SEC Form 10-Q filed by Crescent Energy Company

5/5/25 4:27:38 PM ET

Oil & Gas Production

Energy

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crgy-20250331

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, 2025


☐			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, 2025, there were approximately 255,246,489 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			50
Part II - Other Information
Item 1. Legal Proceedings			51
Item 1A. Risk Factors			51
Item 2. Unregistered Sales of Equity Securities and Use of Proceeds			52
Item 3. Defaults Upon Senior Securities			52
Item 4. Mine Safety Disclosures			52
Item 5. Other Information			52
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 the Ridgemar Acquisition and SilverBow Merger;

•the risk that each of the SilverBow Merger and the Ridgemar Acquisition may not be accretive, and may be dilutive, to Crescent’s earnings per share, which may negatively affect the market price of Crescent common stock;

•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 KKR Energy Assets Manager LLC 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 heightened tensions with Iran, and other sustained military campaigns, the armed conflict in Ukraine and associated economic sanctions on Russia, conditions in South America, 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;

•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 (“D&C”) 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 increased 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 Inflation Reduction Act of 2022 (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 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 increased hostilities in the Middle East and heightened tensions with Iran;

•information technology failures or cyberattacks;

•changes in tax laws;

•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, 2024 ("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, 2025		December 31, 2024
ASSETS
Current assets:
Cash and cash equivalents	$	6,255	$	132,818
Restricted cash	3,247		5,490
Accounts receivable, net	612,129		535,416
Accounts receivable – affiliates	650		6,856
Derivative assets – current	4,891		53,273


Prepaid expenses	38,728		42,595
Other current assets	13,367		11,640
Total current assets	679,267		788,088
Property, plant and equipment:
Oil and natural gas properties at cost, successful efforts method
Proved	12,688,077		11,471,299
Unproved	365,964		374,306
Oil and natural gas properties at cost, successful efforts method	13,054,041		11,845,605
Field and other property and equipment, at cost	230,077		226,871
Total property, plant and equipment	13,284,118		12,072,476
Less: accumulated depreciation, depletion, amortization and impairment	(4,217,540)		(3,927,422)
Property, plant and equipment, net	9,066,578		8,145,054

Derivative assets – noncurrent	—		6,684
Investments in equity affiliates	13,892		13,810
Other assets	112,597		207,013
TOTAL ASSETS	$	9,872,334	$	9,160,649
















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, 2025		December 31, 2024

LIABILITIES, REDEEMABLE NONCONTROLLING INTERESTS AND EQUITY
Current liabilities:
Accounts payable and accrued liabilities	$	736,519	$	740,452
Accounts payable – affiliates	21,092		18,334
Derivative liabilities – current	45,994		2,698
Financing lease obligations – current	4,619		3,625

Other current liabilities	61,949		62,254
Total current liabilities	870,173		827,363
Long-term debt	3,596,870		3,049,255
Derivative liabilities – noncurrent	37,977		37,732
Asset retirement obligations	468,410		448,945
Deferred tax liability	367,603		370,329
Financing lease obligations – noncurrent	3,712		3,526
Other liabilities	93,691		55,539
Total liabilities	5,438,436		4,792,689
Commitments and contingencies (Note 9)
Redeemable noncontrolling interests	1,168,691		1,228,329
Equity:
Class A common stock, $0.0001 par value; 1,000,000,000 shares authorized, 197,908,478 and 189,505,209 shares issued, 194,972,159 and 187,070,725 shares outstanding as of March 31, 2025 and December 31, 2024, respectively	20		19
Class B common stock, $0.0001 par value; 500,000,000 shares authorized and 62,999,401 and 65,948,124 shares issued and outstanding as of March 31, 2025 and December 31, 2024, respectively	7		7
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, 2025 and December 31, 2024	—		—
Treasury stock, at cost; 2,936,319 and 2,434,484 shares of Class A common stock as of March 31, 2025 and December 31, 2024, respectively	(37,742)		(32,430)
Additional paid-in capital	3,360,061		3,227,450
Retained earnings (accumulated deficit)	(66,901)		(64,751)
Noncontrolling interests	9,762		9,336
Total equity	3,265,207		3,139,631
TOTAL LIABILITIES, REDEEMABLE NONCONTROLLING INTERESTS AND EQUITY	$	9,872,334	$	9,160,649

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,
	2025		2024
Revenues:
Oil	$	619,658	$	473,894
Natural gas	187,440		79,944
Natural gas liquids	107,575		66,947
Midstream and other	35,499		36,688
Total revenues	950,172		657,473
Expenses:
Lease operating expense	161,595		130,688
Workover expense	16,022		12,302
Asset operating expense	30,410		31,350
Gathering, transportation and marketing	105,287		69,569
Production and other taxes	60,381		32,523
Depreciation, depletion and amortization	282,573		176,564
Impairment of oil and natural gas properties	45,647		—
Exploration expense	306		—
Midstream and other operating expense	29,816		27,742
General and administrative expense	56,770		42,715
(Gain) loss on sale of assets	(10,862)		—
Total expenses	777,945		523,453
Income (loss) from operations	172,227		134,020
Other income (expense):
Gain (loss) on derivatives	(91,028)		(105,602)
Interest expense	(73,182)		(42,686)
Loss from extinguishment of debt	—		(22,582)
Other income (expense)	115		150
Income (loss) from equity affiliates	392		127
Total other income (expense)	(163,703)		(170,593)
Income (loss) before taxes	8,524		(36,573)
Income tax benefit (expense)	(2,613)		4,209
Net income (loss)	5,911		(32,364)

Less: net (income) loss attributable to noncontrolling interests	(1,989)		(3,499)
Less: net (income) loss attributable to redeemable noncontrolling interests	(6,072)		11,695
Net income (loss) attributable to Crescent Energy	$	(2,150)	$	(24,168)
Net income (loss) per share:
Class A common stock – basic	$	(0.01)	$	(0.25)
Class A common stock – diluted	$	(0.01)	$	(0.25)
Class B common stock – basic and diluted	$	—	$	—
Weighted average shares outstanding:
Class A common stock – basic	191,294		94,793
Class A common stock - diluted	191,294		94,793
Class B common stock – basic and diluted	65,260		84,333

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, 2024		91,609	$	9	88,048	$	9	1	$	—	1,071	$	(17,143)	$	1,626,501	$	95,447	$	29,687	$	1,734,510
Net income (loss)		—	—		—	—		—	—		—	—		—		(24,168)		3,499		(20,669)

Distributions		—	—		—	—		—	—		—	—		—		—		(8,037)		(8,037)

Dividend to Class A common stock		—	—		—	—		—	—		—	—		—		(12,649)		—		(12,649)
Equity-based compensation		—	—		—	—		—	—		—	—		14,556		—		276		14,832


Change in deferred taxes related to basis differences associated with the 2024 Equity Transactions		—	—		—	—		—	—		—	—		(30,713)		—		—		(30,713)
Change in equity associated with the 2024 Equity Transactions		13,800	2		(16,100)	(2)		—	—		—	—		318,963		—		—		318,963
Balance at March 31, 2024		105,409	$	11	71,948	$	7	1	$	—	1,071	$	(17,143)	$	1,929,307	$	58,630	$	25,425	$	1,996,237



























Balance at 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)

Dividend to Class A common stock		—	—		—	—		—	—		—	—		(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 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

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,
	2025		2024
Cash flows from operating activities:
Net income (loss)	$	5,911	$	(32,364)
Adjustments to reconcile net income (loss) to net cash provided by operating activities
Depreciation, depletion and amortization	282,573		176,564
Impairment expense	45,647		—
Deferred tax expense (benefit)	(8,200)		(4,925)
(Gain) loss on derivatives	91,028		105,602
Net cash (paid) received on settlement of derivatives	(10,798)		(22,806)
Non-cash equity-based compensation expense	26,225		28,174
Amortization of debt issuance costs, premium and discount	3,753		4,376
Loss from debt extinguishment	—		22,582
(Gain) loss on sale of oil and natural gas properties	(10,862)		—

Settlement of acquired derivative contracts	17,888		—
Other	(10,750)		(6,098)
Changes in operating assets and liabilities:
Accounts receivable	(83,197)		42,794
Accounts receivable – affiliates	6,206		(5,765)
Prepaid and other current assets	1,685		(430)
Accounts payable and accrued liabilities	(20,591)		(101,948)
Accounts payable – affiliates	3,041		(20,524)
Other	(2,445)		(1,462)
Net cash provided by operating activities	337,114		183,770
Cash flows from investing activities:
Development of oil and natural gas properties	(199,199)		(136,816)
Acquisitions of oil and natural gas properties, net of cash acquired	(864,674)		(19,532)
Proceeds from the sale of oil and natural gas properties	6,931		—
Purchases of restricted investment securities – HTM	(1,781)		(1,776)
Maturities of restricted investment securities – HTM	1,800		1,800

Other	—		(1,137)
Net cash used in investing activities	(1,056,923)		(157,461)
Cash flows from financing activities:
Proceeds from the issuance of Senior Notes, after premium, discount and underwriting fees	—		690,375
Repurchase of Senior Notes, including extinguishment costs	—		(714,817)
Revolving Credit Facility borrowings	1,079,500		684,600
Revolving Credit Facility repayments	(533,000)		(626,800)
Payment of debt issuance costs	(1,142)		(3,721)







Dividend to Class A common stock	(23,457)		(12,649)
Cash distributions to redeemable noncontrolling interests initiated by Class A common stock dividend	(7,560)		(8,274)
Cash distributions to redeemable noncontrolling interests initiated by Manager Compensation	(4,525)		(6,798)
Cash contributions from (cash distributions to) redeemable noncontrolling interests initiated by income taxes	(95)		(66)
Repurchase of redeemable noncontrolling interests related to 2024 Equity Transactions	—		(22,701)


Noncontrolling interest distributions	(1,756)		(1,858)


Repurchases of Class A common stock	(5,312)		—
Other	—		(1,158)
Net cash provided by (used in) financing activities	502,653		(23,867)
Net change in cash, cash equivalents and restricted cash	(217,156)		2,442
Cash, cash equivalents and restricted cash, beginning of period	240,908		8,729
Cash, cash equivalents and restricted cash, end of period	$	23,752	$	11,171

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 and its subsidiaries.

NOTE 1 – Organization and Basis of Presentation

Organization

Crescent is a differentiated U.S. energy company committed to delivering value for shareholders through a disciplined growth through acquisition strategy and consistent return of capital. Our long-life, balanced portfolio combines stable cash flows from low-decline production with deep, high-quality development inventory. Our activities are focused in Texas and the Rocky Mountain region.

Corporate Structure

Our Class A Common Stock is listed on the New York Stock Exchange under the symbol “CRGY.” Crescent is a holding company, the sole material asset of which is units ("OpCo Units") of Crescent Energy OpCo LLC ("OpCo"). The assets and liabilities of OpCo represent substantially all of our consolidated assets and liabilities, with the exception of certain current and deferred taxes and certain liabilities under the Management Agreement, as defined within NOTE 11 – Related Party Transactions. Certain restrictions and covenants related to the transfer of assets from OpCo are discussed further in NOTE 7 – Debt. Shares of Crescent Class A common stock, par value $0.0001 per share ("Class A Common Stock") have both voting and economic rights with respect to Crescent. Previously, Crescent was structured as an “Up-C,” pursuant to which holders of Crescent Class B common stock, par value $0.0001 per share ("Class B Common Stock"), which shares of Class B Common Stock had voting (but no economic) rights with respect to Crescent, held a corresponding amount of economic, non-voting OpCo Units. OpCo Units were redeemable or exchangeable for Class A Common Stock or, at our election, cash on the terms and conditions set forth in the Amended and Restated Limited Liability Company Agreement of OpCo (“OpCo LLC Agreement”). Additionally, 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 Crescent and to certain other approval rights.

On April 8, 2025, we announced that our corporate structure had been simplified through the elimination of the Company’s Up-C structure through the exercise, effective April 4, 2025, by the holders of all remaining shares of Class B common stock of their redemption rights with respect to all of their OpCo Units (the “Corporate Simplification”). Pursuant to such exercise, all of their OpCo Units 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 stockholders now hold Class A common stock. Except as otherwise stated herein, the information in this Quarterly Report does not give effect to the Corporate Simplification, which occurred after the period covered by this report. See NOTE 11 – Related Party Transactions for more information.

2025 Equity Transactions

In March 2025, Independence Energy Aggregator L.P., 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 "March 2025 Class A Redemption"). The shares of Class A Common Stock were sold by Independence Energy Aggregator L.P. 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 March 2025 Class A Redemption.

As a result of the March 2025 Class A Redemption, the total number of shares of our Class A Common Stock increased by 2.9 million shares and the total number of shares of our Class B Common Stock decreased by 2.9 million shares. Redeemable noncontrolling interests decreased by $34.1 million while APIC increased by $34.1 million as a result of the March 2025 Class A Redemption.

2024 Equity Transactions

In March 2024, 16.1 million OpCo Units were acquired from Independence Energy Aggregator L.P. and we cancelled a corresponding number of shares of Class B Common Stock (the "March 2024 Redemption"). Of the total OpCo Units acquired, 13.8 million were exchanged for shares of Class A Common Stock, which were subsequently sold in an underwritten public offering at a price to the public of $10.50 per share, or a net price of $9.87 per share after deducting the underwriters' discounts and commissions, from which we did not receive any proceeds, nor incur any material expenses with respect to such acquisition. In connection with the underwritten public offering, we repurchased 2.3 million OpCo Units from Independence Energy Aggregator L.P. for $22.7 million in cash and we cancelled a corresponding number of shares of Class B Common Stock (the "March 2024 Repurchase," together with the March 2024 Redemption, the "March 2024 Equity Transactions").

As a result of the March 2024 Equity Transactions, the total number of shares of our Class A Common Stock increased by 13.8 million shares and the total number of shares of our Class B Common Stock decreased by 16.1 million shares. Redeemable noncontrolling interests decreased by $341.7 million while APIC increased by $319.0 million as a result of the March 2024 Equity Transactions.

Treasury Stock

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. 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. After share repurchases in early April 2025, the remaining amount under the authorized plan is approximately $91.0 million as of April 30, 2025.

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. During 2024, we repurchased 0.7 million shares of our Class A Common Stock for $7.8 million, at an average price of $10.70 per share (the "2024 Class A Repurchases"), and in connection therewith, we cancelled a corresponding number of OpCo units held by us. 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," and together with the 2024 Class A Repurchases, the "Class A Repurchases"), and in connection therewith, we cancelled a corresponding number of OpCo units.

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. general 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.

Crescent is a holding company that conducts substantially all of its business through its consolidated subsidiaries, including (i) OpCo, which as of March 31, 2025 was owned approximately 76% by Crescent and approximately 24% by holders of our redeemable noncontrolling interests, and (ii) Crescent Energy Finance LLC, OpCo's wholly owned subsidiary. Crescent and OpCo have no operations, or material cash flows, assets or liabilities other than their investment in Crescent Energy Finance LLC. The assets and liabilities of OpCo represent substantially all of our consolidated assets and liabilities with the exception of certain current and deferred taxes and certain liabilities under the Management Agreement (as defined within NOTE 11 – Related Party Transactions). Certain restrictions and covenants related to the transfer of assets from OpCo are discussed further in NOTE 7 – Debt.

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. The majority of our restricted cash is composed of cash that is contractually required to be restricted to fund acquisitions or to pay for the future abandonment of certain wells. Restricted cash is included in Other current assets and 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,
	2025		2024
	(in thousands)
Cash and cash equivalents	$	6,255	$	5,321
Restricted cash – current	3,247		261
Restricted cash – noncurrent	14,250		5,589
Total cash, cash equivalents and restricted cash	$	23,752	$	11,171

Redeemable Noncontrolling Interests

Pursuant to the OpCo LLC Agreement, holders of OpCo Units, other than the Company, may redeem all or a portion of their OpCo Units for either (a) shares of Class A Common Stock or (b) at the election of the Company, an approximately equivalent amount of cash as determined pursuant to the terms of the OpCo LLC Agreement. In connection with such redemption, a corresponding number of shares of Class B Common Stock will be cancelled. The cash redemption election is not considered to be within the control of the Company because the holders of Class B Common Stock and their affiliates control the Company through direct representation on the Board of Directors. As a result, we present the noncontrolling interests in OpCo as redeemable noncontrolling interests outside of permanent equity. Redeemable noncontrolling interests are recorded at the greater of the carrying value or redemption amount with a corresponding adjustment to Additional paid-in capital. The cash redemption amount for OpCo Units for this purpose is based on the 10-day volume-weighted average closing price of Class A Common Stock at the end of the reporting period. Changes in the redemption value are recognized immediately as they occur, as if the end of the reporting period was also the redemption date for the instrument, with an offsetting entry to Additional paid-in capital.

For the three months ended March 31, 2025, the March 2025 Class A Redemption reduced the number of shares of our Class B Common Stock by 2.9 million shares. As a result of the transfer of additional OpCo Units to Crescent, we reclassified $34.1 million from Redeemable noncontrolling interests to Additional paid-in capital.

For the three months ended March 31, 2024, the 2024 Equity Transactions reduced the number of shares of our Class B Common Stock by 16.1 million shares. In addition, the 2024 Equity Transactions resulted in the transfer of 13.8 million OpCo

Units to Crescent and the repurchase, by OpCo, of 2.3 million OpCo Units for $22.7 million in cash. As a result of the transfer of additional OpCo Units to Crescent, we reclassified $319.0 million from Redeemable noncontrolling interests to Additional paid-in capital.

From December 31, 2024 through March 31, 2025, we recorded adjustments to the value of our redeemable noncontrolling interests as shown below:


	Redeemable Noncontrolling Interests
	(in thousands)
Balance as of December 31, 2024	$	1,228,329
Net (loss) income attributable to redeemable noncontrolling interests	6,072


Cash distributions from OpCo initiated by Class A common stock dividend, Manager Compensation and income taxes, net	(7,648)
Accrued OpCo cash distribution initiated by Manager Compensation	(4,242)
Equity-based compensation	6,635


Change in redeemable noncontrolling interests associated with the Ridgemar Acquisition	(26,359)
Change in redeemable noncontrolling interests associated with the March 2025 Class A Redemption	(34,096)

Balance as of March 31, 2025	$	1,168,691

Income Taxes

Crescent 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, 2025, we recognized income tax expense of $2.6 million for an effective tax rate of 30.7%, respectively. For the three months ended March 31, 2024, we recognized income tax benefit of $4.2 million for an effective tax rate of 11.5%. Our effective tax rate has typically been lower than the U.S. federal statutory income tax rate of 21% primarily due to effects of removing income and losses related to our noncontrolling interests and redeemable noncontrolling interests. Our effective tax rate for the three months ended March 31, 2025 was driven higher primarily due to our increased ownership of OpCo in 2025, temporary timing difference 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. Pursuant to Sections 382 and 383 of the U.S. Internal Revenue Code of 1986, as amended, utilization of our NOL and RBIL carryforwards is subject to an annual limitation. These annual limitations may result in the expiration of 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 Section 382 limitations. As part of the Corporate Simplification that occurred in April 2025, see NOTE 11 – Related Party Transactions, we are evaluating the impact to any additional Section 382 limitations.

As of March 31, 2025 and December 31, 2024, 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, 2025 and 2024:


	Three Months Ended March 31,
	2025		2024
	(in thousands)
Supplemental cash flow disclosures:
Interest paid, net of amounts capitalized	$	95,599	$	50,069
Income tax payments (refunds)	1,614		86
Non-cash investing and financing activities:
Capital expenditures included in accounts payable and accrued liabilities	$	188,896	$	136,630

Equity consideration for acquisitions	82,145		—
Right-of-use assets obtained in exchange for leases	3,055		3,673

NOTE 3 – Acquisitions and Divestitures

Acquisitions

Ridgemar Acquisition

On December 3, 2024, we entered into the Membership Interest Purchase Agreement (the “Ridgemar Acquisition Agreement”) pursuant to which we acquired all of the outstanding equity interests in Ridgemar (Eagle Ford) LLC (“Ridgemar”). In connection with the closing of the Ridgemar Acquisition in the first quarter of 2025, we paid $812.5 million in cash and issued 5.5 million shares of our Class A Common Stock to former Ridgemar owners, before any customary post closing adjustments (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.

SilverBow Merger

On July 30, 2024, we consummated the transactions contemplated by the Agreement and Plan of Merger, dated May 15, 2024 (the transactions contemplated therein, the "SilverBow Merger"), between Crescent, SilverBow, Artemis Acquisition Holdings Inc. ("Artemis Holdings"), Artemis Merger Sub Inc. ("Merger Sub Inc.") and Artemis Merger Sub II LLC ("Merger Sub LLC"). The SilverBow Merger has been accounted for as a business combination using the acquisition method of accounting in accordance with Accounting Standards Codification (“ASC”) Topic 805, Business Combinations (“ASC 805”), with Crescent being identified as the accounting acquirer.

Merger Sub Inc., a Delaware corporation and a direct wholly owned subsidiary of Crescent, merged with and into SilverBow (the "Initial Merger"), with SilverBow surviving the merger (the "Initial Surviving Corporation"), and immediately following the Initial Merger, the Initial Surviving Corporation merged with and into Merger Sub LLC, a Delaware limited liability company and a direct, wholly owned subsidiary of Artemis Holdings, a Delaware corporation and a direct wholly owned subsidiary of Crescent (the "Subsequent Merger" and together with the Initial Merger, the "Mergers"), with Merger Sub LLC continuing as the surviving company of the Subsequent Merger (the "Subsequent Surviving Company") as a direct wholly owned subsidiary of Artemis Holdings. Promptly following the completion of the Mergers, Artemis Holdings contributed the Subsequent Surviving Company to Crescent Energy OpCo LLC, a Delaware limited liability company, of which Crescent is the managing member, which in turn contributed the Subsequent Surviving Company to its wholly owned subsidiary, Crescent Energy Finance, a Delaware limited liability company.

Subject to the terms and conditions of the Merger Agreement, each share of SilverBow's common stock, par value $0.01 per share ("SilverBow Common Stock") issued and outstanding immediately prior to the merger close date, was converted into the right to receive, pursuant to an election made and not revoked, one of the following forms of consideration: (A) 3.125 shares of Crescent Class A Common Stock, (B) a combination of 1.866 shares of Crescent Class A Common Stock and $15.31 in cash or (C) $38.00 in cash, subject to an aggregate cap of $400.0 million on the total cash consideration payable for the SilverBow Common Stock in the SilverBow Merger. The Merger Agreement also provided that each outstanding SilverBow restricted stock unit, performance-based stock unit (assuming maximum performance) and in-the money stock option, whether vested or unvested, held by certain employees and directors of SilverBow (collectively, the "SilverBow Equity Awards") became fully vested and was canceled and converted into a right to receive a cash payment (less the exercise price in the case of stock options) or, in the case of the restricted stock units and performance-based stock units, a partial cash payment and partial settlement in shares of Crescent Class A Common Stock. Each stock option with an exercise price that equaled or exceeded the amount of such cash payment was cancelled for no consideration. See the table below for consideration transferred and preliminary purchase price allocation. Certain data necessary to complete the purchase price allocation is not yet available, including final tax returns that provide the underlying tax basis of SilverBow’s assets and liabilities. We expect to complete the purchase price allocation during the 12-month period following the acquisition date. Crescent issued 51.6 million shares of Class A Common Stock in the SilverBow Merger and paid $382.4 million in cash to former SilverBow shareholders, including amounts payable in respect of outstanding SilverBow equity awards. See Note 10 - Equity-Based Compensation Awards.

During the three months ended March 31, 2025, we recognized revenue and net income associated with operations acquired through the SilverBow Merger were $271.6 million and $90.7 million, respectively. We recognized total transaction related expenses of $46.4 million on the condensed consolidated statements of operations, of which $3.6 million were recognized within Production and other taxes during the three months ended March 31, 2025 and $42.8 million were recognized within General and administrative expense during the second half of 2024.

The following table summarizes our unaudited pro forma financial information for the three months ended March 31, 2024 as if the SilverBow Merger and Central Eagle Ford Acquisition, as defined below, occurred on January 1, 2024 (unaudited):


	Three Months Ended March 31, 2024
	(in thousands)
Revenues	$	930,085
Net income	1,670

During 2024 we reorganized our business, primarily as a result of the SilverBow Merger, which included one-time termination costs and exit costs for the closure of one of our offices. We expect the total amount of one-time employee termination benefits incurred to be $11.4 million and lease termination and other costs of $5.5 million, all of which was recognized on the condensed consolidated statements of operations during the second half of 2024. The following is a reconciliation of our restructuring liability, which is included within Accounts payable and accrued liabilities on the condensed consolidated balance sheets.


	One-time employee termination benefits		Lease termination and other costs		Total
	(in thousands)



December 31, 2024	$	4,902	$	—	$	4,902
Costs incurred and charged to expense	—		—		—
Costs paid	(1,766)		—		(1,766)
March 31, 2025	$	3,136	$	—	$	3,136

Other Acquisitions

Webb Gas Acquisition

In January 2025, we acquired from unaffiliated third parties additional interests in Crescent operated oil and gas properties, rights and related assets located in Webb County, Texas for aggregate consideration of approximately $21.2 million, subject to customary post closing adjustments.

Central Eagle Ford Acquisition

In October 2024, we acquired from unaffiliated third parties certain interests in oil and gas properties, rights and related assets located in Atascosa, Frio, La Salle and McMullen Counties, Texas for aggregate consideration of approximately $156.0 million, including certain customary purchase price adjustments (the “Central Eagle Ford Acquisition”).

The Central Eagle Ford Acquisition has been accounted for as a business combination using the acquisition method of accounting in accordance with ASC 805, with Crescent being identified as the accounting acquirer. From the date of the Central Eagle Ford Acquisition through December 31, 2024, revenues and net income associated with operations acquired through the Central Eagle Ford Acquisition were $10.4 million and $3.1 million, respectively. We recognized transaction related expenses of $5.6 million within General and administrative expense on the condensed consolidated statements of operations for the year ended December 31, 2024.

Eagle Ford Minerals Acquisition

In February 2024, we acquired a portfolio of oil and natural gas mineral interests located in the Karnes Trough of the Eagle Ford Basin from an unrelated third-party (the "Eagle Ford Minerals Acquisition") for total cash consideration of approximately $25.0 million, including customary purchase price adjustments. The purchase price was funded using borrowings under our Revolving Credit Facility.

Consideration Transferred

The following table summarizes the consideration transferred and the net assets acquired for our acquisitions during 2025 and 2024 that impact the periods presented:


	Asset Acquisitions						Business Combinations

	Ridgemar Acquisition		Webb Gas Acquisition		Eagle Ford Minerals Acquisition			SilverBow Merger		Central Eagle Ford Acquisition
	(in thousands)
Consideration transferred:
Cash consideration:
Cash paid	$	812,529	$	21,204	$	25,000		$	358,092	$	156,031
Settlement of SilverBow Equity Awards in cash	—				—			18,858		—
Equity consideration:
Fair value of Class A Common Stock issued	82,145		—		—			595,294		—
Settlement of SilverBow Equity Awards in Class A Common Stock	—		—		—			16,129		—
Fair value of contingent earn-out consideration	51,746		—		—			—		—
Transaction costs capitalized	18,484		—		—			—		—
Total	$	964,904	$	21,204	$	25,000		$	988,373	$	156,031
Assets acquired and liabilities assumed:
Cash and cash equivalents	$	—	$	—	$	—		$	5,200	$	—
Accounts receivable, net	1,237		—		—			140,073		—
Derivative assets – current	—		—		—			100,601		—
Prepaid expenses	—		—		—			6,154		—
Other current assets	—		—		—			945		—
Oil and natural gas properties - proved	992,836		21,204		12,865			1,980,500		144,085
Oil and natural gas properties - unproved	—		—		12,135			207,191		—
Field and other property and equipment	3,108		—		—			4,586		17,848
Derivative assets – noncurrent	—		—		—			37,870		—



Other assets	—		—		—			25,199		—
Accounts payable and accrued liabilities	(8,316)		—		—			(196,963)		(1,212)
Acquired deferred acquisition consideration	—		—		—			(76,550)		—
Other current liabilities	(573)		—		—			(10,029)		—

Short-term debt	—		—		—			(37,500)		—
Long-term debt	—		—		—			(1,103,125)		—
Deferred tax liability	—		—		—			(58,670)		—

Asset retirement obligations	(22,855)		—		—			(25,683)		(4,690)
Other liabilities	(533)		—		—			(11,426)		—
Net assets acquired	$	964,904	$	21,204	$	25,000		$	988,373	$	156,031

Divestitures

In addition, in March 2025, we entered into the purchase and sale agreement to sell certain of our non-core assets to an unrelated third-party buyer for $83.0 million in aggregate cash proceeds, subject to customary purchase price adjustments. The transaction closed during the second quarter of 2025. We determined that the assets associated with this divestiture met the criteria of held for sale classification as of March 31, 2025. We performed a fair value assessment of the associated assets and liabilities and recorded an impairment of $45.6 million to the carrying value of the associated oil and natural gas properties. The table below summarizes the balance sheet information associated with assets and liabilities held for sale related to the transaction as of the balance sheet date.


	March 31, 2025
	(in thousands)
Long term assets:
Property, plant and equipment:
Oil and natural gas properties at cost, successful efforts method
Proved	$	182,713
Less: accumulated depreciation, depletion, amortization and impairment	(100,009)
Property, plant and equipment, net	$	82,704
Long term liabilities:
Asset retirement obligations	$	666

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 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, 2025, 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.

Collars: Collars provide a minimum and maximum price on a notional amount of sales volume. Under a collar, we will receive payment if the settlement price is less than the minimum price of the range and make a payment to the counterparty if the settlement price is greater than the maximum price of the range. We would not be required to make a payment or receive payment if the settlement price falls within the range.

The following table details our net volume positions by commodity as of March 31, 2025:


Production Period	Volumes	Weighted Average Fixed Price					Fair Value
	(in thousands)						(in thousands)
Crude oil swaps – WTI (Bbls):
2025	11,338	$70.21					$	13,418
2025 (1)	368	$76.50					(149)
2026	4,301	$68.71					12,802
2026 (2)	2,738	$76.31					(2,771)
2027 (3)	3,650	$75.00					(8,773)





Crude oil collars – WTI (Bbls):
2025	4,078	$	62.24	-	$	79.20	3,137

2026	273	$	64.00	-	$	71.50	440
2026 (4)	730	$	65.00	-	$	76.00	(1,540)

Crude oil collars – Brent (Bbls):
2025	275	$	65.00	-	$	91.61	367


Natural gas swaps (MMBtu):
2025	47,320	$3.91					(26,531)
2026	91,020	$4.04					(33,442)

2027 (5)	18,250	$4.19					(6,452)
Natural gas collars (MMBtu):
2025	54,389	$	3.06	-	$	5.70	(12,641)
2026	40,100	$	3.02	-	$	4.65	(20,804)

NGL swaps (Bbls):
2025	1,100	$23.88					(3,397)

Crude oil basis swaps (Bbls):
2025	12,923	$1.62					2,613
2026	3,831	$1.85					600

Natural gas basis swaps (MMBtu):
2025	83,225	$(0.29)					15,047
2026	98,500	$(0.43)					(4,145)
2027	47,450	$(0.36)					(2,892)
Calendar Month Average roll swaps (Bbls):
2025	12,917	$0.37					(3,892)
2026	1,825	$0.20					(75)

Total							$	(79,080)

(1) Represents outstanding crude oil swap options exercisable by the counterparty until June 2025.

(2) Represents outstanding crude oil swap options exercisable by the counterparty until December 2025.

(3) Represents outstanding crude oil swap options exercisable by the counterparty until December 2026.

(4) Represents outstanding crude oil collar options exercisable by the counterparty until December 2025.

(5) Represents outstanding Natural Gas swap options exercisable by the counterparty until December 2026.

Ridgemar Contingent Consideration: Pursuant to the 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 $75per barrel. For each quarterly period in 2027, we will be required to pay $12.5 million if the average price 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 service provider using a Monte Carlo simulation. The significant inputs used 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.

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, 2025 and December 31, 2024:


	Gross Fair Value		Effect of Counterparty Netting		Net Carrying Value
	(in thousands)
March 31, 2025
Assets:
Derivative assets – current	$	57,591	$	(52,700)	$	4,891
Derivative assets – noncurrent	20,538		(20,538)		—
Total assets	$	78,129	$	(73,238)	$	4,891
Liabilities:
Derivative liabilities – current	$	(98,694)	$	52,700	$	(45,994)
Other current liabilities	(9,207)		—		(9,207)
Derivative liabilities – noncurrent	(58,515)		20,538		(37,977)
Other liabilities	(42,050)		—		(42,050)
Total liabilities	$	(208,466)	$	73,238	$	(135,228)

December 31, 2024
Assets:
Derivative assets – current	$	95,484	$	(42,211)	$	53,273
Derivative assets – noncurrent	25,287		(18,603)		6,684
Total assets	$	120,771	$	(60,814)	$	59,957
Liabilities:
Derivative liabilities – current	$	(44,909)	$	42,211	$	(2,698)
Derivative liabilities – noncurrent	(56,335)		18,603		(37,732)
Total liabilities	$	(101,244)	$	60,814	$	(40,430)

See NOTE 5 – Fair Value Measurements for more information.

The amount of gain (loss) recognized in gain (loss) on derivatives in our condensed consolidated statements of operations was as follows for the three months ended March 31, 2025 and 2024:


	Three Months Ended March 31,
	2025		2024
	(in thousands)
Derivatives not designated as hedging instruments:
Realized gain (loss) on oil positions	$	(4,354)	$	(44,062)

Realized gain (loss) on natural gas positions	(5,156)		21,256
Realized gain (loss) on NGL positions	(1,288)		—

Total realized gain (loss) on derivatives	(10,798)		(22,806)
Unrealized gain (loss) on commodity derivatives	(80,719)		(82,796)
Unrealized gain (loss) on contingent earn-out consideration	489		—
Total unrealized gain (loss) on derivatives	(80,230)		(82,796)
Gain (loss) on derivatives	$	(91,028)	$	(105,602)

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, 2025 and December 31, 2024 by level within the fair value hierarchy:


	Fair Value Measurement Using
	Level 1		Level 2		Level 3		Total
	(in thousands)
March 31, 2025
Financial assets:
Derivative assets	$	—	$	78,129	$	—	$	78,129
Financial liabilities:
Derivative liabilities	$	—	$	(157,209)	$	—	$	(157,209)
Contingent earn-out consideration	—		(51,257)		—		(51,257)

December 31, 2024
Financial assets:
Derivative assets	$	—	$	120,771	$	—	$	120,771
Financial liabilities:
Derivative liabilities	$	—	$	(101,244)	$	—	$	(101,244)

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 inputs used to determine such fair value are primarily based upon internally developed cash flow models 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.

We also perform a separate impairment analysis when certain assets are classified as held for sale. The analysis is based on the agreed-upon proceeds less costs to sell, a Level 2 fair value measurement. For assets classified as held for sale during the quarter ended March 31, 2025, the carrying value of the net assets to be divested exceeded the fair value implied by the expected net proceeds, resulting in an impairment of $45.6 million to our proved oil and natural gas properties. See NOTE 3 – Acquisitions and Divestitures.

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 Senior Notes (as defined herein) as of March 31, 2025 and December 31, 2024 was approximately $3,096.3 million and $3,113.8 million, 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, 2025 and December 31, 2024:


	March 31, 2025		December 31, 2024
	(in thousands)
Accounts payable and accrued liabilities:
Accounts payable	$	76,216	$	56,323
Accrued lease and asset operating expense	77,145		76,990
Accrued capital expenditures	160,423		171,365
Accrued general and administrative expense	18,241		15,044
Accrued gathering, transportation and marketing expense	78,790		76,477
Accrued revenue and royalties payable	193,512		192,884
Accrued interest expense	71,499		98,343
Accrued severance taxes	34,279		36,135

Other	26,414		16,891
Total accounts payable and accrued liabilities	$	736,519	$	740,452

NOTE 7 – Debt

Senior Notes

2033 Notes

In June 2024, we issued $750.0 million aggregate principal amount of 7.375% senior notes due 2033 (the "2033 Notes") at par (the "June 2024 Offering"). In September 2024, we issued an additional $250.0 million, aggregate principal amount of 2033 Notes at 101.000% of par (the "September 2024 Offering," and together with the June 2024 Offering, the "2033 Notes Offerings"). The aggregate proceeds from the 2033 Notes Offerings were approximately $982.1 million, after adjusting for premiums, the initial purchasers' discount and offering expenses. We used the aggregate net proceeds from the 2033 Notes Offerings to finance the majority of the SilverBow Merger, including (i) fund the cash paid to the SilverBow stockholders and holders of SilverBow restricted stock units in connection with the SilverBow Merger, (ii) repay and extinguish SilverBow's existing indebtedness that was outstanding at the completion of the SilverBow Merger for $1.2 billion, including extinguishment costs. In connection with the repayment of SilverBow's debt we incurred a Loss on the extinguishment of debt of $36.5 million, inclusive of make whole fees.

All issuances of the 2033 Notes are treated as a single series of securities under the indenture governing the 2033 Notes, will vote together as a single class, and have substantially identical terms, other than the issue date and the issue price.

The 2033 Notes bear interest at an annual rate of 7.375%, which is payable on January 15 and July 15 of each year, and mature on January 15, 2033. We may, at our option, redeem all or a portion of the 2033 Notes at any time on or after July 15, 2027 at certain redemption prices. We may also redeem up to 40% of the aggregate principal amount of the 2033 Notes before July 15, 2027 with an amount of cash not greater than the net proceeds that we raise in certain equity offerings at a redemption price equal to 107.375% of the principal amount of the 2033 Notes being redeemed, plus accrued and unpaid interest, if any, to, but excluding the redemption date, if at least 50% of the aggregate principal amount of the Notes remains outstanding immediately after such redemption and the redemption occurs within 180 days of the closing date of such equity offering. In addition, prior to July 15, 2027, we may redeem some or all of the 2033 Notes at a price equal to 100% of the principal amount thereof, plus a "make-whole" premium and accrued and unpaid interest, if any, to but excluding the redemption date.

2032 Notes

In March 2024, we issued $700.0 million aggregate principal amount of 7.625% senior notes due 2032 (the "2032 Notes") at par (the “March 2024 Offering”). In December 2024, we issued an additional $400.0 million, aggregate principal amount of 2032 Notes at 100.250% of par (the "December 2024 Offering," and together with the March 2024 Offering, the "2032 Notes Offerings"). The aggregate proceeds from the 2032 Notes Offering were approximately $1,080.7 million, after deducting the initial purchasers' discount and offering expenses. We used the net proceeds to finance the majority of the consideration of the Tender Offer and Redemption (each term as defined below) of all of the aggregate principal amount of the 2026 Notes

outstanding for $714.8 million after including extinguishment costs, as discussed further below. We used the proceeds from the December 2024 Offering to repay the amounts outstanding under our Revolving Credit Facility.

All issuances of the 2032 Notes are treated as a single series of securities under the indenture governing the 2032 Notes, will vote together as a single class, and have substantially identical terms, other than the issue date and the issue price.

The 2032 Notes bear interest at an annual rate of 7.625%, which is payable on April 1 and October 1 of each year, and mature on April 1, 2032. We may, at our option, redeem all or a portion of the 2032 Notes at any time on or after April 1, 2027 at certain redemption prices. We may also redeem up to 40% of the aggregate principal amount of the 2032 Notes before April 1, 2027 with an amount of cash not greater than the net proceeds that we raise in certain equity offerings at a redemption price equal to 107.625% of the principal amount of the 2032 Notes being redeemed, plus accrued and unpaid interest, if any, to, but excluding the redemption date. In addition, prior to April 1, 2027, we may redeem some or all of the 2032 Notes at a price equal to 100% of the principal amount thereof, plus a “make-whole” premium, plus accrued and unpaid interest, if any, to, but excluding the redemption date.

2028 Notes

In February 2023, we issued $400.0 million aggregate principal amount of 9.250% senior notes due 2028 (the "2028 Notes") at par. In July 2023, we issued an additional $300.0 million, aggregate principal amount of 2028 Notes at 98.000% of par. In September 2023, we issued an additional $150.0 million aggregate principal amount of 2028 Notes at 101.125% of par. In December 2023, we issued an additional $150.0 million aggregate principal amount of 2028 Notes at 102.125% of par. The aggregate proceeds from the offerings of the 2028 Notes were $977.4 million, after adjusting for discounts, premiums and offering expenses, but excluding accrued interest payable by purchasers of the 2028 Notes. We used the aggregate net proceeds to repay a portion of our outstanding balance under our Revolving Credit Facility (as defined herein) and to fund a portion of the Western Eagle Ford Acquisitions.

All issuances of the 2028 Notes are treated as a single series of securities under the indenture governing the 2028 Notes, will vote together as a single class, and have substantially identical terms, other than the issue date, the issue price, and the first interest payment date.

The 2028 Notes bear interest at an annual rate of 9.250%, which is payable on February 15 and August 15 of each year and mature on February 15, 2028.

After the completion of the Tender Offer and Redemption, the 2028 Notes, the 2032 Notes and 2033 Notes (collectively, the "Senior Notes") are our senior unsecured obligations and the Senior Notes and the related guarantees rank equally in right of payment with the borrowings under our Revolving Credit Facility and any of our other future senior indebtedness and senior to any of our future subordinated indebtedness. The Senior Notes are guaranteed on a senior unsecured basis by each of our existing and future subsidiaries that will guarantee our Revolving Credit Facility. The Senior Notes and the guarantees are effectively subordinated to all of our secured indebtedness (including all borrowings and other obligations under our Revolving Credit Facility) to the extent of the value of the collateral securing such indebtedness and structurally subordinated in right of payment to all existing and future indebtedness and other liabilities (including trade payables) of any future subsidiaries that do not guarantee the Senior Notes.

The indentures governing the Senior Notes contain covenants that, among other things, limit the ability of our restricted subsidiaries to: (i) incur or guarantee additional indebtedness or issue certain types of preferred stock; (ii) pay dividends or distributions in respect of its equity or redeem, repurchase or retire its equity or subordinated indebtedness; (iii) transfer or sell assets; (iv) make investments; (v) create certain liens; (vi) enter into agreements that restrict dividends or other payments from any non-Guarantor restricted subsidiary to it; (vii) consolidate, merge or transfer all or substantially all of its assets; (viii) engage in transactions with affiliates; and (ix) create unrestricted subsidiaries.

If we experience certain kinds of changes of control accompanied by a ratings decline, holders of the Senior Notes may require us to repurchase all or a portion of their notes at certain redemption prices. The Senior Notes are not listed, and we do not intend to list the notes in the future, on any securities exchange, and currently there is no public market for the notes.

Revolving Credit Facility

Overview

We are party to a senior secured reserve-based revolving credit agreement (as amended, restated, amended and restated or otherwise modified to date, the "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. Our Revolving Credit Facility matures on April 10, 2029, but contains terms that if certain conditions regarding our outstanding 2028 Notes exist on November 16, 2027, it will mature on November 16, 2027.

At March 31, 2025, we had $546.5 million of borrowings and $19.9 million in letters of credit outstanding under the Revolving Credit Facility.

The obligations under the Revolving Credit Facility remain secured by first priority liens on substantially all of the Company’s and the guarantors’ tangible and intangible assets, including without limitation, oil and natural gas properties and associated assets and equity interests owned by the Company and such guarantors. In connection with each redetermination of the borrowing base, the Company must maintain mortgages on at least 85% of the net present value, discounted at 9% per annum (“PV-9”) of the oil and natural gas properties that constitute borrowing base properties. The Company’s domestic direct and indirect subsidiaries are required to be guarantors under the Revolving Credit Facility, subject to certain exceptions.

The borrowing base is subject to semi-annual scheduled redeterminations on or about April 1 and October 1 of each year, as well as (i) elective borrowing base interim redeterminations at our request not more than twice during any consecutive 12-month period or the required lenders not more than once during any consecutive 12-month period and (ii) elective borrowing base interim redeterminations at our request following any acquisition of oil and natural gas properties with a purchase price in the aggregate of at least 5.0% of the then effective borrowing base. The borrowing base will be automatically reduced upon (i) the issuance of certain permitted junior lien debt and other permitted additional debt, (ii) the sale or other disposition of borrowing base properties if the aggregate PV-9 of such properties sold or disposed of is in excess of 5.0% of the borrowing base then in effect and (iii) early termination or set-off of swap agreements (a) the administrative agent relied on in determining the borrowing base or (b) if the value of such swap agreements so terminated is in excess of 5.0% of the borrowing base then in effect.

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 the unused revolving commitments at March 31, 2025 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 March 31, 2025 was 6.34%. We had no borrowing outstanding under the Revolving Credit Facility at December 31, 2024.

Covenants

The Revolving Credit Facility contains certain covenants that restrict the payment of cash dividends, certain borrowings, sales of assets, loans to others, investments, merger activity, commodity swap agreements, liens and other transactions without the adherence to certain financial covenants or 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. The Revolving 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 change of control. If an event of default occurs and we are unable to cure such default, the lenders will be able to accelerate maturity and exercise other rights and remedies.

Letters of Credit

From time to time, we may request the issuance of letters of credit for our own account. Letters of credit accrue interest at a rate equal to the margin associated with SOFR borrowings. At March 31, 2025 and December 31, 2024, we had letters of credit outstanding of $19.9 million and $21.2 million, respectively, which reduce the amount available to borrow under our Revolving Credit Facility.

Total Debt Outstanding

The following table summarizes our debt balances as of March 31, 2025 and December 31, 2024:


	Debt Outstanding		Letters of Credit Issued		Borrowing Base		Maturity
	(in thousands)
March 31, 2025
Revolving Credit Facility	$	546,500	$	19,936	$	2,600,000	4/10/2029

9.250% Senior Notes due 2028	1,000,000		—		—		2/15/2028
7.625% Senior Notes due 2032	1,100,000		—		—		4/1/2032
7.375% Senior Notes due 2033	1,000,000		—		—		1/15/2033
Less: Unamortized discount, premium and issuance costs	(49,630)
Total long-term debt	$	3,596,870

December 31, 2024
Revolving Credit Facility	$	—	$	21,186	$	2,600,000	4/10/2029

9.250% Senior Notes due 2028	1,000,000		—		—		2/15/2028
7.625% Senior Notes due 2032	1,100,000		—		—		4/1/2032
7.375% Senior Notes due 2033	1,000,000		—		—		1/15/2033
Less: Unamortized discount, premium and issuance costs	(50,745)
Total long-term debt	$	3,049,255

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, 2025:


	As of March 31, 2025
	(in thousands)
Balance at beginning of period	$	486,168

Additions (1)	24,006
Retirements	(1,780)
Sale	(19,204)

Accretion expense	8,695
Balance at end of period	497,885
Less: current portion	(29,475)
Balance at end of period, noncurrent portion	$	468,410

(1) For the three months ended March 31, 2025, our ARO additions primarily related to oil and natural gas properties acquired in the Ridgemar Acquisition. See NOTE 3 – Acquisitions and Divestitures for additional information.

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 judgement 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, 2025.

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,
	2025		2024
Equity-based compensation expense (income):	(in thousands)
Liability-classified profits interest awards	$	413	$	393
Equity-classified profits interest awards	193		276
Equity-classified LTIP RSU awards	631		297
Equity-classified LTIP PSU awards	69		159
Equity-classified Manager PSUs	25,332		27,049

Total equity-based compensation expense (income)	$	26,638	$	28,174

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, 2025, we did not grant any equity-classified LTIP RSU awards. In April 2025, we granted 0.8 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 $11.08 per LTIP RSU, and 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 Additional paid-in capital and Redeemable noncontrolling interest on our condensed consolidated balance sheets.

Equity-classified Manager PSU Awards

During the three months ended March 31, 2025, in conjunction with the March 2025 Class A Redemption, the closing of the Ridgemar Acquisition and our 2024 Class A Repurchases, the number of shares of our Class A Common Stock increased by 7.9

million. As a result, the number of equity-classified PSU target shares of Class A Common Stock related to the award of PSUs granted to the Manager under the Crescent Energy Company 2021 Manager Incentive Plan (referred to herein as the Incentive Compensation) increased by approximately 0.6 million shares for the three months ended March 31, 2025. We accounted for this increase as a change in estimate and recognized additional expense of $8.6 million for the three months ended March 31, 2025. See NOTE 3 – Acquisitions and Divestitures for more information on the March 2025 Class A Redemption and the closing of the Ridgemar Acquisition. For more information on the Incentive Compensation, including the performance-based vesting criteria applicable thereto, see NOTE 11 – Related Party Transactions - Management Agreement.

NOTE 11 – Related Party Transactions

KKR Group

Management Agreement

Crescent Energy Company has a management agreement (the "Management Agreement") with KKR Energy Assets Manager LLC (the "Manager"). Pursuant to the Management Agreement, the Manager provides the Company with members of its executive management team and certain management services. The Management Agreement has a term of three years, with automatic three-year renewals, unless the Company or the Manager elects not to renew the Management Agreement. The current term automatically renewed in December 2024 for an additional three-year term ending December 7, 2027.

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 was entitled to receive compensation from the Company equal to $52.5 million per annum ("Manager Compensation") (calculated based on the Company's pro rata relative ownership of OpCo as of March 31, 2025 multiplied by $69.5 million (the "Base Input")), which is included in General and administrative expenses on our condensed consolidated statements of operations. After giving effect to the Corporate Simplification, the Company's relative ownership of OpCo is 100% and the Manager Compensation is now $69.5 million per annum, or 100% of the Base Input, and our concurrent pro rata distribution to the holders of redeemable noncontrolling interests in OpCo was eliminated. As the Company's business and assets expand, the Base Input 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). However, the Base Input will not increase from the issuance of the Company's shares upon the redemption or exchange of OpCo Units, should there be any outstanding in the future. See NOTE 3 – Acquisitions and Divestitures for more information.

In order to pay the Manager Compensation, the Company must first receive a cash distribution from OpCo, and prior to the Corporate Simplification, any such cash distribution necessitated a concurrent pro rata cash distribution 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, not because the distributions to the holders of redeemable noncontrolling interests were made for such purpose (e.g. Cash distributions to redeemable noncontrolling interests initiated by Class A common stock dividend, Cash distributions to redeemable noncontrolling interests initiated by Manager Compensation and Cash contributions from (cash distributions to) redeemable noncontrolling interests initiated by income taxes).

During the three months ended March 31, 2025 and 2024, we recorded general and administrative expense of $13.2 million and $8.2 million, respectively, related to the Manager Compensation and concurrently made cash distributions of $4.5 million and $6.8 million, respectively, to our redeemable noncontrolling interests. At March 31, 2025 we reduced redeemable noncontrolling interest by $4.2 million for the OpCo distribution declaration to redeemable noncontrolling interests that will be paid during the second quarter of 2025. At both March 31, 2025 and December 31, 2024, we had $17.4 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 ("Incentive Compensation") under which the Manager is targeted to receive 10% of our outstanding Class A Common Stock based on the achievement of certain performance-based measures. The Incentive Compensation consists of five tranches that settle over a five-year period beginning in 2024, and each tranche 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. Performance goals are evaluated on absolute stock price performance and relative stock price performance versus a set of our peers and there is no vesting based solely on time. The certification of the Company's level of achievement with respect to the first three-year-performance period under the Incentive Compensation is in process and is expected to be completed in 2025. Based on the level of achievement with respect to the performance goals applicable to such 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 of the outstanding Class A Common Stock at the time each tranche is settled so long as the Manager continuously provides services to us until the end of the performance period applicable to a tranche. During the three months ended March 31, 2025 and 2024, we recorded general and administrative expense of $25.3 million and $27.0 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 monthly 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, 2025 and December 31, 2024, we had a related party receivable of $0.1 million and $4.3 million, respectively, included within Accounts receivable – affiliates and a related party payable of $4.0 million and $1.2 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 including notes offerings, credit facility structuring and equity offerings. 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,
	2025		2024
	(in thousands)
Amounts paid to KCM	$	—	$	1,838

Other Transactions

In March 2024, OpCo repurchased 2.3 million OpCo Units from Independence Energy Aggregator L.P., the entity through which certain private investors in affiliated KKR entities hold their interests in us, for $22.7 million Refer to further discussion in NOTE 1 – Organization and Basis of Presentation. During the three months ended March 31, 2025 and 2024, we made cash distributions of $7.7 million and $8.3 million, respectively, to our redeemable noncontrolling interests related to their pro rata share of cash distributions made to Crescent Energy Company to pay dividends and income taxes. As a result of the Corporate Simplification, our concurrent pro rata distribution to the holders of redeemable noncontrolling interests in OpCo related to dividends and income taxes was eliminated. In addition, during the three months ended March 31, 2025 and 2024, we reimbursed KKR $0.6 million and $1.3 million, respectively, for costs incurred on our behalf. At March 31, 2025 and December 31, 2024 we had $0.7 million accrued within Accounts payable - affiliates for reimbursable costs and distributions to our redeemable noncontrolling interests for their pro rata share of taxes.

Board of Directors

We have a ten-year office lease with an affiliate of Crescent Real Estate LLC. John C. Goff, the Chairman of our Board of Directors, is affiliated with Crescent Real Estate LLC. The terms of the lease provide for annual base rent of $0.4 million increasing to $0.5 million over the life of the agreement.

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. During the three months ended March 31, 2025, we funded $2.0 million to Chama associated with the plugging and abandonment costs.

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 and shares of Class B Common Stock do not have rights to participate in dividends or undistributed earnings. However, shareholders of Class B Common Stock receive pro rata distributions from OpCo through their ownership of OpCo Units. 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 3.2 million and 0.9 million of PSUs and 0.3 million and 0.1 million of RSUs for the three months ended March 31, 2025 and March 31, 2024, respectively, that were not included in the computation of EPS because to do so would have been antidilutive due 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,
	2025		2024
	(in thousands, except share and per share amounts)
Numerator:
Net income (loss)	$	5,911	$	(32,364)

Less: net (income) loss attributable to noncontrolling interests	(1,989)		(3,499)
Less: net (income) loss attributable to redeemable noncontrolling interests	(6,072)		11,695
Net income (loss) attributable to Crescent Energy - basic	(2,150)		(24,168)
Add: Reallocation of net income attributable to redeemable noncontrolling interest for the dilutive effect of RSUs	—		—
Add: Reallocation of net income attributable to redeemable noncontrolling interest for the dilutive effect of PSUs	—		—
Net income (loss) attributable to Crescent Energy - diluted	$	(2,150)	$	(24,168)
Denominator:
Weighted-average Class A Common Stock outstanding - basic	191,293,595		94,793,415
Add: dilutive effect of RSUs	—		—
Add: dilutive effect of PSUs	—		—
Weighted-average Class A Common stock outstanding – diluted	191,293,595		94,793,415
Weighted-average Class B Common stock outstanding – basic and diluted	65,260,089		84,332,739
Net income (loss) per share:
Class A common stock – basic	$	(0.01)	$	(0.25)
Class A common stock – diluted	$	(0.01)	$	(0.25)
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 the exploration and production of crude oil, natural gas and NGLs. 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,
	2025		2024
	(in thousands)
Total revenues	$	950,172	$	657,473
Less:
Lease operating expense	161,595		130,688
Workover expense	16,022		12,302
Asset operating expense	30,410		31,350
Gathering, transportation and marketing	105,287		69,569
Production and other taxes	60,381		32,523
Depreciation, depletion and amortization	282,573		176,564
Impairment of oil and natural gas properties	45,647		—
Midstream and other operating expense	29,816		27,742
General and administrative expense excluding equity-based compensation	30,132		14,541
Equity-based compensation expense	26,638		28,174
Interest expense	73,182		42,686
Other segment items	82,578		123,698
Net income (loss)	$	5,911	$	(32,364)

Total development of oil and natural gas properties	$	207,542	$	193,290

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 5, 2025, 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 2025. The quarterly dividend is payable on June 2, 2025 to shareholders of record as of the close of business on May 19, 2025.

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.

Stock repurchase program

During April 2025, we repurchased 2.9 million shares of our Class A Common Stock for $23.1 million, at an average price of $7.87 per share, under our authorized stock repurchase program. After share repurchases in early April 2025, the remaining amount under the authorized plan is approximately $91.0 million as of April 30, 2025.

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, 2024 ("Annual Report"), as well as our unaudited condensed consolidated financial statements for the three months ended March 31, 2025 and 2024. 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, 2025 and 2024. 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 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, supply chain constraints, elevated interest rates, U.S. international trade and tariff policy developments 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 2025 that has created further volatility. In April 2025, OPEC announced an agreement to phase out oil output cuts by increasing 411,000 barrels per day, starting in May 2025. The actions of OPEC with respect to oil production levels and announcements of potential changes in such levels may result in further volatility in commodity prices and 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, 2025, we recorded an impairment expense of $45.6 million related to oil and natural gas properties. See NOTE 5 – Fair Value Measurements to the unaudited financial statements included in Part I. Item 1. Financial Statements. A further decline of future commodity prices or a decrease in estimates of oil and natural gas reserves for these 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 began increasing in 2021, peaked in the middle of 2022 and began to gradually decline in the second half of 2022 and into 2023 and has remained elevated but relatively stable through 2024 and the first quarter of 2025. 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. Recent tariffs and any further tariffs may also increase our operating costs. Sustained levels of high inflation have likewise caused the U.S. Federal Reserve and other central banks to increase interest rates in 2022, continuing through 2023. The U.S. Federal Reserve made cuts to benchmark interest rates in 2024 and it is currently anticipated that it will make additional cuts; however, there is no guarantee that such additional cuts will occur. Although the financial health of the oil and gas industry has shown improvement as compared to prior periods, to the extent elevated inflation remains, 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 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—Continuing or worsening inflationary issues and associated changes in monetary policy have resulted in and may 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

2025 Equity Transactions

In April 2025, as part of our Corporate Simplification, we acquired 63.0 million OpCo Units in exchange for a corresponding number of shares of Class A Common Stock and cancelled all outstanding shares of Class B Common Stock. As a result, the number of equity-classified Manager PSU target Class A shares related to the award of PSUs granted to the Manager under the Crescent Energy Company 2021 Manager Incentive Plan (referred to herein as the Incentive Compensation) increased by 5.0 million shares and the pro rata relative ownership of OpCo increased the Manager Compensation to approximately $69.5 million per annum, or 100% of the Base Input, and our concurrent pro rata distribution to the holders of redeemable noncontrolling interests was eliminated. For more information on the Incentive Compensation, including the performance-based vesting criteria applicable thereto, see NOTE 11 – Related Party Transactions.

In March 2025, Independence Energy Aggregator L.P., 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 "March 2025 Class A Redemption"). The shares of Class A Common Stock were sold by Independence Energy Aggregator L.P. 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 March 2025 Class A Redemption.

Share repurchase program

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. 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. During 2024, we utilized $30.5 million to repurchase a combination of Class A Common Stock and OpCo units. During 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. During April 2025, we repurchased 2.9 million shares of our Class A Common Stock for $23.1 million, at an average price of $7.87 per share. After share repurchases in early April 2025, the remaining amount under the authorized plan is approximately $91.0 million as of April 30, 2025.

Acquisitions and divestitures

Acquisitions

Ridgemar Acquisition

SilverBow Merger

On July 30, 2024, we consummated the SilverBow Merger. See “—NOTE 3 – Acquisitions and Divestitures. Immediately following the SilverBow Merger, Crescent Energy Company completed a series of internal transactions following which the assets of SilverBow Resources, Inc. ("SilverBow") and its subsidiary became held by subsidiaries of Crescent Energy Finance LLC. In connection with the SilverBow Merger, Crescent issued 51.6 million shares of Class A Common Stock and paid $382.4 million in cash to former SilverBow shareholders, including amounts payable in respect of outstanding SilverBow equity awards. In connection with the closing of the SilverBow Merger, we repaid all of SilverBow’s outstanding indebtedness.

Other Acquisitions

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 cash proceeds and recorded a gain of $10.9 million on the sale of such assets. In addition, in March 2025, we entered into the purchase and sale agreement to sell certain of our non-core assets to an unrelated third-party buyer for $83.0 million in aggregate cash proceeds, subject to customary purchase price adjustments. The transaction closed during the second quarter of 2025.

Stewardship

We seek to strategically improve 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 received Gold Standard pathway ratings in 2022, 2023 and 2024 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 also 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. The sustainability-related information found and/or provided in the Company’s sustainability reports or on the Company’s website in general is 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 2025 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

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,
	2025		2024
Oil	68	%	76	%
Natural gas	20	%	13	%
NGLs	12	%	11	%

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 6% or less of our total revenues for the three months ended March 31, 2025 and 2024.

Production volumes sold

The following table presents historical sales volumes for our properties:


	Three Months Ended March 31,
	2025	2024
Oil (MBbls)	9,161	6,403
Natural gas (MMcf)	58,954	36,704
NGLs (MBbls)	4,230	2,568
Total (MBoe)	23,217	15,088
Daily average (MBoe/d)	258	166

Total sales volume increased 8,129 MBoe during the three months ended March 31, 2025, compared to the three months ended March 31, 2024. The increase for the three months ended March 31, 2025 was primarily due to the SilverBow Merger and the

Ridgemar Acquisition.

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 Russia’s invasion of Ukraine and the associated sanctions imposed on Russia, and the Israel-Hamas conflict and the broader conflict in the Middle East, actions taken by OPEC, sustained elevated inflation, U.S. trade policy and the imposition of tariffs and increased U.S. drilling activity or otherwise. Uncertainty persists regarding OPEC’s actions, increased U.S. drilling, the imposition of increased tariffs and resulting consequences, inflation and the armed conflicts in Ukraine and the Middle East. Additionally, market concern regarding a potential recession, among other factors, contributes 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,
	2025		2024
Oil	59	%	63	%
Natural gas	58	%	40	%
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,
	2025		2024
Oil (Bbl):
Average NYMEX	$	71.42	$	76.96
Realized price (excluding derivative settlements)	67.64		74.01
Realized price (including derivative settlements) (1)	67.17		67.13
Natural Gas (Mcf):
Average NYMEX	$	3.65	$	2.24
Realized price (excluding derivative settlements)	3.18		2.18
Realized price (including derivative settlements) (1)	3.09		2.76
NGLs (Bbl):
Realized price (excluding derivative settlements)	$	25.43	$	26.07
Realized price (including derivative settlements) (1)	25.13		26.07

(1) The realized price presented above 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, 2025 Compared to Three Months Ended March 31, 2024

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,
	2025		2024		$ Change		% Change
Revenues (in thousands):
Oil	$	619,658	$	473,894	$	145,764	31	%
Natural gas	187,440		79,944		107,496		134	%
Natural gas liquids	107,575		66,947		40,628		61	%
Midstream and other	35,499		36,688		(1,189)		(3)	%
Total revenues	$	950,172	$	657,473	$	292,699	45	%
Average realized prices, before effects of derivative settlements:
Oil ($/Bbl)	$	67.64	$	74.01	$	(6.37)	(9)	%
Natural gas ($/Mcf)	3.18		2.18		1.00		46	%
NGLs ($/Bbl)	25.43		26.07		(0.64)		(2)	%
Total ($/Boe)	39.40		41.14		(1.74)		(4)	%
Net sales volumes:
Oil (MBbls)	9,161		6,403		2,758		43	%
Natural gas (MMcf)	58,954		36,704		22,250		61	%
NGLs (MBbls)	4,230		2,568		1,662		65	%
Total (MBoe)	23,217		15,088		8,129		54	%
Average daily net sales volumes:
Oil (MBbls/d)	102		70		32		46	%
Natural gas (MMcf/d)	655		403		252		63	%
NGLs (MBbls/d)	47		28		19		68	%
Total (MBoe/d)	258		166		92		55	%

Oil revenue. Oil revenue increased $145.8 million, or 31%, in the three months ended March 31, 2025, compared to the three months ended March 31, 2024. This was driven by a $204.1 million increase from higher sales volume (32 MBbls/d, or 46%), partially offset by lower realized oil prices that resulted in a decrease of $58.3 million (a decrease of 9% per Bbl). The increase in sales volumes was primarily driven by the SilverBow Merger and the Ridgemar Acquisition. The decrease in realized oil prices was due to lower index prices and higher price differentials.

Natural gas revenue. Natural gas revenue increased $107.5 million, or 134%, in the three months ended March 31, 2025, compared to the three months ended March 31, 2024. This was driven by a $48.5 million increase from higher sales volume (252 MMcf/d, or 63%) and higher natural gas prices that resulted in an increase of $59.0 million (an increase of 46% per Mcf). The increase in sales volumes was primarily due to the SilverBow Merger. The increase in realized natural gas prices was due to higher index prices offset by higher price differentials.

NGL revenue. NGL revenue increased $40.6 million, or 61%, in the three months ended March 31, 2025, compared to the three months ended March 31, 2024. This was driven primarily by a $43.3 million increase from higher sales volume (19 MBbls/d, or 68%), partially offset by lower realized NGL prices that resulted in a decrease of $2.7 million (a decrease of 2% per Bbl). The increase in sales volumes was primarily driven by the SilverBow Merger.

Midstream and other revenue. Midstream and other revenue decreased $1.2 million, or 3%, in the three months ended March 31, 2025, compared to the three months ended March 31, 2024, driven primarily by lower sulfur revenues in 2025, partially offset by higher oil blending revenues.

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,
	2025		2024		$ Change		% Change
Expenses (in thousands):
Operating expense	$	403,511	$	304,174	$	99,337	33	%
Depreciation, depletion and amortization	282,573		176,564		106,009		60	%
Impairment of oil and natural gas properties	45,647		—		45,647		NM*
General and administrative expense	56,770		42,715		14,055		33	%
Other operating costs	(10,556)		—		(10,556)		NM*
Total expenses	$	777,945	$	523,453	$	254,492	49	%
Selected expenses per Boe:
Operating expense	$	17.38	$	20.16	$	(2.78)	(14)	%


Depreciation, depletion and amortization	12.17		11.70		0.47		4	%

* NM = Not meaningful.

Operating expense. Operating expense increased $99.3 million, or 33%, in the three months ended March 31, 2025, compared to the three months ended March 31, 2024, driven primarily by the following factors:

(i)Lease and asset operating expense increased $30.0 million, or 18%, in the three months ended March 31, 2025, compared to the three months ended March 31, 2024, and decreased $2.47 per Boe, or 23%, to $8.27 per Boe. This $30.0 million increase was driven primarily by higher production from the SilverBow Merger and the Ridgemar Acquisition, which was more than offset on a per Boe basis with the additional acquired volumes and cost reduction measures on our other assets.

(ii)Gathering, transportation and marketing expense increased $35.7 million, or 51%, in the three months ended March 31, 2025, compared to the three months ended March 31, 2024, and decreased $0.08 per Boe, or 2%, to $4.53 per Boe. The increase was driven primarily by the SilverBow Merger and the Ridgemar Acquisition, which was more than offset on a per Boe basis with the additional acquired volumes.

(iii)Production and other taxes increased $27.9 million, or 86%, in the three months ended March 31, 2025, compared to the three months ended March 31, 2024, and increased $0.44 per Boe, or 20%, to $2.60 per Boe. This net increase was driven primarily by higher oil and gas revenues, which increased the tax base on which our production and other taxes are calculated.

(iv)Workover expense increased $3.7 million, or 30%, in the three months ended March 31, 2025, compared to the three months ended March 31, 2024, and decreased $0.13 per Boe, or 16%, to $0.69 per Boe. This increase was primarily driven by the SilverBow Merger.

(v)Midstream and other operating expense increased $2.1 million in the three months ended March 31, 2025, compared to the three months ended March 31, 2024, primarily due to increased crude oil blending expense. The additional crude oil blending expense is more than offset by additional oil blending revenue included as part of our Midstream and other revenue.

Depreciation, depletion and amortization. In the three months ended March 31, 2025, depreciation, depletion and amortization increased $106.0 million, or 60%, compared to the three months ended March 31, 2024, driven primarily by increased production from the SilverBow Merger and the Ridgemar Acquisition.

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.

General and administrative expense. General and administrative expense ("G&A") increased $14.1 million, or 33%, for the three months ended March 31, 2025, compared to the three months ended March 31, 2024. The increase was driven by (i) higher recurring G&A due to higher Manager Compensation expense as a result of our equity issuances and share redemptions for our Class A Common Stock, and (ii) $0.7 million higher transaction and nonrecurring related expenses, partially offset by a decrease in equity-based compensation expense of $1.5 million (2025 and 2024 include an additional catch up expense of $8.6 million and $14.1 million, respectively due to change in estimate).


	Three Months Ended March 31,
	2025		2024		$ Change		% Change
General and administrative expense (in thousands):
Recurring general and administrative expense	$	27,812	$	12,917	$	14,895	115	%
Transaction and nonrecurring expenses	2,320		1,624		696		43	%
Equity-based compensation	26,638		28,174		(1,536)		(5)	%
Total general and administrative expense	$	56,770	$	42,715	$	14,055	33	%
General and administrative expense per Boe:
Recurring general and administrative expense	$	1.20	$	0.86	$	0.34	40	%
Transaction and nonrecurring expenses	0.10		0.11		(0.01)		(9)	%
Equity-based compensation	1.15		1.87		(0.72)		(39)	%

Other operating costs. Other operating costs include exploration expense and gain on sale of assets. Other operating costs decreased by $10.6 million, compared to the three months ended March 31, 2024, primarily driven by a $10.9 million higher gain on sale of assets, partially offset by $0.3 million higher exploration expense recognized during the three months ended March 31, 2025.

Interest expense. In the three months ended March 31, 2025, we incurred interest expense of $73.2 million, as compared to $42.7 million in the three months ended March 31, 2024, a 71% increase. This increase was driven primarily by higher average debt balances driven by our Ridgemar Acquisition and the SilverBow Merger.

Loss on extinguishment of debt. During the three months ended March 31, 2025, we did not incur a loss on the extinguishment of debt. During the three months ended March 31, 2024, we incurred a loss on the extinguishment of our 2026 Notes of $22.6 million related to the $14.8 million premium and interest paid for the Tender Offer and Redemption of the 2026 Notes and $7.8 million related to the write-off of outstanding deferred finance costs related to the 2026 Notes.

Gain (loss) on derivatives. We have entered into derivative contracts to manage our exposure to commodity price risks that impact our revenues. Our loss on commodity derivatives during the three months ended March 31, 2025 changed by $14.1 million, or 13%, from a comparable loss during the three months ended March 31, 2024 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, 2025 and March 31, 2024, we recognized income tax expense of $2.6 million and income tax benefit of $4.2 million, respectively, for an effective tax rate of 30.7% and 11.5%, respectively. Our effective tax rate has typically been lower than the U.S. federal statutory income tax rate of 21% primarily due to effects of removing income and losses related to our noncontrolling interests and redeemable noncontrolling interests. Our effective tax rate for the three months ended March 31, 2025 was driven higher primarily due to our increased ownership of OpCo in 2025, temporary timing difference 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,
	2025		2024		$ Change		% Change
(in thousands, except percentages)
Net income (loss)	$	5,911	$	(32,364)	$	38,275	(118)	%
Adjustments to reconcile to Adjusted EBITDAX:
Interest expense	73,182		42,686
Loss from extinguishment of debt	—		22,582
Income tax expense (benefit)	2,613		(4,209)
Depreciation, depletion and amortization	282,573		176,564
Exploration expense	306		—
Non-cash (gain) loss on derivatives	80,230		82,796
Impairment expense	45,647		—
Non-cash equity-based compensation expense	26,225		28,174
(Gain) loss on sale of assets	(10,862)		—
Other (income) expense	(115)		(150)
Certain redeemable noncontrolling interest distributions made by OpCo (1)	(4,242)		(5,627)
Transaction and nonrecurring expenses (2)	10,099		2,871
Settlement of acquired derivative contracts	17,888		—
Adjusted EBITDAX (non-GAAP)	$	529,455	$	313,323	$	216,132	69	%
Adjustments to reconcile to Levered Free Cash Flow:
Interest expense, excluding non-cash amortization of deferred financing costs, discounts, and premiums	(69,429)		(38,310)
Loss from extinguishment of debt, excluding non-cash write-off of deferred financing costs, discounts, premiums and SilverBow Merger transaction related costs	—		(14,817)
Current income tax benefit (expense)	(10,813)		(716)
Tax-related redeemable noncontrolling interest contributions (distributions) made by OpCo	(95)		(66)
Development of oil and natural gas properties	(207,542)		(193,290)
Levered Free Cash Flow (non-GAAP)	$	241,576	$	66,124	$	175,452	265	%

(1)In our calculation of Adjusted EBITDAX and Levered Free Cash Flow, we 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.

(2)Transaction and nonrecurring expenses of $10.1 million for the three months ended March 31, 2025 were primarily related to uncapitalized transaction costs related to the Ridgemar Acquisition and transaction costs related to our divestitures and the SilverBow Merger. Transaction and nonrecurring expenses of $2.9 million for the three months ended March 31, 2024 were primarily related to our capital markets transactions and integration expenses.


	Three Months Ended March 31,
	2025		2024		$ Change		% Change
(in thousands, except percentages)
Net cash provided by operating activities	$	337,114	$	183,770	$	153,344	83	%
Changes in operating assets and liabilities	95,301		87,335

Certain redeemable noncontrolling interest distributions made by OpCo (1)	(4,242)		(5,627)
Tax-related redeemable noncontrolling interest contributions (distributions) made by OpCo	(95)		(66)
Transaction and nonrecurring expenses (2)	10,099		2,871
Loss from extinguishment of debt, excluding non-cash write-off of deferred financing costs, discounts, premiums and SilverBow Merger transaction related costs	—		(14,817)
Other adjustments and operating activities	10,941		5,948
Development of oil and natural gas properties	(207,542)		(193,290)
Levered Free Cash Flow (non-GAAP)	$	241,576	$	66,124	$	175,452	265	%

Adjusted EBITDAX (non-GAAP) increased by $216.1 million, or 69%, in the three months ended March 31, 2025, compared to the three months ended March 31, 2024, primarily driven by additional production generated by the SilverBow Merger and the Ridgemar Acquisition.

Levered Free Cash Flow (non-GAAP) increased by $175.5 million, or 265%, in the three months ended March 31, 2025 compared to the three months ended March 31, 2024, primarily driven by increased Adjusted EBITDAX, partially offset by additional interest expense.

Liquidity and capital resources

Our primary sources of liquidity are cash flow from operations, proceeds from equity and debt offerings and borrowings under a senior secured reserve-based revolving credit agreement (as amended, restated, amended and restated or otherwise modified to date, the “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. Our primary expected uses of capital are for dividends to shareholders, our share repurchase program, debt repayment, 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, 2025		December 31, 2024
	(in thousands)
Cash and cash equivalents	$	6,255	$	132,818
Long-term debt	3,596,870		3,049,255

In connection with the closing of the Ridgemar Acquisition in the first quarter of 2025, we paid in total $812.5 million in cash to former Ridgemar owners after customary purchase price adjustments. We funded the cash to close, less the initial deposit, with cash on hand and borrowings under our Revolving Credit Facility. 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,
	2025		2024
	(in thousands)
Net cash provided by operating activities	$	337,114	$	183,770
Net cash used in investing activities	(1,056,923)		(157,461)
Net cash provided by (used in) financing activities	502,653		(23,867)

Net cash provided by operating activities. Net cash provided by operating activities for the three months ended March 31, 2025 increased by $153.3 million, or 83%, compared to the three months ended March 31, 2024 primarily due to higher net income after adjusting for non-cash items and partially offset by working capital changes.

Net cash used in investing activities. Net cash used in investing activities for the three months ended March 31, 2025 increased by $899.5 million, or a 571%, compared to the three months ended March 31, 2024, primarily due to $845.1 million of additional acquisitions of oil and natural gas properties in 2025 due to the cash consideration for the Ridgemar Acquisition and $62.4 million additional in our cash development capital expenditures.

Net cash provided by financing activities. 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 Class A Common Stock dividend and cash distributions to our redeemable noncontrolling interests. Net cash used in financing activities for the three months ended March 31, 2024 was $23.9 million, driven primarily a result of the repurchase of OpCo Units and our distributions, partially offset by net cash received in our debt transactions and Revolving Credit Facility borrowings.

Debt agreements

Senior Notes

2033 Notes

In June 2024, we issued $750.0 million aggregate principal amount of 7.375% senior notes due 2033 (the "2033 Notes") at par (the "June 2024 Offering"). In September 2024, we issued an additional $250.0 million, aggregate principal amount of 2033 Notes at 101.000% of par (the "September 2024 Offering," and together with the June 2024 Offering, the "2033 Notes Offerings"). The aggregate proceeds from the 2033 Notes Offerings were approximately $981.8 million, after adjusting for premiums, the initial purchasers' discount and offering expenses. We used the aggregate net proceeds from the 2033 Notes Offerings to finance the majority of the SilverBow Merger, including (i) fund the cash paid to the SilverBow stockholders and holders of SilverBow restricted stock units in connection with the SilverBow Merger, (ii) repay and extinguish SilverBow's existing indebtedness that was outstanding at the completion of the SilverBow Merger for $1.2 billion, including

extinguishment costs. In connection with the repayment of SilverBow's debt we incurred a Loss on the extinguishment of debt of $36.5 million, inclusive of make whole fees.

2032 Notes

2028 Notes

The 2028 Notes bear interest at an annual rate of 9.250%, which is payable on February 15 and August 15 of each year and mature on February 15, 2028.

payment with the borrowings under our Revolving Credit Facility and any of our other future senior indebtedness and senior to any of our future subordinated indebtedness. The Senior Notes are guaranteed on a senior unsecured basis by each of our existing and future subsidiaries that will guarantee our Revolving Credit Facility. The Senior Notes and the guarantees are effectively subordinated to all of our secured indebtedness (including all borrowings and other obligations under our Revolving Credit Facility) to the extent of the value of the collateral securing such indebtedness and structurally subordinated in right of payment to all existing and future indebtedness and other liabilities (including trade payables) of any future subsidiaries that do not guarantee the Senior Notes.

Revolving Credit Facility

In connection with the issuance of the 2026 Notes in May 2021, Crescent Energy Finance LLC entered into the Revolving Credit Facility. The Revolving Credit Facility matures on April 10, 2029. At March 31, 2025, our elected commitment amount was approximately $2.0 billion and we had $546.5 million of outstanding borrowings, $19.9 million in outstanding letters of credit and approximately $1.4 billion of availability under the Revolving Credit Facility.

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 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 the unused revolving commitments at March 31, 2025 is 0.375% per year. Our weighted average interest rate on loan amounts outstanding as of March 31, 2025 was 6.34% and we had no borrowings outstanding under the Revolving Credit Facility as of December 31, 2024.

The borrowing base under the Revolving Credit Facility was $2.6 billion as of March 31, 2025 and December 31, 2024.The borrowing base is subject to semi-annual scheduled redeterminations on or about April 1 and October 1 of each year, as well as (i) elective borrowing base interim redeterminations at our request not more than twice during any consecutive 12-month period or the required lenders not more than once during any consecutive 12-month period and (ii) elective borrowing base interim redeterminations at our request following any acquisition of oil and natural gas properties with a purchase price in the aggregate of at least 5.0% of the then effective borrowing base. The borrowing base will be automatically reduced upon (a) the issuance of certain permitted junior lien debt and other permitted additional debt, (b) the sale or other disposition of borrowing base properties if the aggregate net present value, discounted at 9% per annum (“PV-9”) of such properties sold or disposed of is in excess of 5.0% of the borrowing base then in effect and (c) early termination or set-off of swap agreements (x) the administrative agent relied on in determining the borrowing base or (y) if the value of such swap agreements so terminated is in excess of 5.0% of the borrowing base then in effect.

The obligations under the Revolving Credit Facility remain secured by first priority liens on substantially all of our and the guarantors’ tangible and intangible assets, including without limitation, oil and natural gas properties and associated assets and equity interests owned by us and such guarantors. In connection with each redetermination of the borrowing base, we must maintain mortgages on at least 85% of the PV-9 of the oil and gas properties that constitute borrowing base properties. Our domestic direct and indirect subsidiaries are required to be guarantors under the Revolving Credit Facility, subject to certain exceptions.

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. At March 31, 2025, 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.

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 2025 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,
	2025		2024
	(in thousands)
Total development of oil and natural gas properties	$	207,542	$	193,290
Change in accruals or other non-cash adjustments	(8,343)		(56,474)
Cash used in development of oil and natural gas properties	199,199		136,816
Cash used in acquisition of oil and natural gas properties	864,674		19,532
Non-cash acquisition of oil and natural gas properties	82,145		—
Total expenditures on acquisition and development of oil and natural gas properties	$	1,146,018	$	156,348

Our cash used in the development of oil and natural gas properties was higher during the three months ended March 31, 2025, compared to the three months ended March 31, 2024. The increase is related to an increase in our operations and related invoices. We used cash of $864.7 million in the three months ended March 31, 2025 for the acquisition of oil and natural gas properties, primarily related to the Ridgemar Acquisition, as compared to $19.5 million in 2024 for the acquisition of oil and natural gas properties (see Notes to condensed consolidated financial statements, NOTE 3 – Acquisitions and Divestitures in Part I, Item 1. Financial Statements of this Quarterly Report).

Contractual obligations

As of March 31, 2025, 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 indentures governing the Senior Notes.

We paid a quarterly cash dividend of $0.12 per share of our Class A Common Stock on March 26, 2025 to shareholders of record as of the close of business on March 12, 2025.

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 dividend on a quarterly basis.

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, 2024 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, 2025.

Non-GAAP financial measures

Our MD&A includes financial 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 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, 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 include “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.

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 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 and SilverBow Merger transaction related costs, 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, 2025, our derivative portfolio had an aggregate notional value of approximately $3.1 billion, and the fair market value of our commodity derivative contracts was a net liability of $79.1 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, 2025, 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 $214.7 million. If prices decreased by 10%, our derivative position would change by approximately $171.5 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 International Swaps and Derivatives Association (“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 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, 2025, we had $546.5 million of variable rate debt outstanding. Assuming no change in the amount outstanding, the impact on interest expense of a 1% increase or decrease in the average interest rate would be an approximate $1.4 million increase or decrease in interest expense on our variable rate debt outstanding for the three months ended March 31, 2025.

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, 2025. 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, 2025 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 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 35 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.

Tariffs and other trade measures could adversely affect our results of operations, financial position and cash flows.

In April 2025, the U.S. government announced a baseline tariff of 10% on products from all countries and an additional individualized reciprocal tariff on the countries with which the United States has the largest trade deficits. As a result of the new administration's trade policy, tariffs have increased and may continue to increase our material input costs. We may not be able to fully mitigate the impact of these increased costs or pass price increases on to our customers.

The imposition of further tariffs by the United States on a broader range of imports, further retaliatory trade measures taken in response to additional tariffs, or a global recession could increase costs in our supply chain or reduce demand for oil and natural gas, which would adversely affect our results of operations, including potential write-downs of our asset carrying values.

The ultimate impact of these trade measures on our business operations and financial results is uncertain and may be affected by various factors, including whether and when such trade measures are implemented, the timing when such measures may become effective, and the amount, scope, or nature of such trade measures, and our ability to execute strategies to mitigate the negative impacts.

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, 2025.


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)
1/1/2025 - 1/31/2025	—	—	—	$119,454
2/1/2025 - 2/28/2025	—	—	—	$119,454
3/1/2025 - 3/31/2025	501,835	$10.58	501,835	$114,142

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. Repurchases may be of our Class A Common Stock or of OpCo Units (with the cancellation of a corresponding number of shares of our Class B Common Stock). As of March 31, 2025, we had approximately $114.1 million of repurchase authorization under such program remaining. After share repurchases in early April 2025, the remaining amount under the authorized plan is approximately $91.0 million as of April 30, 2025. Such repurchase may be made by Crescent or by OpCo, as applicable, and may be made from time to time in the open market, in a privately negotiated transaction, 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, 2025, 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.

Election of Directors

On May 5, 2025, Mr. Erich Bobinsky provided the Board of Directors (the “Board”) of the Company with notice of his decision to not seek reelection to the Board, effective May 5, 2025. Mr. Bobinsky’s departure was not the result of any disagreement with the Company or any matter relating to the Company’s operations, policies, or practices. Mr. Bobinsky had previously served as a member of the Board of Directors pursuant to the Specified Rights Agreement (as defined below).

On May 5, 2025, Independence Energy Aggregator LP, by a written consent as the sole holder of Series I preferred stock of the Company, elected David C. Rockecharlie, Brandi Kendall, John C. Goff, Claire S. Farley, Robert G. Gwin, Ellis L. “Lon” McCain, Karen J. Simon, Conrad V. Langenhagen, Bevin Brown, Marcus C. Rowland and Michael Duginski 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. Other than Mr. Langenhagen, each director was serving as a director of the Company at the time of election.

A description of the committee membership of our directors is described in Item 10 of the Company’s Annual Report on Form 10-K for the year ended December 31, 2024, filed by the Company on February 26, 2025 (the “Annual Report”). Mr. Langenhagen will replace Mr. Bobinsky as a member of the Audit Committee.

Each non-employee director will continue to receive director compensation under the current director compensation program of the Company, described in Item 11 of the Annual Report. As compensation for his service on the Board, Mr. Langenhagen will

receive the non-employee director compensation generally provided to other non-employee directors for serving on the Board, except that such compensation may be prorated or reduced to some extent to reflect his partial year of service in 2025. Each director has previously entered into the Company’s indemnification agreement for non-executive directors (each an “Indemnification Agreement”), which such agreements have been filed previously as Exhibits 10.10, 10.11, 10.15, 10.16, 10.18, 10.19, 10.20 and 10.21 to the Company’s Current Report on Form 8-K, filed by the Company on December 8, 2021 and Exhibits 10.2 and 10.3 to the Company’s Current Report on Form 8-K, filed by the Company on August 2, 2024. In connection with Mr. Langenhagen’s appointment to the Board, the Company and Mr. Langenhagen entered into a Indemnification Agreement, which is filed as Exhibit 10.2 to this Quarterly Report. The Indemnification Agreements require the Company to indemnify each non-executive director that is party to an Indemnification Agreement to the fullest extent permitted under Delaware law against liability that may arise by reason of his or her service to the Company and to advance expenses incurred as a result of any proceeding against him as to which he could be indemnified.

Certain transactions between the Company and such directors, other than Mr. Langenhagen, required to be disclosed pursuant to Item 404(a) of Regulation S-K are described in Item 13 of the Annual Report and within NOTE 11 – Related Party Transactions to this Quarterly Report. Mr. Langenhagen has no family relationships with any director or executive officer of the Company or any person nominated or chosen by the Company to become a director or executive officer, and the Company is not aware of any transactions involving Mr. Lagenhagen that would require disclosure under Item 404(a) of Regulation S-K.

Mr. Langenhagen was designated for appointment to the Board by PT Independence Energy Holdings LLC (“PT Independence”) pursuant to that certain Specified Rights Agreement, dated as of June 7, 2021, by and among PT Independence and Independence Energy Aggregator GP LLC, a Delaware limited liability company (the “Specified Rights Agreement”). The Specified Rights Agreement grants PT Independence the right to designate two directors to the Board (one of whom must be an independent director), so long as Liberty Mutual Insurance Co. beneficially owns a number of shares of the Company’s common stock equal to at least 33.33% of its initial ownership of shares of Class B common stock. For so long as PT Independence owns at least one share of common stock, PT Independence shall have the right to designate one Director to the Board. Following Mr. Langenhagen’s appointment to the Board, the PT Independence designees to the Board are Mr. Langenhagen and Ms. Bevin Brown.

Mr. Langenhagen, age 58, most recently served as Executive Vice President, Executive Managing Director and Co-Head, Global Alternative Markets at Liberty Mutual Investments, the investment arm of Liberty Mutual Insurance Co. from January 2020 to December 2024. In this position, Mr. Langenhagen oversaw Liberty Mutual Investment’s alternative investments portfolio, which includes real estate, private equity, oil & gas, energy transition and infrastructure, timber & agriculture, direct lending, distressed, and other strategic investments. Mr. Langenhagen joined Liberty Mutual Insurance in 2004, transitioned to Liberty Mutual Investments in 2007 and has held a series of progressively senior roles at the company. Mr. Langenhagen currently serves on the board of The Spotlight Foundation, a charitable organization. Mr. Langenhagen obtained a Bachelor of Science degree in Biomedical/Electrical Engineering from Duke University in 1988 and an MBA from Stanford University in 1997.

Credit Agreement Amendment

On May 2, 2025, Crescent Energy Finance LLC (“Crescent Finance”), a wholly owned subsidiary of the Company, entered into that certain Twelfth Amendment to Credit Agreement (the “Credit Agreement Amendment”), which amended the Company’s existing Credit Agreement, dated as of May 6, 2021 (as amended by the First Amendment to Credit Agreement, dated as of September 24, 2021, the Second Amendment to Credit Agreement, dated as of March 30, 2022, the Third Amendment to Credit Agreement, dated as of March 30, 2022, the Fourth Amendment to Credit Agreement, dated as of September 23, 2022, the Fifth Amendment to Credit Agreement, dated as of July 3, 2023, the Sixth Amendment to Credit Agreement, dated as of December 13, 2023, the Seventh Amendment to Credit Agreement, dated as of April 10, 2024, the Eighth Amendment to Credit Agreement, dated as of May 24, 2024, the Ninth Amendment to Credit Agreement, dated as of June 14, 2024, the Tenth Amendment to Credit Agreement, dated as of July 30, 2024, and the Eleventh Amendment to Credit Agreement, dated as of December 17, 2024, and as further amended, modified, supplemented or restated from time to time, the “Credit Agreement”), by and among Crescent Finance, certain subsidiaries of Crescent Finance, 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 from time to time. Among other things, the Credit Agreement Amendment provides that the incurrence of up to $600.0 million of certain additional indebtedness during the period beginning on May 2, 2025 and ending on the scheduled redetermination date for the October 1, 2025 scheduled borrowing base redetermination will be excluded from the requirement for the borrowing base to be reduced by 0.25x of the principal amount of such new debt incurrences, so long such debt is incurred during such period and does not exceed the $600.0 million aggregate threshold. The borrowing base was maintained at $2.6 billion and the elected commitments were maintained at $2 billion.

The foregoing description of the Credit Agreement Amendment does not purport to be complete and is qualified in its entirety by reference to the text of the Credit Agreement Amendment, a copy of which is filed as Exhibit 10.3 to this Quarterly Report.

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 3 1, 202 5 ).
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 May 6, 2021, among Crescent Energy Finance LLC (f/k/a Independence Energy Finance LLC), the guarantors named therein, and U.S. Bank Trust Company, National Association, as successor to U.S. Bank 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 February 10, 2022).
4.2			First Supplemental Indenture, dated as of January 14, 2022, among Crescent Energy Finance LLC, the guarantors named therein, and U.S. Bank Trust Company, National Association, as successor to U.S. Bank 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 February 10, 2022).
4.3			Second Supplemental Indenture, dated as of February 10, 2022, 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 February 10, 2022).
4.4			Third Supplemental Indenture, dated as of April 1, 2022, 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 Quarterly Report on Form 10-Q filed with the Securities and Exchange Commission on May 10, 2022).
4.5			Fourth Supplemental Indenture, dated as of April 20, 2022, 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 Quarterly Report on Form 10-Q filed with the Securities and Exchange Commission on May 10, 2022).
4.6			Fifth Supplemental Indenture, dated as of October 12, 2022, among Crescent Energy Finance LLC, the guarantors named therein, and U.S. Bank Trust Company, National Association, as trustee (incorporated by reference to Exhibit 4.6 to the Company's Quarterly Report on Form 10-Q, filed with the Securities and Exchange Commission on November 9, 2022).
4.7			Sixth Supplemental Indenture, dated as of March 6, 2023, among Crescent Energy Finance LLC, the guarantors named therein, and U.S. Bank Trust Company, National Association, as trustee (incorporated by reference to Exhibit 4.10 to the Company's Annual Report on Form 10-K filed with the Securities and Exchange Commission on March 7, 2023).
4.8			Indenture, dated as of February 1, 2023, 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 February 1, 2023).
4.9			First Supplemental Indenture, dated as of July 20, 2023, 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 July 21, 2023).


4.10			Second Supplemental Indenture, dated as of September 12, 2023, 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 12, 2023).
4.11			Third Supplemental Indenture, dated as of December 8, 2023, 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 8, 2023).
4.12			Fourth 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 4.14 to the Company's Quarterly Report on Form 10-Q filed with the Securities and Exchange Commission on November 4, 2024).
4.13			Fifth 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 4.15 to the Company's Annual Report on Form 10-K for the year ended December 31, 202 4 filed with the Securities and Exchange Commission on February 26, 2025).
4.14*			Six th 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.
4.15			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).
4.16			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).
4.17			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).
4.18			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).
4.19*			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 .
4.20			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).
4.21			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).
4.22			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).
4.23			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, 202 4 filed with the Securities and Exchange Commission on February 26, 2025).
4.24*			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.
10.1			Registration Rights Agreement, dated as of January 31, 2025, by and between Crescent Energy Company and Ridgemar Energy Operating, LLC. (incorporated by reference to Exhibit 10.1 to the Company's Current Report on Form 8-K, filed with Securities and Exchange Commission on January 31, 2025).
10.2*			Indemnification Agreement , dated May 5, 2025, by and between Crescent Energy Company and Conrad Langenhagen .
10.3*			Twelfth Amendment to Credit Agreement, dated May 2 , 2025, 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 .


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 5, 2025						/s/ David Rockecharlie
						David Rockecharlie
						Chief Executive Officer
						(Principal Executive Officer)

May 5, 2025						/s/ Brandi Kendall
						Brandi Kendall
						Chief Financial Officer
						(Principal Financial Officer)

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Date	Price Target	Rating	Analyst
2/3/2025		Buy	Siebert Williams Shank
10/28/2024		Outperform	Pickering Energy Partners
9/24/2024	$17.00	Outperform	Evercore ISI
9/18/2024	$12.00	Neutral	JP Morgan
8/8/2024	$20.00	Overweight	Wells Fargo
7/18/2024	$16.00	Outperform	Wolfe Research
6/27/2024	$16.00	Overweight	KeyBanc Capital Markets
4/10/2024	$18.00	Buy	Tudor, Pickering, Holt & Co.

SEC Form 10-Q filed by Crescent Energy Company

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