT ENERGY COMPANY
CONDENSED CONSOLIDATED BALANCE SHEETS
(Unaudited)
(in thousands, except share data)

	March 31, 2026		December 31, 2025
ASSETS
Current assets:
Cash and cash equivalents	$	9,775	$	10,157
Restricted cash	5,428		725,702
Accounts receivable, net	786,465		738,333
Accounts receivable – affiliates	1,457		4,501
Derivative assets – current	11,525		322,784


Prepaid expenses	51,458		46,309
Other current assets	30,316		13,271
Total current assets	896,424		1,861,057
Property, plant and equipment:
Oil and natural gas properties at cost, successful efforts method
Proved	13,833,356		13,264,097
Unproved	572,530		413,444
Oil and natural gas properties at cost, successful efforts method	14,405,886		13,677,541
Field and other property and equipment, at cost	172,744		157,031
Total property, plant and equipment	14,578,630		13,834,572
Less: accumulated depreciation, depletion, amortization and impairment	(3,899,343)		(3,558,601)
Property, plant and equipment, net	10,679,287		10,275,971

Derivative assets – noncurrent	15,550		2,829
Investments in equity affiliates	9,042		8,146
Deferred tax asset	233,973		143,706
Other assets	163,968		151,498
TOTAL ASSETS	$	11,998,244	$	12,443,207
















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


CRESCENT ENERGY COMPANY
CONDENSED CONSOLIDATED BALANCE SHEETS
(Unaudited)
(in thousands, except share data)

	March 31, 2026		December 31, 2025

LIABILITIES, REDEEMABLE NONCONTROLLING INTERESTS AND EQUITY
Current liabilities:
Accounts payable and accrued liabilities	$	1,090,434	$	1,121,678
Accounts payable – affiliates	21,674		46,279
Derivative liabilities – current	314,603		—
Financing lease obligations – current	4,579		4,860

Other current liabilities	137,228		86,603
Total current liabilities	1,568,518		1,259,420
Long-term debt	5,237,734		5,524,128
Derivative liabilities – noncurrent	42,684		13,421
Asset retirement obligations	378,790		383,057
Deferred tax liability	6,658		11,671
Financing lease obligations – noncurrent	2,345		3,228
Other liabilities	75,068		82,847
Total liabilities	7,311,797		7,277,772
Commitments and contingencies (Note 9)

Equity:
Class A common stock, $0.0001 par value; 1,000,000,000 shares authorized, 337,074,231 and 334,979,293 shares issued, 329,994,544 and 327,900,272 shares outstanding as of March 31, 2026 and December 31, 2025, respectively	33		33
Class B common stock, $0.0001 par value; 500,000,000 shares authorized as of March 31, 2026 and December 31, 2025, respectively	—		—
Preferred stock, $0.0001 par value; 500,000,000 shares authorized and 1,000 Series I preferred shares issued and outstanding as of March 31, 2026 and December 31, 2025	—		—
Treasury stock, at cost; 7,079,687 and 7,079,021 shares of Class A common stock as of March 31, 2026 and December 31, 2025, respectively	(71,062)		(71,054)
Additional paid-in capital	5,169,881		5,228,928
Retained earnings (accumulated deficit)	(419,847)		—
Noncontrolling interests	7,442		7,528
Total equity	4,686,447		5,165,435
TOTAL LIABILITIES, REDEEMABLE NONCONTROLLING INTERESTS AND EQUITY	$	11,998,244	$	12,443,207

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

CRESCENT ENERGY COMPANY

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS

(Unaudited)

(in thousands, except per share amounts)


	Three Months Ended March 31,
	2026		2025
Revenues:
Oil	$	893,320	$	619,658
Natural gas	158,365		187,440
Natural gas liquids	125,107		107,575
Midstream and other	6,038		35,499
Total revenues	1,182,830		950,172
Expenses:
Lease and asset operating expense	234,156		192,005
Workover expense	30,340		16,022

Gathering, processing and transportation	102,075		105,287
Production and other taxes	55,699		60,381
Depreciation, depletion and amortization	354,125		282,573
Impairment of oil and natural gas properties	—		45,647
Exploration expense	6,519		306
Midstream and other operating expense	6,746		29,816
General and administrative expense	62,800		56,770
(Gain) loss on sale of assets	2,878		(10,862)
Total expenses	855,338		777,945
Income (loss) from operations	327,492		172,227
Other income (expense):
Gain (loss) on derivatives	(706,591)		(91,028)
Interest expense	(104,574)		(73,182)
Loss from extinguishment of debt	(17,397)		—
Other income (expense)	(327)		115
Income (loss) from equity affiliates	(51)		392
Total other income (expense)	(828,940)		(163,703)
Income (loss) before taxes	(501,448)		8,524
Income tax benefit (expense)	82,272		(2,613)
Net income (loss)	(419,176)		5,911

Less: net (income) loss attributable to noncontrolling interests	(671)		(1,989)
Less: net (income) loss attributable to redeemable noncontrolling interests	—		(6,072)
Net income (loss) attributable to Crescent Energy	$	(419,847)	$	(2,150)
Net income (loss) per share:
Class A common stock – basic	$	(1.28)	$	(0.01)
Class A common stock – diluted	$	(1.28)	$	(0.01)
Class B common stock – basic and diluted	$	—	$	—
Weighted average shares outstanding:
Class A common stock – basic	328,273		191,294
Class A common stock – diluted	328,273		191,294
Class B common stock – basic and diluted	—		65,260

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


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		187,071	$	19	65,948	$	7	1	$	—	2,434	$	(32,430)	$	3,227,450	$	(64,751)	$	9,336	$	3,139,631
Net income (loss)		—	—		—	—		—	—		—	—		—		(2,150)		1,989		(161)

Distributions		—	—		—	—		—	—		—	—		—		—		(1,756)		(1,756)

Dividends		—	—		—	—		—	—		—	—		(23,457)		—		—		(23,457)
Equity-based compensation		—	—		—	—		—	—		—	—		19,398		—		193		19,591


Change in deferred taxes related to basis in OpCo		—	—		—	—		—	—		—	—		(5,474)		—		—		(5,474)

Change in equity associated with the 2025 Class A Redemption		2,949	—		(2,949)	—		—	—		—	—		34,096		—		—		34,096
Changes in equity associated with the Ridgemar Acquisition		5,455	1		—	—		—	—		—	—		108,048		—		—		108,049
Repurchases of Class A common stock		(503)	—		—	—		—	—		503	(5,312)		—		—		—		(5,312)
Balance at March 31, 2025		194,972	$	20	62,999	$	7	1	$	—	2,937	$	(37,742)	$	3,360,061	$	(66,901)	$	9,762	$	3,265,207








































Balance at January 1, 2026		327,900	$	33	—	$	—	1	$	—	7,079	$	(71,054)	$	5,228,928	$	—	$	7,528	$	5,165,435
Net income (loss)		—	—		—	—		—	—		—	—		—		(419,847)		671		(419,176)

Distributions		—	—		—	—		—	—		—	—		—		—		(757)		(757)
Dividends		—	—		—	—		—	—		—	—		(39,348)		—		—		(39,348)
Equity-based compensation		2,094	—		—	—		—	—		1	(8)		23,429		—		—		23,421


Changes in equity associated with 2031 Convertible Notes capped call, net of tax impact		—	—		—	—		—	—		—	—		(44,257)		—		—		(44,257)
Other		—	—		—	—		—	—		—	—		1,129		—		—		1,129
Balance at March 31, 2026		329,994	$	33	—	$	—	1	$	—	7,080	$	(71,062)	$	5,169,881	$	(419,847)	$	7,442	$	4,686,447

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

CRESCENT ENERGY COMPANY

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)

(in thousands)


	Three Months Ended March 31,
	2026		2025
Cash flows from operating activities:
Net income (loss)	$	(419,176)	$	5,911
Adjustments to reconcile net income (loss) to net cash provided by operating activities
Depreciation, depletion and amortization	354,125		282,573
Impairment expense	—		45,647
Deferred tax expense (benefit)	(82,888)		(8,200)
(Gain) loss on derivatives	706,591		91,028
Net cash (paid) received on settlement of derivatives	(105,972)		(10,798)
Non-cash equity-based compensation expense	23,429		26,225
Amortization of debt issuance costs, premium and discount	3,986		3,753
Loss from debt extinguishment	17,397		—
(Gain) loss on sale of oil and natural gas properties	2,878		(10,862)

Settlement of acquired derivative contracts	60,563		17,888
Other	(9,475)		(10,750)
Changes in operating assets and liabilities	(142,267)		(95,301)






Net cash provided by operating activities	409,191		337,114
Cash flows from investing activities:
Development of oil and natural gas properties	(320,402)		(199,199)
Acquisitions of oil and natural gas properties, net of cash acquired	(351,818)		(864,674)
Proceeds from the sale of oil and natural gas properties	1,228		6,931
Purchases of restricted investment securities – HTM	(7,248)		(1,781)
Maturities of restricted investment securities – HTM	7,264		1,800
Other	(10,683)		—
Net cash used in investing activities	(681,659)		(1,056,923)
Cash flows from financing activities:
Proceeds from the issuance of Senior Notes, after premium, discount and underwriting fees	671,025		—
2031 Convertible Notes capped call	(56,649)		—
Repurchase of Senior Notes, including extinguishment costs	(551,258)		—
Revolving Credit Facility borrowings	1,204,000		1,079,500
Revolving Credit Facility repayments	(1,976,648)		(533,000)
CRF Credit Facility borrowings	230,000		—

Proceeds from issuance of CRF Term Loan	135,000		—
Repayments of CRF Term Loan	(15,500)		—
Payment of debt issuance costs	(6,391)		(1,142)
Settlement of Ridgemar contingent earn-out consideration	(9,509)		—








Dividends	(39,348)		(23,457)
Distributions to redeemable noncontrolling interests	—		(12,180)




Repurchase of noncontrolling interest	(32,196)		—
Noncontrolling interest distributions	(757)		(1,756)

Cash paid for treasury stock acquired for equity-based compensation tax withholding	(8)		—
Repurchases of Class A common stock	—		(5,312)

Net cash provided by (used in) financing activities	(448,239)		502,653
Net change in cash, cash equivalents and restricted cash	(720,707)		(217,156)
Cash, cash equivalents and restricted cash, beginning of period	753,310		240,908
Cash, cash equivalents and restricted cash, end of period	$	32,603	$	23,752

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

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 (the “OpCo LLC 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. ("IEA"), 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 IEA 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, the total number of shares of our Class A Common Stock increased by 2.9 million shares with a corresponding decrease in the number of shares of our Class B Common Stock, and redeemable noncontrolling interests decreased by $34.1 million, while Additional paid-in capital (“APIC") increased by $34.1 million.

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 our 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 months ended March 31, 2025, we repurchased 0.5 million shares of our Class A Common Stock for $5.3 million, at an average price of $10.58 per share (the "2025 Class A Repurchases"). In connection therewith, we cancelled a corresponding number of OpCo Units held by us. When combining the 2025 Class A Repurchases with the 2025 Class A Redemption, the remaining amount under the plan (as re-authorized in February 2026) is approximately $336.0 million as of March 31, 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 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 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 and restricted cash presented on our balance sheets to amounts shown in our condensed consolidated statements of cash flows:


	As of March 31,
	2026		2025
	(in thousands)
Cash and cash equivalents	$	9,775	$	6,255
Restricted cash – current	5,428		3,247
Restricted cash – noncurrent	17,400		14,250
Total cash, cash equivalents and restricted cash	$	32,603	$	23,752

Income Taxes

CEC is a holding company and its sole material asset is OpCo Units. OpCo is a partnership and is generally not subject to U.S. federal and certain state taxes. Crescent is subject to U.S. federal and certain state taxes on its allocable share of any taxable income of OpCo. For the three months ended March 31, 2026, we recognized income tax benefit of $82.3 million for an effective tax rate of 16.4%. For the three months ended March 31, 2025, we recognized income tax expense of $2.6 million for an effective tax rate of 30.7%. Our effective tax rate for the three months ended March 31, 2026 was lower primarily due to the permanent difference recognized in conjunction with the performance stock units granted to our Manager ("Manager PSUs") that vested during the three months ended March 31, 2026. Our effective tax rate for the three months ended March 31, 2025 was higher due to temporary timing differences of certain deductions and a higher state tax rate due to the apportionment changes created by the Ridgemar Acquisition.

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 ("IRC"). Pursuant to Sections 382 and 383 of 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 IRC.

As of March 31, 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 three months ended March 31, 2026 and 2025:


	Three Months Ended March 31,
	2026		2025
	(in thousands)
Supplemental cash flow disclosures:
Interest paid, net of amounts capitalized	$	109,626	$	95,599
Income tax payments (refunds)	(876)		1,614
Non-cash investing and financing activities:
Capital expenditures included in accounts payable and accrued liabilities	$	238,168	$	188,896

Equity consideration for acquisitions	—		82,145
Vital purchase price allocation adjustment	11,728		—
Right-of-use assets obtained in exchange for leases	9,407		3,055

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 MS Inc."), Venus Merger Sub II LLC ("Venus MS 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 three months ended March 31, 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 $11.0 million, an increase to Oil and gas properties - unproved of $0.7 million, a decrease to Accounts receivable, net of $2.8 million, a decrease to Prepaid expenses of $0.3 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

exit costs for the closure of certain legacy corporate offices. As of March 31, 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	$	52,166	$	9,153	$	61,319
Costs incurred and charged to expense	—		15		15
Costs paid	(31,702)		(7,473)		(39,175)
March 31, 2026	$	20,464	$	1,695	$	22,159

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"). 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”). We accounted for the Ridgemar Acquisition as an asset acquisition. 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.

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	$	47,660	$	307,599	$	67,369	$	807,247	$	21,204	$	—
Settlement of Equity Awards in cash							—				3,693
Equity consideration:
Fair value of Class A Common Stock issued	—		—		—		82,145		—		640,982
Settlement of Equity Awards in Class A Common Stock	—		—		—		—		—		7,557
Fair value of contingent earn-out consideration	—		—		—		51,746		—		—
Transaction costs capitalized	224		2,255		490		18,484		—		—
Total	$	47,884	$	309,854	$	67,859	$	959,622	$	21,204	$	652,232
Assets acquired and liabilities assumed:
Cash and cash equivalents	$	—	$	—	$	—	$	—	$	—	$	122,923
Accounts receivable, net	—		—		—		1,150		—		276,882
Derivative assets – current	—		—		—		—		—		184,247
Prepaid expenses	—		—		—		—		—		25,559

Oil and natural gas properties - proved	23,189		169,735		57,200		988,758		21,204		2,219,008
Oil and natural gas properties - unproved	24,695		140,119		11,044		—		—		137,741
Field and other property and equipment	—		—		—		3,240		—		50,156
Derivative assets – noncurrent	—		—		—		—		—		2,471


Deferred tax asset	—		—				—				695,291
Other assets	—		—		—		—		—		62,847
Accounts payable and accrued liabilities	—		—		(385)		(9,565)		—		(421,231)

Other current liabilities	—		—		—		(573)		—		(39,046)


Long-term debt	—		—		—		—		—		(2,490,578)

Derivative liabilities – noncurrent	—		—				—				(7,329)
Asset retirement obligations	—		—		—		(22,855)		—		(127,821)
Other liabilities	—		—		—		(533)		—		(38,888)
Net assets acquired	$	47,884	$	309,854	$	67,859	$	959,622	$	21,204	$	652,232

Supplemental Pro Forma Information (Unaudited)

The following table summarizes our unaudited pro forma financial information for the three months ended March 31, 2025 as if the Vital Energy Merger occurred on January 1, 2025:


	Three Months Ended March 31, 2025
	(in thousands)
Revenues	$	1,462,352
Net income	73,731

Divestitures

During the three months ended March 31, 2026, we sold 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 on the sale of such assets.

During the three months ended March 31, 2025, we sold non-core assets to unrelated third-party buyers for $6.9 million in aggregate net cash proceeds and recorded a gain of $10.9 million on the sale of such assets.

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 March 31, 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.

The following table details our net volume positions by commodity as of March 31, 2026:


Production Period	Volumes	Weighted Average Fixed Price
	(in thousands)
Crude oil swaps – WTI (Bbls):
2026	16,454	$64.57
2026 (1)	368	$67.03
2027	5,490	$62.40
2027 (2)	4,563	$73.92







Crude oil two-way collars – WTI (Bbls):
2026	2,696	$60.27			-	$70.33




Crude oil three-way collars – WTI (Bbls):
2026	3,446	$48.00	-	$60.53			-	$74.62
2027	3,991	$47.66	-	$60.91			-	$75.21
2027 (3)	460	$45.00	-	$60.00			-	$70.00
Crude oil two-way collars – Brent (Bbls):
2026	138	$60.00			-	$82.00


Natural gas swaps (MMBtu):
2026	68,290	$3.95
2027	7,300	$4.21

2027 (4)	18,250	$4.19
Natural gas two-way collars (MMBtu):
2026	31,160	$3.05			-	$4.78





Crude oil basis swaps (Bbls):
2026	16,134	$1.33
2027	2,459	$1.75

Natural gas basis swaps (MMBtu):
2026	75,160	$(0.43)
2027	91,250	$(0.42)

Calendar Month Average roll swaps (Bbls):
2026	18,320	$0.50

Natural gas fixed index swaps – Waha (MMBtu):
2026	41,800	$2.41
2027	43,800	$2.69

(1) Represents outstanding crude oil swap options exercisable by the counterparty until June 2026.

(2) Represents outstanding crude oil swap options exercisable by the counterparty until December 2026 and June 2027.

(3) Represents outstanding crude oil three-way collar options exercisable by the counterparty until June 2027.

(4) Represents outstanding natural gas swap options exercisable by the counterparty until December 2026.

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 million if the average WTI price for the quarter is equal to or greater than $70 per barrel, and an additional $15.0 million if the average price equals or exceeds $75 per barrel. For each quarterly period in 2027, we will be required to pay $12.5 million if the average price of NYMEX WTI crude oil for the quarter equals or exceeds $70 per barrel. The fair value of the Ridgemar Contingent Consideration is determined by a third-party valuation specialist using a Monte Carlo simulation. The significant inputs used in the valuation are the NYMEX WTI forward price curve, mean reversion rate, and volatility. We determined these were Level 2 fair value inputs that are substantially observable in active markets or can be derived from observable data. Contingent earn-out consideration is included in Other current liabilities and Other liabilities on the condensed consolidated balance sheets. The average WTI price for the first quarter of 2026 was $71.93 per barrel, and accordingly, we made a payment of $15.0 million in April 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. Contingent earn-out consideration is included in Other assets 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 March 31, 2026 and December 31, 2025:


	Gross Fair Value		Effect of Counterparty Netting		Net Carrying Value
	(in thousands)
March 31, 2026
Assets:
Derivative assets – current	$	199,182	$	(187,657)	$	11,525
Other assets – current	6,923		—		6,923
Derivative assets – noncurrent	46,884		(31,334)		15,550
Other assets – noncurrent	43,225		—		43,225
Total assets	$	296,214	$	(218,991)	$	77,223
Liabilities:
Derivative liabilities – current	$	(502,260)	$	187,657	$	(314,603)
Other current liabilities	(53,573)		—		(53,573)
Derivative liabilities – noncurrent	(74,018)		31,334		(42,684)
Other liabilities	(15,125)		—		(15,125)
Total liabilities	$	(644,976)	$	218,991	$	(425,985)

December 31, 2025
Assets:
Derivative assets – current	$	346,849	$	(24,065)	$	322,784
Derivative assets – noncurrent	22,875		(20,046)		2,829
Other assets	17,590		—		17,590
Total assets	$	387,314	$	(44,111)	$	343,203
Liabilities:
Derivative liabilities – current	$	(24,065)	$	24,065	$	—
Other current liabilities	(16,153)		—		(16,153)
Derivative liabilities – noncurrent	(33,467)		20,046		(13,421)
Other liabilities	(10,717)		—		(10,717)
Total liabilities	$	(84,402)	$	44,111	$	(40,291)

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 months ended March 31, 2026 and 2025:


	Three Months Ended March 31,
	2026		2025
	(in thousands)
Derivatives not designated as hedging instruments:
Realized gain (loss) on oil positions	$	(91,179)	$	(4,354)

Realized gain (loss) on natural gas positions	(9,302)		(5,156)
Realized gain (loss) on NGL positions	—		(1,288)
Realized gain (loss) on contingent earn-out consideration	(5,491)		—
Total realized gain (loss) on derivatives	(105,972)		(10,798)
Unrealized gain (loss) on commodity derivatives	(581,840)		(80,719)
Unrealized gain (loss) on contingent earn-out consideration	(18,779)		489
Total unrealized gain (loss) on derivatives	(600,619)		(80,230)
Gain (loss) on derivatives	$	(706,591)	$	(91,028)

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 March 31, 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)
March 31, 2026
Financial assets:
Derivative assets	$	—	$	246,066	$	—	$	246,066
Vital contingent earn-out consideration	—		—		50,148		50,148
Financial liabilities:
Derivative liabilities	$	—	$	(576,278)	$	—	$	(576,278)
Ridgemar contingent earn-out consideration	—		(68,698)		—		(68,698)

December 31, 2025
Financial assets:
Derivative assets	$	—	$	369,724	$	—	$	369,724
Vital contingent earn-out consideration	—		—		17,590		17,590
Financial liabilities:
Derivative liabilities	$	—	$	(57,532)	$	—	$	(57,532)
Ridgemar contingent earn-out consideration	—		(26,870)		—		(26,870)


	As of March 31, 2026
	(in thousands)
Rollforward of Recurring Level 3 Fair Value Measurements:
Beginning balance	$	17,590
Unrealized gain (loss) on Vital contingent earn-out consideration	32,558
Ending balance	$	50,148

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 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 March 31, 2026 and December 31, 2025 was approximately $5.2 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 March 31, 2026 and December 31, 2025:


	March 31, 2026		December 31, 2025
	(in thousands)
Accounts payable and accrued liabilities:
Accounts payable	$	194,315	$	144,794
Accrued lease and asset operating expense	126,592		177,348
Accrued capital expenditures	176,089		164,739
Accrued general and administrative expense	43,767		86,964
Accrued gathering, processing and transportation expense	87,258		72,303
Accrued revenue and royalties payable	293,107		304,468
Accrued interest expense	125,319		130,816
Accrued severance taxes	20,276		22,449

Other	23,711		17,797
Total accounts payable and accrued liabilities	$	1,090,434	$	1,121,678

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, 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 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.

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. Our Revolving Credit Facility

matures on October 22, 2030, 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.

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 March 31, 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 March 31, 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 of $365.0 million and an initial aggregate elected commitment amount of $230.0 million, and an initial term loan facility with an aggregate commitment amount of $135.0 million ("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 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 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 March 31, 2026 was 6.437% and 6.937%, 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 March 31, 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.

Total Debt Outstanding

The following table summarizes our debt balances as of March 31, 2026 and December 31, 2025:


	Debt Outstanding		Letters of Credit Issued		Borrowing Base		Maturity
	(in thousands)
March 31, 2026
Crescent Energy Company
2.750% Convertible Senior Notes due 2031	$	690,000	$	—	$	—	3/15/2031
Less: Unamortized discount, premium and issuance costs	(19,713)
Crescent Energy Finance LLC
Revolving Credit Facility	—		16,625		3,900,000		10/22/2030

7.750% Senior Notes due 2029	258,678		—		—		7/31/2029
9.750% Senior Notes due 2030	302,149		—		—		10/15/2030
7.875% Senior Notes due 2032	1,000,000		—		—		4/15/2032
7.625% Senior Notes due 2032	1,100,000		—		—		4/1/2032
7.375% Senior Notes due 2033	1,000,000		—		—		1/15/2033
8.375% Senior Notes due 2034	600,000		—		—		1/15/2034
Less: Unamortized discount, premium and issuance costs	(41,083)
Crescent Royalty Finance LLC
CRF Term Loan	119,500		—		—		2/23/2029
CRF Credit Facility	230,000		—		349,500 (1)		2/23/2031
Less: Unamortized discount, premium and issuance costs	(1,797)
Total long-term debt	$	5,237,734

December 31, 2025
Crescent Energy Finance LLC
Revolving Credit Facility	$	772,000	$	16,625	$	3,900,000	10/22/2030
9.250% Senior Notes due 2028	500,000		—		—		2/15/2028
7.750% Senior Notes due 2029	298,214		—		—		7/31/2029
9.750% Senior Notes due 2030	302,364		—		—		10/15/2030
7.875% Senior Notes due 2032	1,000,000		—		—		4/15/2032
7.625% Senior Notes due 2032	1,100,000		—		—		4/1/2032
7.375% Senior Notes due 2033	1,000,000		—		—		1/15/2033
8.375% Senior Notes due 2034	600,000		—		—		1/15/2034
Less: Unamortized discount, premium and issuance costs	(48,450)
Total long-term debt	$	5,524,128

(1) Represents the borrowing base as of March 31, 2026, consisting of a $230.0 million conforming borrowing base and a $119.5 million non-conforming borrowing base.

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 three months ended March 31, 2026:


	As of March 31, 2026
	(in thousands)
Balance at beginning of period	$	402,601

Additions	723
Retirements	(4,227)
Divestitures	(32)

Accretion expense	7,483
Balance at end of period	406,548
Less: current portion	(27,758)
Balance at end of period, noncurrent portion	$	378,790

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 March 31, 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:


	Three Months Ended March 31,
	2026		2025
Equity-based compensation expense:	(in thousands)
Liability-classified profits interest awards	$	1,071	$	413
Equity-classified profits interest awards	—		193
Equity-classified LTIP RSU awards	1,856		631
Equity-classified LTIP PSU awards	461		69
Equity-classified Manager PSUs	21,112		25,332
Total equity-based compensation expense	$	24,500	$	26,638
Tax benefit related to equity-based compensation awards	$	5,417	$	—

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 months ended March 31, 2026, we did not grant any equity-classified LTIP RSU awards. In April 2026, we granted 1.8 million equity-classified LTIP RSUs under the Crescent Energy Company 2021 Equity Incentive Plan to certain directors, officers and employees. Each LTIP RSU represents the contingent right to receive one share of Class A Common Stock. The grant date fair value was $12.73 per LTIP RSU. The LTIP RSUs will vest over a period of one to three years, with equity-based compensation expense recognized ratably over the applicable vesting period. Compensation cost for these awards is presented within General and administrative expense on the condensed consolidated statements of operations with a corresponding credit to APIC on our condensed consolidated balance sheets.

Equity-classified LTIP PSU Awards

During the three months ended March 31, 2026, we did not grant any equity-classified LTIP PSU awards. In April 2026, we granted 0.5 million equity-classified LTIP PSUs under the Crescent Energy Company 2021 Equity Incentive Plan to certain officers and employees. Each LTIP PSU represents the right to receive one share of Class A Common Stock, on such LTIP PSUs performance period end date, modified by an amount ranging from 0% to 240% based on certain absolute and relative shareholder return components. The grant date fair value was $22.75 per LTIP PSU. Compensation cost for these awards is presented within General and administrative expense on the condensed consolidated statements of operations with a corresponding credit to APIC on our condensed consolidated balance sheets.

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 three months ended March 31, 2026. We accounted for this increase as a change in estimate and recognized additional expense of $2.1 million for the three months ended March 31, 2026. 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

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 March 31, 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 months ended March 31, 2026, we recorded General and administrative expense of $19.6 million 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 months ended March 31, 2025, we recorded General and administrative expense of $13.2 million related to the Manager Compensation and made cash distributions of $4.5 million to our redeemable noncontrolling interests related to the Management Agreement. At both March 31, 2026 and December 31, 2025, we had $19.6 million included within Accounts payable – affiliates on the consolidated balance sheets associated with the Management Agreement.

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 Class A Shares granted under the Crescent Energy Company 2021 Manager Incentive Plan increases. During the three months ended March 31, 2026 and 2025, we recorded non-cash general and administrative expense of $21.1 million and $25.3 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 March 31, 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 $2.1 million and $25.1 million, respectively, included within Accounts payable – affiliates on our condensed consolidated balance sheets associated with KKR Funds transactions.

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 March 31,
	2026		2025
	(in thousands)
Amounts paid to KCM	$	5,008	$	—

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 months ended March 31, 2025, we made cash distributions of $7.7 million 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 months ended March 31, 2026 and 2025, we reimbursed KKR $0.6 million for both periods for costs incurred on our behalf. At March 31, 2026 and December 31, 2025, we had $0.7 million accrued for both periods within Accounts payable - affiliates on the condensed consolidated balance sheet for reimbursable costs.

Other

We may be required to fund certain workover costs, and we will be required to fund plugging and abandonment costs related to producing assets held by 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 three months ended March 31, 2025, we funded $2.0 million to Chama associated with plugging and abandonment costs. During the three months ended March 31, 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. Net income (loss) per share - diluted excludes the effect of 10.1 million and 3.5 million of RSUs and PSUs for the three months ended March 31, 2026 and March 31, 2025, respectively, that were not included in the computation of EPS because to do so would have been antidilutive to our net loss.

The dilutive effect of the 2031 Convertible Notes was determined using the if-converted method. Net income (loss) per share - diluted excludes the effect of 46.3 million shares issuable upon conversion of the 2031 Convertible Notes at the initial conversion rate for the three months ended March 31, 2026, that were not included in the computation of EPS because to do so would have been antidilutive to our net loss.

The following table sets forth the computation of basic and diluted net income (loss) per share:


	Three Months Ended March 31,
	2026		2025
	(in thousands, except share and per share amounts)
Numerator:
Net income (loss)	$	(419,176)	$	5,911

Less: net (income) loss attributable to noncontrolling interests	(671)		(1,989)
Less: net (income) loss attributable to redeemable noncontrolling interests	—		(6,072)
Net income (loss) attributable to Crescent Energy - basic	$	(419,847)	$	(2,150)
Add: Interest expense, net of taxes, of 2031 Convertible Notes	—		—

Net income (loss) attributable to Crescent Energy - diluted	$	(419,847)	$	(2,150)
Denominator:
Weighted-average Class A Common Stock outstanding - basic	328,272,587		191,293,595
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	328,272,587		191,293,595
Weighted-average Class B Common Stock outstanding – basic and diluted	—		65,260,089
Net income (loss) per share:
Class A Common Stock – basic	$	(1.28)	$	(0.01)
Class A Common Stock – diluted	$	(1.28)	$	(0.01)
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:


	Three Months Ended March 31,
	2026		2025
	(in thousands)

Total revenues	$	1,182,830	$	950,172
Less:
Lease and asset operating expense	234,156		192,005
Workover expense	30,340		16,022
Gathering, processing and transportation	102,075		105,287
Production and other taxes	55,699		60,381
Depreciation, depletion and amortization	354,125		282,573
Impairment expense	—		45,647
Midstream and other operating expense	6,746		29,816
General and administrative expense excluding equity-based compensation	38,300		30,132
Equity-based compensation expense	24,500		26,638
Interest expense	104,574		73,182
Other segment items	651,491		82,578
Net income (loss)	$	(419,176)	$	5,911

Total development of oil and natural gas properties	$	384,724	$	207,542

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 May 4, 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 first quarter of 2026. The quarterly dividend is payable on June 1, 2026 to shareholders of record as of the close of business on May 18, 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.

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"), as well as our unaudited condensed consolidated financial statements for the three months ended March 31, 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 months ended March 31, 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

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 in 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. 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 in 2026 that has created further volatility. For example, actions taken by OPEC and allies with respect to production levels, and announcements of potential changes in such levels, including production adjustments during 2025 and the first quarter of 2026, 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.

During the three months ended March 31, 2026, no impairment expense was incurred. During the three months ended March 31, 2025, we recorded an impairment expense of $45.6 million 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, 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 in 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 and indicated that near-term cuts are unlikely. 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 changes to the composition of the Federal Reserve’s Board of Governors expected in 2026), 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

2028 Notes

2029 Notes

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 Crescent Energy Finance LLC. 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 NOTE 3 – Acquisitions and Divestitures 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"). 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”). We accounted for the Ridgemar Acquisition as an asset acquisition. See NOTE 3 – Acquisitions and Divestitures for additional information.

Other Acquisitions

Minerals Acquisitions

Webb Gas Acquisition

Divestitures

During the three months ended March 31, 2025, we sold non-core assets to unrelated third-party buyers for $6.9 million in aggregate net cash proceeds and recorded a gain on the sale of assets of $10.9 million.

Income Taxes

CEC is a holding company and its sole material asset is OpCo Units. OpCo is a partnership and is generally not subject to U.S. federal and certain state taxes. Crescent is subject to U.S. federal and certain state taxes on its allocable share of any taxable income of OpCo. Our effective tax rate for the three months ended March 31, 2026 was lower primarily due to the permanent difference recognized in conjunction with the performance stock units granted to our Manager ("Manager PSUs") that vested during the three months ended March 31, 2026. Our effective tax rate for the three months ended March 31, 2025 was higher due to temporary timing differences of certain deductions and a higher state tax rate due to the apportionment changes created by the Ridgemar Acquisition.

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 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 March 31, 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.

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. Pricing of commodities 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 March 31,
	2026		2025
Oil	76	%	68	%
Natural gas	13	%	20	%
NGLs	11	%	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 months ended March 31, 2026 and 2025.

Production volumes sold

The following table presents historical sales volumes for our properties:


	Three Months Ended March 31,
	2026	2025






Total consolidated
Oil (MBbls)	12,582	9,161
Natural gas (MMcf)	66,860	58,954
NGLs (MBbls)	6,930	4,230
Total (MBoe)	30,655	23,217
Daily average (MBoe/d)	341	258
Working interest (CEF)
Oil (MBbls)	12,217	8,966
Natural gas (MMcf)	64,124	57,472
NGLs (MBbls)	6,752	4,123
Total (MBoe)	29,656	22,668
Daily average (MBoe/d)	330	252
Minerals and royalties (CRF)
Oil (MBbls)	365	195
Natural gas (MMcf)	2,736	1,482
NGLs (MBbls)	178	107
Total (MBoe)	999	549
Daily average (MBoe/d)	11	6

Total consolidated sales volumes increased 7,438 MBoe during the three months ended March 31, 2026, compared to the three months ended March 31, 2025. Our Working interest sales volumes increased 6,988 MBoe, primarily due to the Vital Energy Merger and our Minerals and royalties sales volumes increased 450 MBoe due to our 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 the geopolitical events, such as the recent events in Venezuela, and expected increase in Venezuelan crude being brought to market, 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, sustained levels of inflation and increased U.S. drilling activity or otherwise. Uncertainty persists regarding OPEC’s actions, 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 ongoing hostilities in Venezuela. Additionally, market concern regarding the health of the global banking sector and any resultant recessionary effects 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.

The following table presents the percentages of our production that was economically hedged through the use of derivative contracts:


	Three Months Ended March 31,
	2026		2025
Oil	68	%	59	%
Natural gas	56	%	58	%
NGLs	—	%	9	%

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 March 31,
	2026		2025
Oil (Bbl):
Average NYMEX	$	71.93	$	71.42
Realized price (excluding derivative settlements)	71.00		67.64
Realized price (including derivative settlements) (1)	63.75		67.17
Natural Gas (Mcf):
Average NYMEX	$	5.04	$	3.65
Realized price (excluding derivative settlements)	2.37		3.18
Realized price (including derivative settlements) (1)	2.23		3.09
NGLs (Bbl):
Realized price (excluding derivative settlements)	$	18.05	$	25.43
Realized price (including derivative settlements) (1)	18.05		25.13

(1) The realized price presented above does not include $60.6 million received from the settlement of acquired oil, gas and NGL derivative contracts for the three months ended March 31, 2026, and does not include $17.9 million received from the settlement of acquired oil, gas and NGL derivative contracts for the three months ended March 31, 2025.

Results of operations:

Three Months Ended March 31, 2026 Compared to Three Months Ended March 31, 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 March 31,
	2026		2025		$ Change		% Change
Revenues (in thousands):
Oil	$	893,320	$	619,658	$	273,662	44	%
Natural gas	158,365		187,440		(29,075)		(16)	%
Natural gas liquids	125,107		107,575		17,532		16	%
Midstream and other	6,038		35,499		(29,461)		(83)	%
Total revenues	$	1,182,830	$	950,172	$	232,658	24	%
Average realized prices, before effects of derivative settlements:
Oil ($/Bbl)	$	71.00	$	67.64	$	3.36	5	%
Natural gas ($/Mcf)	2.37		3.18		(0.81)		(25)	%
NGLs ($/Bbl)	18.05		25.43		(7.38)		(29)	%
Total ($/Boe)	38.39		39.40		(1.01)		(3)	%
Net sales volumes:
Oil (MBbls)	12,582		9,161		3,421		37	%
Natural gas (MMcf)	66,860		58,954		7,906		13	%
NGLs (MBbls)	6,930		4,230		2,700		64	%
Total (MBoe)	30,655		23,217		7,438		32	%
Average daily net sales volumes:
Oil (MBbls/d)	140		102		38		37	%
Natural gas (MMcf/d)	743		655		88		13	%
NGLs (MBbls/d)	77		47		30		64	%
Total (MBoe/d)	341		258		83		32	%

Oil revenue. Oil revenue increased $273.7 million, or 44%, in the three months ended March 31, 2026, compared to the three months ended March 31, 2025. This was driven by a $231.4 million increase from higher sales volume (38 MBbls/d, or 37%), and higher realized oil prices that resulted in an increase of $42.3 million (an increase of 5% per Bbl). The increase in sales volumes was primarily driven by the Vital Energy Merger. The increase in realized oil prices was due to higher index pricing and more favorable price differentials.

Natural gas revenue. Natural gas revenue decreased $29.1 million, or 16%, in the three months ended March 31, 2026, compared to the three months ended March 31, 2025. This was driven by lower natural gas prices that resulted in a decrease of $54.2 million (a decrease of 25% per Mcf), partially offset by a $25.1 million increase from higher sales volume (88 MMcf/d, or 13%). The increase in sales volumes was primarily due to the Vital Energy Merger. 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.

NGL revenue. NGL revenue increased $17.5 million, or 16%, in the three months ended March 31, 2026, compared to the three months ended March 31, 2025. This was driven primarily by a $68.7 million increase from higher sales volume (30 MBbls/d, or 64%), partially offset by lower realized NGL prices that resulted in a decrease of $51.2 million (a decrease of 29% per Bbl). The increase in sales volumes was primarily driven by the Vital Energy Merger.

Midstream and other revenue. Midstream and other revenue decreased $29.5 million, or 83%, in the three months ended March 31, 2026, compared to the three months ended March 31, 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 March 31,
	2026		2025		$ Change		% Change
Expenses (in thousands):















Operating expense	$	429,016	$	403,511	$	25,505	6	%
Depreciation, depletion and amortization	354,125		282,573		71,552		25	%
Impairment of oil and natural gas properties	—		45,647		(45,647)		NM*
General and administrative expense	62,800		56,770		6,030		11	%
Other operating costs	9,397		(10,556)		19,953		NM*
Total expenses	$	855,338	$	777,945	$	77,393	10	%
Selected expenses per Boe:







Operating expense	$	14.00	$	17.38	$	(3.38)	(19)	%


Depreciation, depletion and amortization	11.55		12.17		(0.62)		(5)	%

* NM = Not meaningful.

Operating expense. Operating expense increased $25.5 million, or 6%, in the three months ended March 31, 2026, compared to the three months ended March 31, 2025, driven primarily by the following factors:

(i)Lease and asset operating expense increased $42.2 million, or 22%, in the three months ended March 31, 2026, compared to the three months ended March 31, 2025, and decreased $0.63 per Boe, or 8%, to $7.64 per Boe. This $42.2 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 $3.2 million, or 3%, in the three months ended March 31, 2026, compared to the three months ended March 31, 2025, and decreased $1.20 per Boe, or 26%, to $3.33 per Boe. These decreases were driven primarily by the Vital Energy Merger and our 2025 divestitures.

(iii)Production and other taxes decreased $4.7 million, or 8%, in the three months ended March 31, 2026, compared to the three months ended March 31, 2025, and decreased $0.78 per Boe, or 30%, to $1.82 per Boe. This net decrease was driven primarily by our 2025 divestitures higher tax rates, partially offset by the Vital Energy Merger.

(iv)Workover expense increased $14.3 million, or 89%, in the three months ended March 31, 2026, compared to the three months ended March 31, 2025, and increased $0.30 per Boe, or 43%, to $0.99 per Boe. This increase was primarily driven by the Vital Energy Merger.

(v)Midstream and other operating expense decreased $23.1 million, or 77%, in the three months ended March 31, 2026, compared to the three months ended March 31, 2025, primarily due to our 2025 divestitures.

Depreciation, depletion and amortization. In the three months ended March 31, 2026, depreciation, depletion and amortization increased $71.6 million, or 25%, compared to the three months ended March 31, 2025, driven primarily by increased production from the Vital Energy Merger.

Impairment expense. During the three months ended March 31, 2025, we recorded an impairment of $45.6 million to write down the value of certain assets classified as held for sale to expected net proceeds. We did not have impairment expense during the three months ended March 31, 2026.

General and administrative expense. General and administrative expense increased $6.0 million, or 11%, for the three months ended March 31, 2026, compared to the three months ended March 31, 2025. The increase was driven by (i) higher recurring General and administrative expense due to an increase in Manager Compensation as a result of the Vital Energy Merger and (ii)

$5.1 million higher transaction and nonrecurring related expenses offset by a decrease in equity-based compensation expense of $2.1 million, (2026 and 2025 includes additional expense of $2.1 million and $8.6 million due to changes in estimate).


	Three Months Ended March 31,
	2026		2025		$ Change		% Change
General and administrative expense (in thousands):
Recurring general and administrative expense	$	30,872	$	27,812	$	3,060	11	%
Transaction and nonrecurring expenses	7,428		2,320		5,108		220	%
Equity-based compensation	24,500		26,638		(2,138)		(8)	%
Total general and administrative expense	$	62,800	$	56,770	$	6,030	11	%
General and administrative expense per Boe:
Recurring general and administrative expense	$	1.01	$	1.20	$	(0.19)	(16)	%
Transaction and nonrecurring expenses	0.24		0.10		0.14		140	%
Equity-based compensation	0.80		1.15		(0.35)		(30)	%

Other operating costs. Other operating costs include exploration expense and gain on sale of assets. Other operating costs increased by $20.0 million, compared to the three months ended March 31, 2025, primarily driven by $6.3 million higher exploration expense recognized during the three months ended March 31, 2026 and a $13.7 million change in the gain or loss on sale of assets.

Interest expense. In the three months ended March 31, 2026, we incurred interest expense of $104.6 million, as compared to $73.2 million in the three months ended March 31, 2025, a 43% increase. This increase was driven primarily by higher average debt balances from the Vital Energy Merger.

Loss on extinguishment of debt. During the three months ended March 31, 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 three months ended March 31, 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 three months ended March 31, 2026 changed by $615.6 million, from a comparable loss during 2025 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 March 31, 2026 and 2025, we recognized income tax benefit of $82.3 million and tax expense of $2.6 million, respectively, for an effective tax rate of 16.4% and 30.7%, respectively. Our effective tax rate for the three months ended March 31, 2026 was lower primarily due to the permanent difference recognized in conjunction with the performance stock units granted to our Manager ("Manager PSUs") that vested during the three months ended March 31, 2026. Our effective tax rate for the three months ended March 31, 2025 was higher due to temporary timing differences of certain deductions and a higher state tax rate due to the apportionment changes created by the Ridgemar Acquisition.

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:


	Three Months Ended March 31,
	2026		2025		$ Change		% Change
(in thousands, except percentages)
Net income (loss)	$	(419,176)	$	5,911	$	(425,087)	(7,191)	%
Adjustments to reconcile to Adjusted EBITDAX:
Interest expense	104,574		73,182
Loss from extinguishment of debt	17,397		—
Income tax expense (benefit)	(82,272)		2,613
Depreciation, depletion and amortization	354,125		282,573
Exploration expense	6,519		306
Non-cash (gain) loss on derivatives	600,619		80,230
Impairment expense	—		45,647
Non-cash equity-based compensation expense	23,429		26,225
(Gain) loss on sale of assets	2,878		(10,862)
Other (income) expense	327		(115)
Certain redeemable noncontrolling interest distributions made by OpCo (1)	—		(4,242)
Transaction and nonrecurring expenses (2)	20,748		10,099
Settlement of acquired derivative contracts	60,563		17,888
Adjusted EBITDAX (non-GAAP)	$	689,731	$	529,455	$	160,276	30	%
Adjustments to reconcile to Levered Free Cash Flow:
Interest expense, excluding non-cash amortization of deferred financing costs, discounts, and premiums	(100,588)		(69,429)
Loss from extinguishment of debt, excluding non-cash write-off of deferred financing costs, discounts, and premiums	(11,963)		—
Current income tax benefit (expense)	(617)		(10,813)
Tax-related redeemable noncontrolling interest distributions made by OpCo	—		(95)
Development of oil and natural gas properties	(384,724)		(207,542)
Levered Free Cash Flow (non-GAAP)	$	191,839	$	241,576	$	(49,737)	(21)	%

(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 $20.7 million for the three months ended March 31, 2026 were primarily related to the Ridgemar Acquisition earn-out payments, Vital Energy Merger transaction costs, capital markets transactions and restructuring costs. Transaction and nonrecurring expenses of $10.1 million for the three months ended March 31, 2025 were primarily related to the Ridgemar Acquisition transaction costs, divestitures and restructuring costs.


	Three Months Ended March 31,
	2026		2025		$ Change		% Change
(in thousands, except percentages)
Net cash provided by operating activities	$	409,191	$	337,114	$	72,077	21	%
Changes in operating assets and liabilities	142,267		95,301

Certain redeemable noncontrolling interest distributions made by OpCo (1)	—		(4,242)
Tax-related redeemable noncontrolling interest contributions (distributions) made by OpCo	—		(95)
Transaction and nonrecurring expenses (2)	20,748		10,099
Loss from extinguishment of debt, excluding non-cash write-off of deferred financing costs, discounts, and premiums	(11,963)		—
Exploration expense	6,519		306
Other adjustments and operating activities	9,801		10,635
Development of oil and natural gas properties	(384,724)		(207,542)
Levered Free Cash Flow (non-GAAP)	$	191,839	$	241,576	$	(49,737)	(21)	%

Adjusted EBITDAX (non-GAAP) increased by $160.3 million, or 30%, in the three months ended March 31, 2026, compared to the three months ended March 31, 2025, primarily driven by additional production from the Vital Energy Merger.

Levered Free Cash Flow (non-GAAP) decreased by $49.7 million, or 21%, in the three months ended March 31, 2026 compared to the three months ended March 31, 2025, primarily driven by $177.2 million of increased development of oil and natural gas properties expenditures and additional interest expense, excluding non-cash amortization and the loss from extinguishment of debt, partially offset by increased Adjusted EBITDAX.

Liquidity and capital resources

Our primary sources of liquidity are 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.

The following table presents our cash balances and outstanding borrowings at the end of each period presented:


	March 31, 2026		December 31, 2025
	(in thousands)
Cash and cash equivalents	$	9,775	$	10,157
Long-term debt	5,237,734		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:


	Three Months Ended March 31,
	2026		2025
	(in thousands)
Net cash provided by operating activities	$	409,191	$	337,114
Net cash used in investing activities	(681,659)		(1,056,923)
Net cash provided by (used in) financing activities	(448,239)		502,653

Net cash provided by operating activities. Net cash provided by operating activities for the three months ended March 31, 2026 increased by $72.1 million, or 21%, compared to the three months ended March 31, 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 three months ended March 31, 2026 decreased by $375.3 million, or 36%, compared to the three months ended March 31, 2025, primarily due to $512.9 million lower acquisitions of oil and natural gas properties in 2026 partially offset by $121.2 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 three months ended March 31, 2026 was $448.2 million, primarily a result of net repayments of our long-term debt balances. Net cash provided by financing activities for the three months ended March 31, 2025 was $502.7 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

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.

2028 Notes

2029 Notes

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. The Revolving Credit Facility matures on October 22, 2030. The borrowing base under the Revolving Credit Facility was $3.9 billion as of March 31, 2026 and December 31, 2025. At March 31, 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 March 31, 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 March 31, 2026.

At March 31, 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

Interest

Covenants

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, 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:


	Three Months Ended March 31,
	2026		2025
	(in thousands)
Total development of oil and natural gas properties	$	384,724	$	207,542
Change in accruals or other non-cash adjustments	(64,322)		(8,343)
Cash used in development of oil and natural gas properties	320,402		199,199


Cash used in acquisition of oil and natural gas properties	351,818		864,674
Non-cash acquisition of oil and natural gas properties	11,728		82,145
Total expenditures on acquisition and development of oil and natural gas properties	$	683,948	$	1,146,018

Our cash used in the development of oil and natural gas properties was higher during the three months ended March 31, 2026, compared to the three months ended March 31, 2025. The increase is related to an increase in our operations and related timing of invoices. We used cash of $351.8 million in the three months ended March 31, 2026 for the acquisition of oil and natural gas properties, primarily related to the 2026 Minerals Acquisitions, as compared to $864.7 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 March 31, 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 $0.12 per share of our Class A Common Stock to shareholders during the three months ended March 31, 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)

Selected Summarized Balance Sheet Information:


	As of
	March 31, 2026
	(in thousands)
Minerals and royalties (CRF)
Assets:
Current assets	$	36,904
Property and equipment, net	683,311
Other noncurrent assets	4,143
Liabilities:
Current liabilities	24,186

Long-term debt	347,703
Equity:
Total equity	348,497

Other entities (CEF and CEC)
Debt:
CEF long-term debt	4,219,744
CEC long-term debt	670,287

Selected Summarized Statement of Operations:


	Three Months Ended
	March 31, 2026
	(in thousands)
Minerals and royalties (CRF)
Revenues	$	44,509
Operating expense	4,226
Gain (loss) on derivatives	(23,077)
Interest expense	(2,612)



Net income (loss)	529

Critical accounting policies and estimates

This discussion and analysis of our financial 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 March 31, 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.

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 subtract 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.

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 March 31, 2026, our derivative portfolio had an aggregate notional value of approximately $3.3 billion, and the fair market value of our commodity derivative contracts was a net liability of $330.2 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 March 31, 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 $293.3 million. If prices decreased by 10%, our derivative position would change by approximately $282.9 million. The hypothetical change in fair value could be a gain or a loss depending on whether commodity prices decrease or increase.

Derivative assets and liabilities are classified on our condensed consolidated balance sheets as risk management assets and liabilities. 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 March 31, 2026, we had no variable rate borrowings outstanding under the Revolving Credit Facility. At March 31, 2026, we had $349.5 million of variable rate borrowings outstanding under the Crescent Royalty Finance 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 $0.4 million increase or decrease in interest expense on our variable rate debt outstanding for the three months ended March 31, 2026.

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 SEC’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 March 31, 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 March 31, 2026 that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.

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 SEC, 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 SEC 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.

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 March 31, 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)
1/1/2026 - 1/31/2026	—	$—	—	$85,984
2/1/2026 - 2/28/2026	—	—	—	$335,984
3/1/2026 - 3/31/2026	—	—	—	$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 March 31, 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 March 31, 2026, no director or officer of the Company adopted or terminated a “Rule 10b5-1 trading arrangement” or “non-Rule 10b5-1 trading arrangement,” as each term is defined in Item 408(a) of Regulation S-K.

Departure of Directors or Certain Officers; Election of Directors; Appointment of Certain Officers; Compensatory Arrangements of Certain Officers

On May 4, 2026, Ms. Bevin Brown provided the Company with notice of her decision not to seek reappointment to the Board of Directors, effective May 4, 2026. Ms. Brown’s departure was not the result of any dispute or disagreement with the Company or any member of our Board of Directors or senior management team on any matter relating to the Company’s operations, policies or practices.

Submission of Matters to a Vote of Security Holders

On May 4, 2026, Independence Energy Aggregator L.P., by a written consent as the sole holder of Series I preferred stock of the Company, fixed the size of the Board of Directors to eleven directors and elected David C. Rockecharlie, Brandi Kendall, John C. Goff, Robert G. Gwin, Claire S. Farley, Conrad V. Langenhagen, Ellis L. “Lon” McCain, Karen J. Simon, Marcus C. Rowland, William Albrecht and Jarvis Hollingsworth as directors of the Company, to serve as provided in the Company’s Amended and Restated Certificate of Incorporation and Amended and Restated By-laws. Each director was serving as a director of the Company at the time of election.

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 Securities and Exchange Commission on May 16, 2024).
2.2#			Membership Interest Purchase Agreement, dated 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 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 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).
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 By-Laws 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, 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, 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).
4.15			Indenture, 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 4.3 4 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, 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 December 5, 2023, among Crescent Energy Finance LLC, the guarantors named therein, and Computershar e 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 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 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, 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 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 December 15, 2025, among Crescent Energy Finance, LLC, the guarantors named therein, and U.S. Bank Trust Company, National Association, and Computershare 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, 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 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, dated 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, dated 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, 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 F o r m 8-K, filed with the Securities and Exchange Commission on March 9, 2026).
10.1			Fourteenth Amendment to Credit Agreement, dated February 23 , 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 10.47 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).
10.2			Credit Agreement, dated February 23, 2026, by and among Crescent Royalty Finance LLC, certain subsidiaries of Crescent Royalty Finance LLC, as guarantors, Wells Fargo Bank, Na tional 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 10.48 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).
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 U.S. Securities and Exchange Commission.

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)

May 4, 2026						/s/ David Rockecharlie
						David Rockecharlie
						Chief Executive Officer
						(Principal Executive Officer)

May 4, 2026						/s/ Brandi Kendall
						Brandi Kendall
						Chief Financial Officer
						(Principal Financial Officer)