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, 2023

OR

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

For the transition period from            to

Commission file number 001-41132

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) 337-4600

(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, 2023, there were approximately 48,361,601 and 118,645,323 shares of the registrant's Class A and Class B common stock outstanding, respectively.

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	25
Item 3. Quantitative and Qualitative Disclosures About Market Risk	38
Item 4. Controls and Procedures	39
Part II - Other Information
Item 1. Legal Proceedings	41
Item 1A. Risk Factors	41
Item 2. Unregistered Sales of Equity Securities and Use of Proceeds	41
Item 3. Defaults Upon Senior Securities	41
Item 4. Mine Safety Disclosures	41
Item 5. Other Information	41
Item 6. Exhibits	41
Signatures	43

1

GLOSSARY

The following are abbreviations and definitions of certain terms used in this document, which are commonly used in the oil and natural gas industry:

barrel or Bbl — One stock tank barrel, or 42 United States gallons liquid volume.

Boe — One barrel of oil equivalent determined using the ratio of six Mcf of natural gas to one barrel of crude oil or condensate.

Boe/d — Barrels of oil equivalent per day.

Brent — the reference price paid in U.S. dollars for a barrel of light sweet crude oil produced from the Brent field in the UK sector of the North Sea.

Btu — British thermal unit, which is the heat required to raise the temperature of a one-pound mass of water one degree Fahrenheit.

Henry Hub — Henry Hub is the major exchange for pricing natural gas futures on the New York Mercantile Exchange. It is frequently referred to as the Henry Hub index.

MBbls — One thousand Bbls or other liquid hydrocarbons.

MBbl/d — One thousand Bbls or other liquid hydrocarbons per day.

MBoe — One thousand Boe.

MBoe/d — One thousand Boe per day.

Mcf — One thousand cubic feet of natural gas.

Mcf/d — One thousand Mcf per day.

MMBoe — One million Boe.

MMBtu — One million Btus.

MMcf — One million Mcf.

MMcf/d — One million Mcf per day.

NYMEX — The New York Mercantile Exchange.

Proved developed reserves — Proved reserves that can be expected to be recovered through existing wells with existing equipment and operating methods or in which the cost of the required equipment is relatively minor compared with the cost of a new well or through installed extraction equipment and infrastructure operational at the time of the reserves estimate if the extraction is by means not involving a well.

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.

Proved undeveloped reserves — Proved undeveloped reserves are proved reserves that are expected to be recovered from new wells on undrilled acreage or from existing wells where a relatively major expenditure is required for recompletion. The U.S. Securities and Exchange Commission (the “SEC”) provides a complete definition of undeveloped oil and gas reserves in Rule 4-10(a)(31) of Regulation S-K.

Working interest — The operating interest that gives the owner the right to drill, produce and conduct operating activities on the property and a share of production.

WTI — A light crude oil produced in the United States with an American Petroleum Institute gravity of approximately 38-40 and sulfur content of approximately 0.3%.

2

Cautionary Statement Regarding Forward-Looking Statements

The information in this Quarterly Report on Form 10-Q (this "Quarterly Report") contains or incorporates by reference information that includes or is based upon "forward-looking statements" within the meaning of Section 27A of the Securities Act of 1933, as amended (the "Securities Act"), and Section 21E of the Securities Exchange Act of 1934, as amended (the "Exchange Act"). All statements, other than statements of historical facts, included herein concerning, among other things, planned capital expenditures, increases in oil, natural gas and natural gas liquids (“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 identify and select possible acquisition and disposition opportunities;

•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 foreign oil, natural gas and NGL producing countries, including embargoes, continued hostilities in the Middle East 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;

•general economic conditions, including the impact of continued or worsened inflation and associated changes in monetary policy;

•the impact of disruptions in the bank and capital markets, including those related to the unavailability of liquidity to banking and financial services firms;

•the length, scope, and severity of the ongoing coronavirus disease 2019 (“COVID-19”) pandemic, including the effects of related public health concerns and the impact of continued actions taken by governmental authorities and other third parties in response to the pandemic and its impact on 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;

•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, including the Mesquite Acquisition (as defined herein);

•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, including as a result of the recent change in presidential administrations;

3

•federal and state regulations and laws, including the IRA 2022 (as defined herein);

•our ability to predict and manage the effects of actions of the Organization of the Petroleum Exporting Countries (“OPEC”) and agreements to set and maintain production levels, including as a result of recent production cuts by OPEC;

•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, the uncertainty inherent in estimating reserves and in projecting future rates of production, cash flow and access to capital, 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, 2022 ("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.

4

Part I – Financial Information

Item 1. Financial Statements 

CRESCENT ENERGY COMPANY
CONDENSED CONSOLIDATED BALANCE SHEETS
(Unaudited)
(in thousands, except share data)
	March 31, 2023		December 31, 2022
ASSETS
Current assets:
Cash and cash equivalents	$	2,930	$	—
Accounts receivable, net	467,592		457,071
Accounts receivable – affiliates	2,771		2,681
Derivative assets - current	19,460		14,878
Drilling advances	10,541		14,655
Prepaid and other current assets	36,747		27,454
Total current assets	540,041		516,739
Property, plant and equipment:
Oil and natural gas properties at cost, successful efforts method
Proved	7,308,862		7,113,819
Unproved	307,925		314,255
Oil and natural gas properties at cost, successful efforts method	7,616,787		7,428,074
Field and other property and equipment, at cost	191,531		176,831
Total property, plant and equipment	7,808,318		7,604,905
Less: accumulated depreciation, depletion, amortization and impairment	(2,303,470)		(2,167,135)
Property, plant and equipment, net	5,504,848		5,437,770
Derivative assets – noncurrent	8,548		—
Investment in equity affiliates	12,602		15,038
Other assets	45,670		50,302
TOTAL ASSETS	$	6,111,709	$	6,019,849
The accompanying notes to financial statements are an integral part of these condensed consolidated financial statements

5

CRESCENT ENERGY COMPANY
CONDENSED CONSOLIDATED BALANCE SHEETS
(Unaudited)
(in thousands, except share data)
	March 31, 2023		December 31, 2022
LIABILITIES, REDEEMABLE NONCONTROLLING INTERESTS AND EQUITY
Current liabilities:
Accounts payable and accrued liabilities	$	566,156	$	524,690
Accounts payable – affiliates	39,513		27,652
Derivative liabilities – current	154,149		312,975
Financing lease obligations – current	3,543		3,341
Other current liabilities	22,755		25,091
Total current liabilities	786,116		893,749
Long-term debt	1,244,587		1,247,558
Derivative liabilities – noncurrent	19,578		63,737
Asset retirement obligations	353,674		346,868
Deferred tax liability	163,196		147,348
Financing lease obligations – noncurrent	7,149		7,412
Other liabilities	13,763		14,183
Total liabilities	2,588,063		2,720,855
Commitments and contingencies (Note 9)
Redeemable noncontrolling interests	2,607,169		2,436,703
Equity:
Class A common stock, $0.0001 par value; 1,000,000,000 shares authorized, 49,433,154 shares issued, and 48,282,163 shares outstanding as of March 31, 2023 and December 31, 2022	5		5
Class B common stock, $0.0001 par value; 500,000,000 shares authorized and 118,645,323 shares issued and outstanding as of March 31, 2023 and December 31, 2022	12		12
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, 2023 and December 31, 2022	—		—
Treasury stock, at cost; 1,150,991 shares of Class A common stock as of March 31, 2023 and December 31, 2022	(18,448)		(18,448)
Additional paid-in capital	806,399		804,587
Retained earnings (accumulated deficit)	113,543		61,957
Noncontrolling interests	14,966		14,178
Total equity	916,477		862,291
TOTAL LIABILITIES, REDEEMABLE NONCONTROLLING INTERESTS AND EQUITY	$	6,111,709	$	6,019,849

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

6

CRESCENT ENERGY COMPANY

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS

(Unaudited)

(in thousands, except per share amounts)

	Three Months Ended March 31,
	2023		2022
Revenues:
Oil	$	372,336	$	372,509
Natural gas	162,021		143,311
Natural gas liquids	42,523		71,179
Midstream and other	13,257		11,911
Total revenues	590,137		598,910
Expenses:
Lease operating expense	130,954		94,823
Workover expense	12,571		9,959
Asset operating expense	22,218		16,619
Gathering, transportation and marketing	47,403		48,276
Production and other taxes	54,923		46,484
Depreciation, depletion and amortization	146,483		99,019
Exploration expense	—		91
Midstream operating expense	3,779		3,078
General and administrative expense	21,238		22,522
(Gain) loss on sale of assets	—		(4,790)
Total expenses	439,569		336,081
Income (loss) from operations	150,568		262,829
Other income (expense):
Gain (loss) on derivatives	150,310		(673,486)
Interest expense	(29,320)		(16,524)
Other income (expense)	250		(1,499)
Income (loss) from equity affiliates	163		948
Total other income (expense)	121,403		(690,561)
Income (loss) before taxes	271,971		(427,732)
Income tax benefit (expense)	(16,360)		21,725
Net income (loss)	255,611		(406,007)
Less: net (income) loss attributable to noncontrolling interests	(149)		(470)
Less: net (income) loss attributable to redeemable noncontrolling interests	(195,668)		321,477
Net income (loss) attributable to Crescent Energy	$	59,794	$	(85,000)
Net income (loss) per share:
Class A common stock – basic	$	1.24	$	(2.03)
Class A common stock – diluted	$	1.24	$	(2.03)
Class B common stock – basic and diluted	$	—	$	—
Weighted average shares outstanding:
Class A common stock – basic	48,282		41,954
Class A common stock - diluted	48,665		41,954
Class B common stock – basic and diluted	118,645		127,536

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

7

CRESCENT ENERGY COMPANY
CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY
(Unaudited)
(in thousands)
	Crescent Energy Company
	Class A Common Stock			Class B Common Stock			Series I Preferred Stock			Treasury Stock			Additional Paid-in Capital		Retained Earnings (Accumulated Deficit)		Noncontrolling Interest		Total
	Shares	Amount		Shares	Amount		Shares	Amount		Shares	Amount
Balance at January 1, 2022	41,954	$	4	127,536	$	13	1	$	—	1,151	$	(18,448)	$	720,016	$	(19,376)	$	12,435	$	694,644
Net income (loss)	—	—		—	—		—	—		—	—		—		(85,000)		470		(84,530)
Contributions	—	—		—	—		—	—		—	—		—		—		1,533		1,533
Distributions	—	—		—	—		—	—		—	—		—		—		(645)		(645)
Dividend to Class A common stock	—	—		—	—		—	—		—	—		(5,035)		—		—		(5,035)
Equity-based compensation	—	—		—	—		—	—		—	—		964		—		(192)		772
Change in deferred taxes related to basis in OpCo (see Note 2)	—	—		—	—		—	—		—	—		20,216		—		—		20,216
Adjustment of redeemable noncontrolling interests to redemption amount (see Note 2)	—	—		—	—		—	—		—	—		(194,980)		—		—		(194,980)
Balance at March 31, 2022	41,954	$	4	127,536	$	13	1	$	—	1,151	$	(18,448)	$	541,181	$	(104,376)	$	13,601	$	431,975
Balance at January 1, 2023	48,282	$	5	118,645	$	12	1	$	—	1,151	$	(18,448)	$	804,587	$	61,957	$	14,178	$	862,291
Net income (loss)	—	—		—	—		—	—		—	—		—		59,794		149		59,943
Contributions	—	—		—	—		—	—		—	—		—		—		3		3
Distributions	—	—		—	—		—	—		—	—		—		—		(917)		(917)
Dividend to Class A common stock	—	—		—	—		—	—		—	—		—		(8,208)		—		(8,208)
Equity based compensation	—	—		—	—		—	—		—	—		1,812		—		1,553		3,365
Balance at March 31, 2023	48,282	$	5	118,645	$	12	1	$	—	1,151	$	(18,448)	$	806,399	$	113,543	$	14,966	$	916,477

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

8

CRESCENT ENERGY COMPANY

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)

(in thousands)

	Three Months Ended March 31,
	2023		2022
Cash flows from operating activities:
Net income (loss)	$	255,611	$	(406,007)
Adjustments to reconcile net income (loss) to net cash provided by operating activities
Depreciation, depletion and amortization	146,483		99,019
Deferred income tax expense (benefit)	15,848		(26,675)
(Gain) loss on derivatives	(150,310)		673,486
Net cash (paid) received on settlement of derivatives	(47,157)		(175,801)
Non-cash equity-based compensation expense	7,605		11,115
Amortization of debt issuance costs and discount	1,050		1,597
(Gain) loss on sale of oil and natural gas properties	—		(4,790)
Restructuring of acquired derivative contracts	—		(51,994)
Settlement of acquired derivative contracts	(18,647)		—
Other	(5,125)		(2,781)
Changes in operating assets and liabilities:
Accounts receivable	(8,952)		(179,180)
Accounts receivable – affiliates	(90)		15,206
Prepaid and other current assets	(4,586)		(14,469)
Accounts payable and accrued liabilities	34,681		174,512
Accounts payable – affiliates	11,861		23,611
Other	1,818		442
Net cash provided by operating activities	240,090		137,291
Cash flows from investing activities:
Development of oil and natural gas properties	(190,478)		(93,816)
Acquisitions of oil and natural gas properties	(11,353)		(620,342)
Proceeds from the sale of oil and natural gas properties	4,890		764
Purchases of restricted investment securities – HTM	(1,780)		(1,800)
Maturities of restricted investment securities – HTM	1,800		1,800
Other	1,808		—
Net cash used in investing activities	(195,113)		(713,394)
Cash flows from financing activities:
Proceeds from the issuance of Senior Notes, after premium, discount and underwriting fees	394,000		199,250
Revolving Credit Facility borrowings	218,000		771,000
Revolving Credit Facility repayments	(613,400)		(373,000)
Payment of debt issuance costs	(2,621)		(13,081)
Dividend to Class A common stock	(8,208)		(5,035)
Distributions to redeemable noncontrolling interests related to Class A common stock dividend	(20,171)		(15,323)
Distributions to redeemable noncontrolling interests related to Manager Compensation	(9,471)		(2,726)
Distributions to redeemable noncontrolling interests related to income taxes	(54)		—
Noncontrolling interest distributions	(924)		(645)
Noncontrolling interest contributions	3		1,533
Other	(826)		(456)
Net cash (used in) provided by financing activities	(43,672)		561,517
Net change in cash, cash equivalents and restricted cash	1,305		(14,586)
Cash, cash equivalents and restricted cash, beginning of period	15,304		135,117
Cash, cash equivalents and restricted cash, end of period	$	16,609	$	120,531

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

9

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

We are a well-capitalized U.S. independent energy company with a portfolio of assets in key proven basins across the lower 48 states with substantial cash flow supported by a predictable base of production. We seek to deliver attractive risk-adjusted investment returns and predictable cash flows across cycles by employing our differentiated approach to investing in the oil and gas industry. Our approach employs a unique business model that combines an investor mindset and deep operational expertise to pursue a cash flow-based investment mandate focused on operated working interests with an active risk management strategy. We pursue our strategy through the production, development and acquisition of crude oil, natural gas and NGL reserves. We maintain a diverse portfolio of assets in key proven regions across the United States, focused in Texas and the Rockies.

Corporate Structure

Our Class A Common Stock is listed on the New York Stock Exchange under the symbol “CRGY.” We are structured as an “Up-C,” with substantially all of our assets and operations held by Crescent Energy OpCo LLC ("OpCo"). Crescent is a holding company, the sole material asset of which consists of units representing limited liability interests in OpCo ("OpCo Units"). Shares of Crescent Class A common stock ("Class A Common Stock") have both voting and economic rights, while holders of Crescent Class B common stock ("Class B Common Stock") have voting (but no economic) rights and hold a corresponding amount of economic, non-voting OpCo Units. OpCo Units may be redeemed or exchanged 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”).

At March 31, 2023, shares of our Class A Common Stock represented approximately 29% of the outstanding shares of Class A Common Stock and Class B Common Stock, taken together, and we owned approximately 29% of the outstanding OpCo Units. 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, which entitles the holder thereof to appoint the Board of Directors of Crescent and to certain other approval rights.

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 condensed consolidated financial statements should be read in conjunction with the audited combined and 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 at March 31, 2023 is owned approximately 29% by Crescent and approximately 71% 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.

10

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 and valuation of derivative instruments.

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 pay for the future abandonment of certain wells in California. Restricted cash is included in Prepaid and 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 the statements of cash flows:

	As of March 31,
	2023		2022
	(in thousands)
Cash and cash equivalents	$	2,930	$	112,548
Restricted cash – current	8,631		—
Restricted cash – noncurrent	5,048		7,983
Total cash, cash equivalents and restricted cash	$	16,609	$	120,531

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, together with a corresponding number of shares of Class B Common Stock, for either (a) shares of Class A Common Stock or (b) an approximately equivalent amount of cash as determined pursuant to the terms of the OpCo LLC Agreement, at the election of the Company. In connection with the exercise of such redemption, a corresponding number of shares of Class B Common Stock will be cancelled. The 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 interest is recorded at the greater of the carrying value or redemption amount with a corresponding adjustment to additional paid-in capital. The redemption amount 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.

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From December 31, 2022 through March 31, 2023, we recorded adjustments to the value of our redeemable noncontrolling interests as shown below:

	Redeemable Noncontrolling Interests
	(in thousands)
Balance as of December 31, 2022	$	2,436,703
Net income attributable to redeemable noncontrolling interests	195,668
Distributions from OpCo related to Class A common stock dividend, Manager compensation and income taxes	(20,183)
Accrued OpCo distribution	(9,471)
Equity-based compensation	4,452
Balance as of March 31, 2023	$	2,607,169

Income Taxes

Crescent is a holding company of which our sole material assets are 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, 2023 and March 31, 2022, we recognized income tax expense of $16.4 million and income tax benefit of $21.7 million for an effective tax rate of 6.0% and 5.1%, respectively. Our effective tax rate is 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.

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 federal net operating losses ("NOLs") and recognized built-in-loss ("RBIL") property which are subject to Section 382 limitation. Pursuant to Sections 382 and 383 of the Internal Revenue Code, utilization of our NOLs and RBIL carryforwards is subject to a small annual limitation. These annual limitations may result in the expiration of NOLs and RBIL carryforwards prior to utilization and accordingly we have maintained a valuation allowance related to federal NOLs and RBIL carryforwards that we do not believe are recoverable due these Section 382 limitations.

As of March 31, 2023 and December 31, 2022, we did not have any uncertain tax positions.

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Supplemental Cash Flow Disclosures

The following table presents our supplemental cash flow disclosures for the three months ended March 31, 2023 and 2022:

	Three Months Ended March 31,
	2023		2022
	(in thousands)
Supplemental cash flow disclosures:
Interest paid, net of amounts capitalized	$	7,447	$	3,650
Income tax (refunds) payments	20		(7)
Non-cash investing and financing activities:
Capital expenditures included in accounts payable and accrued liabilities	$	88,540	$	47,569
Debt issuance costs included in accounts payable – affiliates	—		1,500
Right-of-use assets obtained in exchange for leases	2,485		542

NOTE 3 – Acquisitions and Divestitures

Uinta Transaction

In March 2022, we consummated the acquisition contemplated by the Membership Interest Purchase Agreement dated February 15, 2022 (the transactions contemplated therein, the “Uinta Transaction”) between certain of our subsidiaries, including OpCo, and Verdun Oil Company II LLC, a Delaware limited liability company, pursuant to which we purchased all of the issued and outstanding membership interests of Uinta AssetCo, LLC, a Texas limited liability company that holds all development and production assets of, and certain obligations formerly held by EP Energy E&P Company, L.P. located in the State of Utah. Upon closing of the Uinta Transaction, we paid $621.3 million in cash consideration and transaction fees and assumed certain commodity derivatives. The Uinta Transaction was funded with cash on hand and borrowings under our Revolving Credit Facility (as defined in NOTE 7 – Debt). Subsequent to closing the Uinta Transaction, we recorded $11.1 million in customary purchase price adjustments that increased our total purchase price to $632.4 million during the year ended December 31, 2022. We accounted for the Uinta Transaction as an asset acquisition and recorded an additional $863.6 million of property, plant and equipment, net of acquired commodity derivative liabilities of $179.7 million, accounts payable of $14.3 million and asset retirement liability of $37.2 million. In connection with the closing of the Uinta Transaction, we entered into an amendment to our Revolving Credit Facility to, among other things, increase the borrowing base to $1.8 billion and the elected commitment amount to $1.3 billion (see NOTE 7 – Debt). We incurred financing costs of $13.4 million associated with this amendment, which are recorded as debt issuance costs within Other assets on the condensed consolidated balance sheets.

Subsequent to the closing of the Uinta Transaction, we settled certain acquired oil commodity derivative positions and entered into new commodity derivative contracts for 2022 with a swap price of $75 per barrel for a net cost of $54.1 million, including restructuring fees, during the three months ended March 31, 2022.

Equity Method Investment

In April 2022, our equity method investment, Exaro Energy III, LLC ("Exaro"), entered into a purchase and sale agreement to sell its operations in the Jonah Field in Wyoming. During the year ended December 31, 2022, we received a distribution of $6.8 million primarily as a result of the sale.

Chama

In February 2022, we contributed all of the assets and prospects in the Gulf of Mexico formerly owned by one of our subsidiaries to Chama Energy LLC ("Chama") in exchange for a 9.4% interest in Chama, which interest was valued at $3.8 million. As a result, we derecognized the assets and liabilities that were contributed to Chama from our condensed consolidated balance sheets and recorded an equity method investment for our interest in Chama, as well as a $4.5 million gain related to the deconsolidation of these assets and liabilities. John Goff, the Chairman of our Board of Directors, holds an approximate interest of 17.5% in Chama, and the remaining interests are held by other non-affiliated investors. Pursuant to the Limited Liability Company Agreement of Chama, we may be required to fund certain workover costs, and we will be required to fund plugging and abandonment costs related to the producing assets we contributed to Chama.

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Permian Basin Divestiture

On November 4, 2022, we entered into a definitive purchase and sale agreement with an unaffiliated third party to sell certain of our non-core producing properties and related oil and natural gas leases in Ector County, Texas in the Permian Basin in exchange for cash consideration, subject to customary purchase price adjustments, of $80.0 million. We consummated this transaction in December 2022 and recorded a loss of $0.9 million.

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 consists of either a single derivative instrument or a combination of instruments to manage our exposure to these risks.

As of March 31, 2023, our commodity derivative instruments consisted of fixed price 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 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.

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The following table details our net volume positions by commodity as of March 31, 2023:

Production Period	Volumes	Weighted Average Fixed Price			Fair Value
Crude oil swaps (Bbls):	(in thousands)				(in thousands)
WTI
2023	6,863	$60.20			$	(96,745)
2024	5,721	$63.82			(37,791)
Brent
2023	397	$52.52			(10,071)
2024	276	$68.65			(1,753)
Crude oil collars – WTI (Bbls):
2023	2,215	$55.62	-	$73.83	(15,611)
Natural gas swaps (MMBtu):
2023	44,509	$2.78			2,789
2024	9,604	$4.14			4,594
NGL swaps (Bbls):
2023	678	$40.77			8,850
Crude oil basis swaps (Bbls):
2023	2,291	$1.33			94
2024	914	$1.59			60
Natural gas basis swaps (MMBtu):
2023	17,529	$(0.32)			(1,357)
Calendar Month Average ("CMA") roll swaps (Bbls):
2023	2,429	$0.09			(644)
2024	915	$0.31			(126)
Natural gas collars (MMBtu):
2023	18,300	$3.38	-	$4.56	1,992
Total					$	(145,719)

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We use derivative commodity instruments and enter into swap contracts that are governed by International Swaps and Derivatives Association master agreements. The following table shows the effects of master netting arrangements on the fair value of our derivative contracts as of March 31, 2023 and December 31, 2022:

	Gross Fair Value		Effect of Counterparty Netting		Net Carrying Value
	(in thousands)
March 31, 2023
Assets:
Derivative assets – current	$	33,544	$	(14,084)	$	19,460
Derivative assets – noncurrent	16,044		(7,496)		8,548
Total assets	$	49,588	$	(21,580)	$	28,008
Liabilities:
Derivative liabilities – current	$	(168,233)	$	14,084	$	(154,149)
Derivative liabilities – noncurrent	(27,074)		7,496		(19,578)
Total liabilities	$	(195,307)	$	21,580	$	(173,727)
December 31, 2022
Assets:
Derivative assets – current	$	21,880	$	(7,002)	$	14,878
Derivative assets – noncurrent	10,338		(10,338)		—
Total assets	$	32,218	$	(17,340)	$	14,878
Liabilities:
Derivative liabilities – current	$	(319,977)	$	7,002	$	(312,975)
Derivative liabilities – noncurrent	(74,075)		10,338		(63,737)
Total liabilities	$	(394,052)	$	17,340	$	(376,712)

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, 2023 and 2022:

	Three Months Ended March 31,
	2023		2022
	(in thousands)
Derivatives not designated as hedging instruments:
Realized gain (loss) on oil positions	$	(38,105)	$	(100,091)
Realized gain (loss) on natural gas positions	(16,536)		(49,845)
Realized gain (loss) on NGL positions	7,484		(25,865)
Total realized gain (loss) on derivatives	(47,157)		(175,801)
Unrealized gain (loss) on commodity hedges	197,467		(497,685)
Gain (loss) on derivatives	$	150,310	$	(673,486)

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NOTE 5 – Fair Value Measurements

GAAP defines fair value as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date (exit price). Generally, the determination of fair value requires the use of significant judgment and different approaches and models under varying circumstances. Under a market-based approach, we consider prices of similar assets, consult with brokers and experts or employ other valuation techniques. Under an income-based approach, we generally estimate future cash flows and then discount them at a risk-adjusted rate. We classify the inputs used to measure the fair value of our financial assets and liabilities into the following hierarchy:

Level 1: Quoted prices (unadjusted) in active markets for identical assets or liabilities as of the reporting date. Active markets are those in which transactions for the asset or liability occur in sufficient frequency and volume to provide pricing information on an ongoing basis.

Level 2: Quoted market prices for similar assets or liabilities in active markets, quoted prices for identical or similar assets and liabilities in markets that are not active or other than quoted prices that are observable, either directly or indirectly, and can be corroborated by observable market data.

Level 3: Unobservable inputs that reflect management’s best estimates and assumptions of what market participants would use in measuring the fair value of an asset or liability.

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

Recurring Fair Value Measurements

The following table presents the fair value of our derivative assets and liabilities that were accounted for at fair value on a recurring basis as of March 31, 2023 and December 31, 2022 by level within the fair value hierarchy:

	Fair Value Measurement Using
	Level 1		Level 2		Level 3		Total
	(in thousands)
March 31, 2023
Financial assets:
Derivative assets	$	—	$	49,588	$	—	$	49,588
Financial liabilities:
Derivative liabilities	$	—	$	(195,307)	$	—	$	(195,307)
December 31, 2022
Financial assets:
Derivative assets	$	—	$	32,218	$	—	$	32,218
Financial liabilities:
Derivative liabilities	$	—	$	(394,052)	$	—	$	(394,052)

Non-Recurring Fair Value Measurements

Certain nonfinancial assets and liabilities are measured at fair value on a non-recurring basis. We utilize fair value measurement on a non-recurring basis to value our oil and natural gas properties when the carrying value of such property exceeds the respective undiscounted future cash flows. The inputs used to determine such fair value are primarily based upon internally developed cash flow models, as well as market-based valuations and are classified within Level 3. Significant Level 3 assumptions associated with discounted cash flows include estimates of future prices, production costs, development expenditures, anticipated production, appropriate risk-adjusted discount rates, and other relevant data.

Our other non-recurring fair value measurements include the estimates of the fair value of assets and liabilities acquired through business combinations. 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

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assumptions. Net derivative liabilities assumed in acquisitions are valued based on Level 2 inputs similar to the Company's other commodity price derivatives.

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 below) as of March 31, 2023 and December 31, 2022 was approximately $1,044.4 million and $661.5 million based on quoted market prices.

NOTE 6 – Accounts Payable and Accrued Liabilities

Accounts payable and accrued liabilities consisted of the following as of March 31, 2023 and December 31, 2022: 

	March 31, 2023		December 31, 2022
	(in thousands)
Accounts payable and accrued liabilities:
Accounts payable	$	93,110	$	104,343
Accrued lease and asset operating expense	53,834		58,375
Accrued capital expenditures	70,571		76,246
Accrued general and administrative expense	20,044		13,688
Accrued transportation expense	52,181		31,525
Accrued revenue and royalties payable	193,207		160,775
Accrued interest expense	30,996		11,672
Accrued severance taxes	37,742		55,496
Other	14,471		12,570
Total accounts payable and accrued liabilities	$	566,156	$	524,690

NOTE 7 – Debt

Senior Notes

In February 2023, we issued $400.0 million aggregate principal amount of 9.250% senior notes due 2028 (the "2028 Notes") at par. The proceeds of the offering were approximately $391.3 million, after deducting the initial purchasers' discount and offering expenses. We used the proceeds therefrom to repay a portion of our outstanding balance under our Revolving Credit Facility (as defined herein). 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.

We may, at our option, redeem all or a portion of the 2028 Notes at any time on or after February 15, 2025 at certain redemption prices. In addition, prior to February 15, 2025, we may redeem some or all of the 2028 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.

In May 2021, we issued $500.0 million aggregate principal amount of 7.250% senior notes due 2026 (the "Original 2026 Notes") at par. In February 2022, we issued an additional $200.0 million aggregate principal amount of 7.250% senior notes due 2026 at 101% of par (the "Additional 2026 Notes" and, together with the Original 2026 Notes, the "2026 Notes"). Both issuances of the 2026 Notes are treated as a single series, will vote together as a single class, and have identical terms and conditions, other than the issue date, the issue price and the first interest payment. The 2026 Notes bear interest at an annual rate of 7.25%, which is payable on May 1 and November 1 of each year and mature on May 1, 2026.

We may, at our option, redeem all or a portion of the 2026 Notes at any time on or after May 1, 2023 at certain redemption prices.

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The 2026 Notes and the 2028 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. From time to time, we have entered into amendments to the Revolving Credit Facility, which have (i) increased our elected commitment amount from $700.0 million to $1.3 billion, (ii) increased our borrowing base from $1.3 billion to $2.0 billion, (iii) increased our maximum credit amount from $1.5 billion to $3.0 billion, (iv) extended the maturity date from May 6, 2025 to September 23, 2027 and (v) reduced the applicable margin by 0.50% so that loans under the Revolving Credit Facility will be priced based on SOFR (as defined herein) plus 2.35% to 3.35% or an adjusted base rate plus 1.25% to 2.25%, in each case, based on utilization of the Revolving Credit Facility. Our Revolving Credit Facility contains terms that if certain conditions regarding our outstanding Senior Notes exist in January 2026, it will mature in January 2026 prior to the extended maturity date. At March 31, 2023, we had $164.0 million of borrowings and $9.7 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)

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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 is 0.5% per year and is included within interest expense on our condensed consolidated statements of operations. Our weighted average interest rate on loan amounts outstanding as of March 31, 2023 and December 31, 2022 was 7.17% and 6.98%, respectively.

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, 2023 and December 31, 2022, we had letters of credit outstanding of $9.7 million and $9.8 million, 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, 2023 and December 31, 2022:

	Debt Outstanding		Letters of Credit Issued		Borrowing Base		Maturity
	(in thousands)
March 31, 2023
Revolving Credit Facility	$	164,049	$	9,719	$	2,000,000	9/23/2027
7.250% Senior Notes due 2026	700,000		—		—		5/1/2026
9.250% Senior Notes due 2028	400,000		—		—		2/15/2028
Less: Unamortized discount and issuance costs	(19,462)
Total long-term debt	$	1,244,587
December 31, 2022
Revolving Credit Facility	$	559,449	$	9,770	$	2,000,000	9/23/2027
7.250% Senior Notes due 2026	700,000		—		—		5/1/2026
Less: Unamortized discount and issuance costs	(11,891)
Total long-term debt	$	1,247,558

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NOTE 8 – Asset Retirement Obligations

Our ARO liabilities are based on our net ownership in wells and facilities and management’s estimate of the costs to abandon and remediate those wells and facilities together with management’s estimate of the future timing of the costs to be incurred. The following table summarizes activity related to our ARO liabilities for the three months ended March 31, 2023:

	Three Months Ended March 31, 2023
	(in thousands)
Balance at beginning of period	$	365,614
Additions	289
Retirements	(1,626)
Accretion expense	6,640
Balance at end of period	370,917
Less: current portion	(17,243)
Balance at end of period, noncurrent portion	$	353,674

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 or 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 laws and regulations. Accordingly, no liability or loss associated with environmental remediation was recognized as of March 31, 2023.

On February 14, 2022, the New Mexico Energy, Minerals and Natural Resources Department’s Oil Conservation Division(“OCD”) issued a Notice of Violation to us for failure to file form C-115 according to required deadlines and having too many inactive wells. OCD proposed a civil penalty of $0.9 million, the plugging and abandonment of certain inactive wells, and the imposition of certain other restrictions on our operations. The parties discussed a resolution to the matter and

on November 16, 2022, the OCD entered into a Stipulated Final Order (the “Order”) with us pursuant to which we agreed to pay a civil penalty of $0.1 million, the OCD withdrew the allegation of exceeding the number of inactive wells permitted and we agreed to pay a penalty of $500 for each day for each late or missing C-115 report from May 1, 2022 to April 30, 2023. As of March 31, 2023, we have filed no later or missing C-115 reports and are in full compliance with the Order.

NOTE 10 – Incentive Compensation Arrangements

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, and non-employee directors. Our incentive compensation awards may contain certain service-based, performance-based, and market-based vesting conditions. The following table summarizes compensation expense we recognized in connection with our incentive compensation awards for the periods indicated:

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	Three Months Ended March 31,
	2023		2022
	(in thousands)
Recognized in expense (income):
ASC 718 liability-classified profits interest awards	(212)		7,220
ASC 718 equity-classified profits interest awards	1,553		—
ASC 718 equity-classified RSU awards	391		—
ASC 718 equity-classified PSU awards	5,873		3,895
Total expense (income)	$	7,605	$	11,115

2023 Grant Activity

We did not grant any incentive compensation awards during the three months ended March 31, 2023.

In April 2023, we granted 140,856 equity-classified RSUs under the Crescent Energy Company 2021 Equity Incentive Plan to certain directors, officers and employees. Each RSU represents the contingent right to receive one share of Class A Common Stock. The grant date fair value was $11.31 per RSU, and the 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 the condensed consolidated balance sheets.

NOTE 11 – Related Party Transactions

KKR Group

Management Agreement

We have entered into 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 its senior executive management team and certain management services. The Management Agreement has an initial term of three years and shall renew automatically at the end of the initial term for an additional three-year period unless the Company or the Manager elects not to renew the Management Agreement.

As consideration for the services rendered pursuant to the Management Agreement and the Manager’s overhead, including compensation of the executive management team, the Manager is entitled to receive compensation ("Manager Compensation") on a quarterly basis equal to our pro rata share (based on our relative ownership of OpCo) of $53.3 million. This amount will increase over time as our ownership percentage of OpCo increases. In addition, as our business and assets expand, Manager Compensation may increase by an amount equal to 1.5% per annum of the net proceeds from all future issuances of our equity securities (including in connection with acquisitions). However, incremental Manager Compensation will not apply to the issuance of our shares upon the redemption or exchange of OpCo Units. During the three months ended March 31, 2023 and 2022, we recorded general and administrative expense of $3.9 million and $3.3 million, respectively, and made cash distributions of $9.5 million and $2.7 million, respectively, to our redeemable noncontrolling interests related to the Management Agreement. In addition, at March 31, 2023, in relation to the Management Agreement, we accrued a $9.5 million distribution to redeemable noncontrolling interests that will be paid during the second quarter of 2023. At March 31, 2023 and December 31, 2022 we had $13.3 million included within Accounts payable – affiliates on our condensed 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. So long as the Manager continuously provides services to us until the end of the performance period applicable to a tranche, the Manager is entitled to settlement of such tranche with respect to a number of shares of Class A Common Stock ranging from 0% to 4.8% of the of the outstanding Class A Common Stock at the time each tranche is settled. During the three months ended March 31, 2023 and 2022, we recorded general and administrative expense of

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$5.9 million and $3.9 million, respectively, related to Incentive Compensation. See NOTE 10 – Incentive Compensation Arrangements 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 ("MSAs") 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, 2023 and December 31, 2022, we had a related party receivable of $0.6 million and $0.8 million, respectively, included within Accounts receivable – affiliates and a related party payable of $25.9 million and $14.0 million, respectively, included within Accounts payable – affiliates on our condensed consolidated balance sheets associated with KKR Funds transactions.

Other Transactions

During the three months ended March 31, 2023 and 2022, we incurred $1.1 million and $0.7 million, respectively, in fees to KKR Capital Markets LLC ("KCM"), an affiliate of KKR Group, in connection with transactions relating to the 2028 Notes and the 2026 Notes, respectively. We recorded these fees as debt issuance costs within Long-term debt on the condensed consolidated balance sheets. In April 2022, we paid an additional $1.5 million in fees to KCM related to the amendment to our Revolving Credit Facility, which increased our borrowing base and elected commitment amount in connection with the Uinta Transaction. We recorded these fees as debt issuance costs within Other assets on the condensed consolidated balance sheets. See NOTE 7 – Debt.

In March 2023, we signed 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 approximately $276,000, increasing over the term of the lease, and the payment by one of our subsidiaries of certain other customary expenses.

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. 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 4.2 million PSUs for the three months ended March 31, 2022 that were antidilutive.

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

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	Three Months Ended March 31,
	2023		2022
	(in thousands, except share and per share amounts)
Numerator:
Net income (loss)	$	255,611	$	(406,007)
Less: net loss attributable to Predecessor	—		—
Less: net (income) loss attributable to noncontrolling interests	(149)		(470)
Less: net (income) loss attributable to redeemable noncontrolling interests	(195,668)		321,477
Net income (loss) attributable to Crescent Energy - basic	59,794		(85,000)
Add: Reallocation of net income attributable to redeemable noncontrolling interest for the dilutive effect of RSUs	55		—
Add: Reallocation of net income attributable to redeemable noncontrolling interest for the dilutive effect of PSUs	360		—
Net income (loss) attributable to Crescent Energy - diluted	$	60,209	$	(85,000)
Denominator:
Weighted-average Class A common stock outstanding – basic	48,282,163		41,954,385
Add: dilutive effect of RSUs	50,579		—
Add: dilutive effect of PSUs	332,610		—
Weighted-average Class A common stock outstanding – diluted	48,665,352		41,954,385
Weighted-average Class B common stock outstanding – basic and diluted	118,645,323		127,536,463
Net income (loss) per share:
Class A common stock – basic	$	1.24	$	(2.03)
Class A common stock – diluted	$	1.24	$	(2.03)
Class B common stock – basic and diluted	$	—	$	—

NOTE 13 – Subsequent Events

Dividend

On May 10, 2023, 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 2023. The quarterly dividend is payable on June 7, 2023 to shareholders of record as of the close of business on May 24, 2023. OpCo unitholders will also receive a distribution based on their pro rata ownership of OpCo Units.

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.

Western Eagle Ford Bolt-On Acquisition

On May 2, 2023, one of our subsidiaries entered into a Purchase and Sale Agreement (the “Mesquite Purchase Agreement” and the transactions contemplated therein, the "Mesquite Acquisition") with Mesquite Comanche Holdings, LLC (“Comanche Holdings”) and SN EF Maverick, LLC (“SN EF Maverick,” and collectively with Comanche Holdings, the “Seller”), pursuant to which our subsidiary agreed to acquire from the Seller certain interests in oil and gas properties, rights and related assets in the Eagle Ford basin for aggregate cash consideration of approximately $600 million, subject to customary purchase price adjustments set forth in the Mesquite Purchase Agreement. Subject to the terms of the Mesquite Purchase Agreement, the acquisition is expected to close in the third quarter of 2023.

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Item 2. Management’s discussion and analysis of financial condition and results of operations

Management's Discussion and Analysis of Financial Condition and Results of Operations ("MD&A") is intended to provide the reader of the financial statements with a narrative from the perspective of management on the financial condition, results of operations, liquidity and certain other factors that may affect the Company's operating results. The following discussion and analysis should be read in conjunction with Management's Discussion and Analysis of Financial Condition and Results of Operations in our Annual Report on Form 10-K for the year ended December 31, 2022 ("Annual Report"), as well as our unaudited condensed consolidated financial statements for the three months ended March 31, 2023 and 2022. 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, 2023 and 2022. 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.

Business

We are a well-capitalized U.S. independent energy company with a portfolio of low-decline assets in key proven regions across the lower 48 states, focused in Texas and the Rockies.

Our approach employs a unique business model that combines an investor mindset and deep operational expertise to pursue a cash flow-based investment mandate focused on operated working interests with an active risk management strategy. We pursue our strategy through the production, development and acquisition of oil, natural gas and NGL reserves.

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 the COVID-19 pandemic and recovery, Russia’s invasion of Ukraine and the related sanctions imposed on Russia, supply chain constraints and rising interest rates and costs of capital. Furthermore, the United States experienced a significant inflationary environment in 2022 that, along with international geopolitical risks, has contributed to concerns of a potential recession in 2023 that has caused oil and gas prices to retreat from their earlier highs in 2022 and has created further volatility. In April 2023, OPEC announced production cuts of around 1.16 million barrels per day. The actions of OPEC with respect to oil production levels and announcements of potential changes in such levels, including agreement on and compliance with production cuts, 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.

Recently, growing market concern regarding the health of the global banking sector, in which two U.S. bank failures have occurred and large national and international banks have experienced significant declines in market value, and any resultant recessionary effects have contributed, among other factors, to a significant decline in the price for oil and natural gas, with the posted price for WTI reaching a low of $66.61 in March 2023, a level not seen since December 2021. Ongoing uncertainty regarding the going concern of certain banks, including the inability of banking and other financial services firms to access liquidity, has and may continue to result in significant disruptions to global markets, may result in lower commodity prices and continued volatility thereof and negatively impact our financial condition.

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. These 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. Sustained levels of high inflation have likewise caused the U.S. Federal Reserve and other central banks to increase interest rates, most recently in

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March 2023 by a quarter of a percentage point. To the extent elevated inflation remains, we may experience further cost increases for our operations, including oilfield services, labor costs and equipment if our drilling activity increases. 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—"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.

In August 2022, the Inflation Reduction Act of 2022 (“IRA 2022”) was signed into law. The IRA 2022 contains hundreds of billions of dollars in incentives for the development of renewable energy, clean hydrogen, clean fuels, electric vehicles and supporting infrastructure and carbon capture and sequestration, amongst other provisions. These incentives could further accelerate the transition of the U.S. economy away from the use of fossil fuels towards lower- or zero-carbon emissions alternatives, which could decrease demand for the oil and gas we produce and consequently materially and adversely affect our business and results of operations. In addition, the IRA 2022 imposes a federal fee on the emission of greenhouse gases through a methane emissions charge, including onshore petroleum and natural gas production. The methane emissions charge will start in calendar year 2024 and the fee is based on certain thresholds established in the IRA 2022. The methane emissions charge could increase our operating costs and adversely affect our business and results of operations. See Part II, Item 1A. Risk Factors for additional information. Finally, the IRA 2022 includes a new corporate alternative minimum tax of 15% on the adjusted financial statement income ("AFSI") of corporations with average AFSI exceeding $1.0 billion over a three-year period. While we are evaluating the impact of the new corporate alternative minimum tax will have, we do not believe that it will have a material impact on our near-term taxes.

Other transactions

In February 2023, we issued $400.0 million aggregate principal amount of 9.250% senior notes due 2028 (the "2028 Notes"). The proceeds of the offering were approximately $391.3 million, after deducting the initial purchasers' discount and offering expenses. We used the proceeds to repay a portion of outstanding borrowings under our Revolving Credit Facility.

Acquisitions and divestitures

Acquisitions

On May 2, 2023, one of our subsidiaries entered into a Purchase and Sale Agreement (the “Mesquite Purchase Agreement” and the transactions contemplated therein, the "Mesquite Acquisition") with Mesquite Comanche Holdings, LLC (“Comanche Holdings”) and SN EF Maverick, LLC (“SN EF Maverick,” and collectively with Comanche Holdings, the “Seller”), pursuant to which our subsidiary agreed to acquire from the Seller certain interests in oil and gas properties, rights and related assets in the Eagle Ford basin for aggregate cash consideration of approximately $600 million, subject to customary purchase price adjustments set forth in the Mesquite Purchase Agreement. Subject to the terms of the Mesquite Purchase Agreement, the acquisition is expected to close in the third quarter of 2023.

In March 2022, we consummated the acquisition contemplated by the Membership Interest Purchase Agreement dated February 15, 2022 (the transactions contemplated therein, the “Uinta Transaction”) between certain of our subsidiaries, including OpCo, and Verdun Oil Company II LLC, a Delaware limited liability company, pursuant to which we purchased all of the issued and outstanding membership interests of Uinta AssetCo, LLC, a Texas limited liability company that held all development and production assets of, and certain obligations of, EP Energy E&P Company, L.P. located in the State of Utah. Upon closing of the Uinta Transaction on March 30, 2022, we paid $621.3 million in cash consideration and related transaction fees and assumed certain commodity derivatives. The Uinta Transaction was funded with cash on hand and borrowings under our Revolving Credit Facility. In connection with the closing of the Uinta Transaction, we entered into an amendment to our Revolving Credit Facility to, among other things, increase the borrowing base to $1.8 billion and the elected commitment amount to $1.3 billion.

Subsequent to the closing of the Uinta Transaction, we settled certain acquired oil commodity derivative positions and entered into new commodity derivative contracts for 2022 with a swap price of $75 per barrel for a net cost of $54.1 million, including restructuring fees, during the three months ended March 31, 2022.

Divestitures

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On November 4, 2022, we entered into a definitive purchase and sale agreement with an unaffiliated third party to sell certain of our non-core producing properties and related oil and natural gas leases in Ector County, Texas in the Permian Basin in exchange for cash consideration, subject to customary purchase price adjustments, of $80.0 million. We closed the divestiture in December 2022 and recorded a loss of $0.9 million during the year ended December 31, 2022.

In April 2022, our equity method investment, Exaro Energy III, LLC ("Exaro"), entered into a purchase and sale agreement to sell its operations in the Jonah Field in Wyoming. During the year ended December 31, 2022, we received a distribution from Exaro of $6.8 million primarily as a result of the sale.

In February 2022, we contributed all of the assets and prospects in the Gulf of Mexico formerly owned by one of our subsidiaries to Chama Energy LLC ("Chama"), in exchange for a 9.4% interest in Chama, which we valued at approximately $3.8 million. As a result, we derecognized these contributed assets and liabilities from our condensed consolidated balance sheets and recorded an equity method investment for our interest in Chama, as well as a $4.5 million gain related to on the deconsolidation of these assets and liabilities. John Goff, the Chairman of our Board of Directors, holds an approximate interest of 17.5% in Chama, and the remaining interests are held by other non-affiliated investors. Pursuant to the Limited Liability Company Agreement of Chama, we may be required to fund certain workover costs, and we will be required to fund plugging and abandonment costs related to the producing assets we contributed to Chama.

Stewardship

We strive to be good stewards of others’ assets: our investors’ capital, the environment and the communities in which we operate. We believe that this stewardship, and our success, requires an alignment with the interests of our stakeholders including our employees, investors, customers, suppliers and society at large. 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. In September 2022, we released our 2021 ESG report. The report included benchmarks for measuring future performance, consistent with Crescent's commitment to aligning with the SASB and Task Force on Climate-related Financial Disclosures frameworks, noted the progress of our key ESG priorities and detailed our goals to reduce absolute Scope 1 GHG and methane emissions in support of an economy-wide transition to a net-zero world. We invite you to review our 2021 ESG report, which is available on Crescent’s website at https://www.crescentenergyco.com/#esg. However, please note that the contents of this ESG report, and other materials on our website, are not incorporated into this Quarterly Report by reference. In February 2022, we joined the Oil & Gas Methane Partnership 2.0 Initiative to enhance reporting of methane emissions. We also established a Sustainability Expert Advisory Council to advise management and our Board of Directors on sustainability-related issues.

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 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 incur approximately $575 million to $650 million, excluding acquisitions, for our 2023 capital program. The majority of our program is allocated to D&C, which approximately 85% is allocated to our operated assets in Texas and the Rockies. We are currently running one rig in the Eagle Ford and one rig in the Uinta. We expect to fund our 2023 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

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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.

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,
	2023		2022
Oil	65	%	64	%
Natural gas	28	%	24	%
NGLs	7	%	12	%

In addition, revenue from our midstream assets is supported by commercial agreements that have established minimum volume commitments. These midstream revenues comprise the majority of our midstream and other revenue. Midstream and other revenue accounts for 2% or less of our total revenues for the three months ended March 31, 2023 and 2022.

Production volumes sold

The following table presents historical sales volumes for our properties:

	Three Months Ended March 31,
	2023	2022
Oil (MBbls)	5,320	3,985
Natural gas (MMcf)	31,550	30,014
NGLs (MBbls)	1,712	1,827
Total (MBoe)	12,290	10,814
Daily average (MBoe/d)	137	120

Total sales volume increased 1,476 MBoe during the three months ended March 31, 2023 compared to the three months ended March 31, 2022. The increase is primarily due to the Uinta Transaction, which contributed an additional 2,086 MBoe for the three months ended March 31, 2023 as compared to the three months ended March 31, 2022. Sales volumes from our existing asset base decreased by 610 MBoe during the three months ended March 31, 2023 compared to the three months ended March 31, 2022, primarily as a result of natural decline, partially offset by new operated Eagle Ford completions in the first quarter of 2023.

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, impacted by the COVID-19 pandemic and recovery, Russia’s invasion of Ukraine and the associated sanctions imposed on Russia, actions taken by OPEC, inflation and increased U.S. drilling activity. Uncertainty persists regarding OPEC’s actions, increased U.S. drilling, inflation and the armed conflict in Ukraine. Additionally, growing market concern regarding the health of the global banking sector and any resultant recessionary effects have contributed, among other factors, to a significant decline in the price for oil and natural gas in the first quarter of 2023.

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

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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,
	2023		2022
Oil	62	%	75	%
Natural gas	58	%	75	%
NGLs	41	%	51	%

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,
	2023		2022
Oil (Bbl):
Average NYMEX	$	76.13	$	94.29
Realized price (excluding derivative settlements)	69.99		93.47
Realized price (including derivative settlements) (1)	62.83		68.36
Natural Gas (Mcf):
Average NYMEX	$	3.42	$	4.95
Realized price (excluding derivative settlements)	5.14		4.77
Realized price (including derivative settlements)	4.61		3.11
NGLs (Bbl):
Realized price (excluding derivative settlements)	$	24.84	$	38.97
Realized price (including derivative settlements)	29.21		24.81

(1) Does not include the $18.6 million impact from the settlement of acquired derivative contracts.

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Results of operations:

Three Months Ended March 31, 2023 Compared to Three Months Ended March 31, 2022

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,
	2023		2022		$ Change		% Change
Revenues (in thousands):
Oil	$	372,336	$	372,509	$	(173)	—	%
Natural gas	162,021		143,311		18,710		13	%
Natural gas liquids	42,523		71,179		(28,656)		(40)	%
Midstream and other	13,257		11,911		1,346		11	%
Total revenues	$	590,137	$	598,910	$	(8,773)	(1)	%
Average realized prices, before effects of derivative settlements:
Oil ($/Bbl)	$	69.99	$	93.47	$	(23.48)	(25)	%
Natural gas ($/Mcf)	5.14		4.77		0.37		8	%
NGLs ($/Bbl)	24.84		38.97		(14.13)		(36)	%
Total ($/Boe)	46.94		54.28		(7.34)		(14)	%
Net sales volumes:
Oil (MBbls)	5,320		3,985		1,335		34	%
Natural gas (MMcf)	31,550		30,014		1,536		5	%
NGLs (MBbls)	1,712		1,827		(115)		(6)	%
Total (MBoe)	12,290		10,814		1,476		14	%
Average daily net sales volumes:
Oil (MBbls/d)	59		44		15		34	%
Natural gas (MMcf/d)	351		333		18		5	%
NGLs (MBbls/d)	19		20		(1)		(5)	%
Total (MBoe/d)	137		120		17		14	%

Oil revenue. Oil revenue decreased $0.2 million, or a nominal percentage, in the three months ended March 31, 2023, compared to the three months ended March 31, 2022. This was driven by a $124.8 million increase in sales volume (15 MBbls/d or 34%), offset by lower realized oil prices that resulted in a decrease of $125.0 million (a decrease of 25% per Bbl). The increase in sales volumes is primarily related to the Uinta Transaction, which contributed an additional 1,372 MBbls.

Natural gas revenue. Natural gas revenue increased $18.7 million, or 13% in the three months ended March 31, 2023, compared to the three months ended March 31, 2022. This was driven by higher natural gas prices that resulted in an increase of $11.5 million (an increase of 8% per Mcf) and a $7.2 million increase in sales volume (18 MMcf/d, or 5%). The increase in natural gas price was primarily driven by access to west coast natural gas pricing markets resulting in significant volumes priced at a premium to Henry Hub. The increase in sales volumes is primarily related to the Uinta Transaction, which contributed an additional 4,268 MMcf, partially offset by the natural decline from our existing asset base of 2,732 MMcf.

NGL revenue. NGL revenue decreased $28.7 million, or 40%, in the three months ended March 31, 2023, compared to the three months ended March 31, 2022. This was driven primarily by lower realized NGL prices that resulted in a decrease of $24.2 million (a decrease of 36% per Bbl) and a $4.5 million decrease in sales volume (1 MBbls/d, or 5%). The decrease in sales volumes is primarily related to the natural decline from our existing asset base.

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Midstream and other revenue. Midstream and other revenue increased $1.3 million, or 11%, in the three months ended March 31, 2023, compared to the three months ended March 31, 2022, driven primarily by higher sulfur 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,
	2023		2022		$ Change		% Change
Expenses (in thousands):
Operating expense	$	271,848	$	219,239	$	52,609	24	%
Depreciation, depletion and amortization	146,483		99,019		47,464		48	%
General and administrative expense	21,238		22,522		(1,284)		(6)	%
Other operating costs	—		(4,699)		4,699		NM*
Total expenses	$	439,569	$	336,081	$	103,488	31	%
Selected expenses per Boe:
Operating expense	$	22.12	$	20.27	$	1.85	9	%
Depreciation, depletion and amortization	11.92		9.16		2.76		30	%

* NM = Not meaningful.

Operating expense. Operating expense increased $52.6 million, or 24%, in the three months ended March 31, 2023, compared to the three months ended March 31, 2022, driven primarily by the following factors:

(i)Lease and asset operating expense increased $41.7 million, or 37%, in the three months ended March 31, 2023, compared to the three months ended March 31, 2022, and increased $2.15 per Boe, or 21% to $12.46 per Boe. This $41.7 million increase was driven primarily by higher production during the three months ended March 31, 2023, due in part to the Uinta Transaction, which contributed $31.6 million to the increase, general inflationary costs across our assets and higher cost residue gas purchases related to increased natural gas prices in the West Coast pricing market. Higher cost residue gas was more than offset by higher realized pricing.

(ii)Gathering, transportation and marketing expense decreased $0.9 million, or 2%, in the three months ended March 31, 2023, compared to the three months ended March 31, 2022, and decreased $0.60 per Boe, or 13% to $3.86 per Boe. This decrease was driven primarily by higher production during the three months ended March 31, 2023, mainly due to production related to the Uinta Transaction in the current quarter of 2,086 Mboe.

(iii)Production and other taxes increased $8.4 million, or 18%, in the three months ended March 31, 2023, compared to the three months ended March 31, 2022, and increased $0.17 per Boe, or 4%, to $4.47 per Boe. This increase was driven primarily by the Uinta Transaction and the additional oil and natural gas revenues from those assets.

(iv)Workover expense increased $2.6 million, or 26%, in the three months ended March 31, 2023, compared to the three months ended March 31, 2022, and increased $0.10 per Boe, or 11%, to $1.02 per Boe. This increase was primarily driven by the Uinta Transaction, which contributed $2.1 million to the increase.

(v)Midstream operating expense increased $0.7 million, or 23%, in the three months ended March 31, 2023, compared to the three months ended March 31, 2022.

Depreciation, depletion and amortization. In the three months ended March 31, 2023, depreciation, depletion and amortization increased $47.5 million, or 48%, compared to the three months ended March 31, 2022, driven primarily by $36.3 million of additional depreciation, depletion and amortization due to the Uinta Transaction.

General and administrative expense. General and administrative expense ("G&A") decreased $1.3 million, or 6%, for the three months ended March 31, 2023, compared to the three months ended March 31, 2022, primarily driven by (i) a decrease in equity-based compensation expense of $3.5 million and (ii) $0.8 million lower transaction and nonrecurring related expenses, offset by higher recurring G&A including higher expense payable under the Management Agreement with KKR Energy Assets Manager LLC, which is the pro-rata portion of the Manager Compensation borne by us, due to an increase in public ownership of Class A Common Stock as a result of public offerings of our Class A Common Stock completed in 2022. While only the portion of Manager Compensation borne by us impacts our consolidated statements of operations, we include the full amount in the calculation of Adjusted EBITDAX and Levered Free Cash Flow (the difference between the Manager Compensation and

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the amount presented in G&A is represented by “Certain-redeemable noncontrolling interest distributions made by OpCo related to Manager Compensation”).

	Three Months Ended March 31,
	2023		2022		$ Change		% Change
General and administrative expense (in thousands):
Recurring general and administrative expense	$	11,265	$	8,263	$	3,002	36	%
Transaction and nonrecurring expenses	2,368		3,144		(776)		(25)	%
Equity-based compensation	7,605		11,115		(3,510)		(32)	%
Total general and administrative expense	$	21,238	$	22,522	$	(1,284)	(6)	%
General and administrative expense per Boe:
Recurring general and administrative expense	$	0.92	$	0.76	$	0.16	21	%
Transaction and nonrecurring expenses	0.19		0.29		(0.10)		(34)	%
Equity-based compensation	0.62		1.03		(0.41)		(40)	%

Other operating costs. Other operating costs include exploration expense and gain on sale of assets. Other operating costs increased by $4.7 million, compared to the three months ended March 31, 2022, primarily driven by the $4.8 million gain on asset sales recognized during the three months ended March 31, 2022.

Interest expense

In the three months ended March 31, 2023, we incurred interest expense of $29.3 million, as compared to $16.5 million in the three months ended March 31, 2022, a 77% increase. This increase was driven primarily by higher interest rates associated with the issuance of the 2028 Notes (as defined below) and our Revolving Credit Facility, as well as an increase in our weighted average debt outstanding during the period related to the Uinta Transaction.

Gain (loss) on derivatives

We have entered into derivative contracts to manage our exposure to commodity price risks that impact our revenues. The following table presents total unrealized and realized gain (loss) on derivatives for the periods presented:

	Three Months Ended March 31,
	2023		2022		$ Change		% Change
Gain (loss) on derivatives (in thousands):
Gain (loss) on commodity derivatives	$	150,310	$	(673,486)	$	823,796	(122)	%
Gain (loss) on derivatives	$	150,310	$	(673,486)	$	823,796	(122)	%

Our gains on commodity derivatives during the three months ended March 31, 2023 changed by $823.8 million, or 122%, from a comparable loss during the three months ended March 31, 2022 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, 2023 and March 31, 2022 we recognized income tax expense of $16.4 million and $21.7 million, respectively, for an effective tax rate of 6.0% and 5.1%, respectively. Our effective tax rate is 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.

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. See “—Non-GAAP Financial Measures” below for their definitions and application.

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The following table presents a reconciliation of Adjusted EBITDAX (non-GAAP) and Levered Free Cash Flow (non-GAAP) to net income (loss), the most directly comparable financial measure calculated in accordance with GAAP:

	Three Months Ended March 31,
	2023		2022		$ Change		% Change
(in thousands)
Net income (loss)	$	255,611	$	(406,007)	$	661,618	(163)	%
Adjustments to reconcile to Adjusted EBITDAX:
Interest expense	29,320		16,524
Income tax expense (benefit)	16,360		(21,725)
Depreciation, depletion and amortization	146,483		99,019
Exploration expense	—		91
Non-cash (gain) loss on derivatives	(197,467)		497,685
Non-cash equity-based compensation expense	7,605		11,115
(Gain) loss on sale of assets	—		(4,790)
Other (income) expense	(250)		1,499
Certain redeemable noncontrolling interest distributions made by OpCo related to Manager Compensation	(9,471)		(10,064)
Transaction and nonrecurring expenses (1)	2,435		11,559
Settlement of acquired derivative contracts	(18,647)		—
Adjusted EBITDAX (non-GAAP)	$	231,979	$	194,906	$	37,073	19	%
Adjustments to reconcile to Levered Free Cash Flow:
Interest expense, excluding non-cash deferred financing cost amortization	(28,270)		(14,927)
Current income tax benefit (expense)	(512)		(4,950)
Tax-related redeemable noncontrolling interest distributions made by OpCo	(12)		—
Development of oil and natural gas properties	(201,687)		(85,480)
Levered Free Cash Flow (non-GAAP)	$	1,498	$	89,549	$	(88,051)	(98	%)

(1)Transaction and nonrecurring expenses of $2.4 million for the three months ended March 31, 2023 were primarily related to system integration expenses. Transaction and nonrecurring expenses of $11.6 million for the three months ended March 31, 2022 were primarily related to (i) legal, consulting, transition service agreement costs, related restructuring of acquired derivative contracts, and other fees incurred for the Uinta Transaction and the series of transactions pursuant to which we indirectly combined the businesses of Contango Oil & Gas Company and Independence Energy LLC (the "Merger Transactions"), (ii) severance costs subsequent to the Merger Transactions, (iii) merger integration costs and (iv) acquisition and debt transaction related costs.

Adjusted EBITDAX increased by $37.1 million, or 19%, in the three months ended March 31, 2023, compared to the three months ended March 31, 2022, primarily driven by (i) the Uinta Transaction and (ii)  realized natural gas prices, particularly in the Rockies, which realized a premium to Henry Hub due to winter weather conditions experienced during the first quarter of 2023.

Levered Free Cash Flow decreased by $88.1 million, or 98%, in the three months ended March 31, 2023 compared to the three months ended March 31, 2022, primarily driven by $116.2 million of increased capital expenditures related to our additional reinvestment activities, partially offset by our increased Adjusted EBITDAX.

Liquidity and capital resources

Our primary sources of liquidity are cash flow from operations, 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 and, as appropriate and subject to market conditions, opportunistic capital markets offerings. Our primary expected uses of capital are for dividends to shareholders, debt repayment, development of our existing assets and acquisitions.

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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 as well as adding incremental derivatives to our production base over time. Our active derivative program allows us to preserve capital and 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, 2023		December 31, 2022
(in thousands)
Cash and cash equivalents	$	2,930	$	—
Long-term debt	1,244,587		1,247,558

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,
	2023		2022
(in thousands)
Net cash provided by operating activities	$	240,090	$	137,291
Net cash used in investing activities	(195,113)		(713,394)
Net cash (used in) provided by financing activities	(43,672)		561,517

Net cash provided by operating activities. Net cash provided by operating activities for the three months ended March 31, 2023 increased by $102.8 million, or 75%, compared to the three months ended March 31, 2022 primarily due to higher EBITDAX. In addition, net cash provided by operating activities for the three months ended March 31, 2022 was impacted by a $52.0 million restructuring of certain oil commodity derivative contracts acquired in connection with the Uinta Transaction.

Net cash used in investing activities. Net cash used in investing activities for the three months ended March 31, 2023 decreased by $518.3 million, or 73%, compared to the three months ended March 31, 2022, primarily due to $609.0 million of additional acquisitions of oil and natural gas properties in 2022, driven by the Uinta Transaction, partially offset by an additional $96.7 million of cash development capital expenditures.

Net cash (used in) provided by financing activities. Net cash used in financing activities for the three months ended March 31, 2023 was $43.7 million, driven by $29.7 million in distributions to redeemable noncontrolling interests and $8.2 million in dividends to holders of our Class A Common Stock, which were in total $14.8 million higher than the related 2022 cash outflows. Net cash provided by financing activities for the three months ended March 31, 2022 was primarily a result of our debt transactions used primarily to fund the Uinta Transaction.

Debt agreements

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Senior Notes

On February 1, 2023, we issued $400.0 million aggregate principal amount of the 2028 Notes. The estimated proceeds of the offering were $391.3 million, after deducting the initial purchasers' discount and offering expenses. We used the proceeds to repay a portion of the outstanding balance of our Revolving Credit Facility. 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.

We may, at our option, redeem all or a portion of the 2028 Notes at any time on or after February 15, 2025 at certain redemption prices. We may also redeem up to 40% of the aggregate principal amount of the 2028 Notes before February 15, 2025 with an amount of cash not greater than the net proceeds that we raise in certain equity offerings at a redemption price equal to 109.250% of the principal amount of the 2028 Notes being redeemed, plus accrued and unpaid interest, if any, to, but excluding the redemption date. In addition, prior to February 15, 2025, we may redeem some or all of the 2028 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.

In May 2021, Crescent Energy Finance LLC ("Crescent Finance") issued $500.0 million aggregate principal amount of senior notes due 2026 at par (the "Original 2026 Notes"). In February 2022, Crescent Finance issued an additional $200.0 million aggregate principal amount of our senior notes due 2026 at 101% of par (the "Additional 2026 Notes" and, together with the Original 2026 Notes, the "2026 Notes"). Both issuances of the Senior Notes are treated as a single series and vote together as a single class, and have identical terms and conditions, other than the issue date, the issue price and the first interest payment. The Senior Notes bear interest at an annual rate of 7.250%, which is payable on May 1 and November 1 of each year and mature on May 1, 2026.

We may, at our option, redeem all or a portion of the 2026 Notes at any time on or after May 1, 2023 at certain redemption prices. We may also redeem up to 40% of the aggregate principal amount of the 2026 Notes before May 1, 2023 with an amount of cash not greater than the net proceeds that we raise in certain equity offerings at a redemption price equal to 107.250% of the principal amount of the 2026 Notes being redeemed, plus accrued and unpaid interest, if any, to, but excluding the redemption date. In addition, prior to May 1, 2023, we may redeem some or all of the 2026 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.

The Senior Notes are our senior unsecured obligations, and the notes and the guarantees issued in connection with the issuance of the Senior Notes rank equally in right of payment with the borrowings under the Revolving Credit Facility and all other future senior indebtedness and senior to any future subordinated indebtedness. The Senior Notes are guaranteed on a senior unsecured basis by each of our existing and future subsidiaries that guarantee the 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 the 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. Under each of the indentures governing the Senior Notes, Crescent Finance may issue additional notes that will be treated as a single series and vote together as a single class and have substantially identical terms and conditions.

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 change 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 Senior Notes in the future, on any securities exchange, and currently there is no public market for the Senior Notes.

Revolving Credit Facility

In connection with the issuance of the 2026 Notes in May 2021, Crescent Finance entered into the Revolving Credit Facility. The Revolving Credit Facility matures on September 23, 2027. At March 31, 2023, we had $164.0 million of outstanding

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borrowings under the Revolving Credit Facility and $9.7 million in outstanding letters of credit. Our elected commitment amount was $1.3 billion and we had $1.1 billion of available borrowings under the Revolving Credit Facility as of March 31, 2023.

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 is 0.50% per year. Our weighted average interest rate on loan amounts outstanding as of March 31, 2023 and December 31, 2022 was 7.17% and 6.98%, respectively.

The borrowing base under the Revolving Credit Facility was $2.0 billion as of March 31, 2023 and December 31, 2022. 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.

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 a 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. At March 31, 2023, 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 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 approximately $575 million to $650 million to our 2023 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 and conversions of proved undeveloped volumes to proved developed volumes. These risks could materially affect our business, financial condition and results of operations.

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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,
	2023		2022
(in thousands)
Total development of oil and natural gas properties	$	201,687	$	85,480
Change in accruals or other non-cash adjustments	(11,209)		8,336
Cash used in development of oil and natural gas properties	190,478		93,816
Cash used in acquisition of oil and natural gas properties	11,353		620,342
Total expenditures on acquisition and development of oil and natural gas properties	$	201,831	$	714,158

Our development of oil and natural gas properties was higher during the three months ended March 31, 2023, compared to the three months ended March 31, 2022. The increase in our development is related to the timing of development activity and the Uinta Transaction. We used cash of $11.4 million in the first quarter of 2023 for the acquisition of oil and natural gas properties, as compared to $620.3 million in the first quarter of 2022, primarily related to the Uinta Transaction (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, 2023, 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 $0.17 per share of our Class A Common Stock on March 31, 2023 to shareholders of record as of the close of business on March 20, 2023.

On May 10, 2023, 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 2023. The quarterly dividend is payable on June 7, 2023 to shareholders of record as of the close of business on May 24, 2023. OpCo unitholders will also receive a distribution based on their pro rata ownership of OpCo Units.

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 changes 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, 2022 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, 2023.

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

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•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, realized (gain) loss on interest rate derivatives, income tax expense (benefit), depreciation, depletion and amortization, exploration expense, non-cash gain (loss) on derivative contracts, impairment expense, non-cash equity-based compensation, (gain) loss on sale of assets, other (income) expense, certain redeemable noncontrolling interest distributions made by OpCo related to Manager Compensation, transaction and nonrecurring expenses and settlement of acquired derivative contracts. We believe Adjusted EBITDAX is a useful performance measure because it allows for an effective evaluation of our operating performance when compared against our peers, without regard to our financing methods, corporate form or capital structure. We exclude the items listed above from net income (loss) in arriving at Adjusted EBITDAX because these amounts can vary substantially within our industry depending upon accounting methods and book values of assets, capital structures and the method by which the assets were acquired. Adjusted EBITDAX should not be considered as an alternative to, or more meaningful than, net income (loss) as determined in accordance with GAAP, of which such measure is the most comparable GAAP measure. Certain items excluded from Adjusted EBITDAX are significant components in understanding and assessing a company’s financial performance, such as a company’s cost of capital and tax burden, as well as the historic costs of depreciable assets, none of which are reflected in Adjusted EBITDAX. Our presentation of Adjusted EBITDAX should not be construed as an inference that our results will be unaffected by unusual or nonrecurring items. Our computations of Adjusted EBITDAX may not be identical to other similarly titled measures of other companies. In addition, the Revolving Credit Facility and Senior Notes include a calculation of Adjusted EBITDAX for purposes of covenant compliance.

We define Levered Free Cash Flow as Adjusted EBITDAX less interest expense, excluding non-cash deferred financing cost amortization, realized gain (loss) on interest rate derivatives, 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 or proceeds received from asset sales. Levered Free Cash Flow is not a measure of performance as determined by GAAP. Levered Free Cash Flow is a supplemental non-GAAP performance 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 performance 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 income (loss) as determined in accordance with GAAP, of which such measure is the most comparable GAAP measure, or as an indicator of actual 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.

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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, 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, 2023, our derivative portfolio had an aggregate notional value of approximately $1.2 billion, and the fair market value of our commodity derivative contracts was a net liability of $145.7 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, 2023, 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 $125.1 million. If prices decreased by 10%, our derivative position would change by approximately $124.0 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 the 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 the 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, 2023, we had $164.0 million of variable rate debt outstanding. Assuming no change in the amount outstanding, a 1% (or 100 basis point) increase or decrease in the average interest rate would result in an approximately $0.4 million increase or decrease in interest expense on our variable rate debt outstanding for the three months ended March 31, 2023.

Item 4. Controls and Procedures 

Limitations on effectiveness of controls and procedures

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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, 2023. 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, 2023 that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.

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Part II – Other Information

Item 1. Legal Proceedings

The Company may, from time to time, be involved in litigation and claims arising out of its operations in the normal course of business. We are currently unaware of any proceedings that, in the opinion of management, will individually or in the aggregate have a material adverse effect on our financial position, results of operations or cash flows. Additional information required for this item is provided in Notes to condensed consolidated financial statements, Note 9 – Commitments and Contingencies 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 37 in our Annual Report. If any of the risks and uncertainties described within our Annual Report or elsewhere in this Quarterly Report actually occur, our business, financial condition or results of operations could be materially adversely affected.

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

None.

Item 3. Defaults Upon Senior Securities

None.

Item 4. Mine Safety Disclosures

Not applicable.

Item 5. Other Information

Not applicable.

Item 6. Exhibits

Exhibit No.	Description
2.1	Transaction Agreement, dated as of June 7, 2021, by and among Contango Oil & Gas Company, Independence Energy LLC, IE PubCo Inc., IE OpCo LLC, IE L Merger Sub LLC and IE C Merger Sub Inc. (incorporated by reference to Exhibit 2.1 to the Company's proxy statement/prospectus, filed with the Securities and Exchange Commission on October 8, 2021).
2.2	Membership Interest Purchase Agreement, dated as of February 15, 2022, by and between Verdun Oil Company II LLC and Javelin VentureCo, LLC, and Crescent Energy OpCo LLC, as guarantor (incorporated by reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K filed with the Securities and Exchange Commission on February 16, 2022).
2.3	Purchase and Sale Agreement, dated as of May 2, 2023, by and among Mesquite Comanche Holdings, LLC, SN EF Maverick, LLC and Javelin EF L.P. (incorporated by reference to Exhibit 2.1 to the Company's Current Report on Form 8-K filed with the Securities and Exchange Commission on May 3, 2023).
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).

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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 7, 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).
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.INS**	XBRL Instance Document
101.SCH**	XBRL Schema Document
101.CAL**	XBRL Calculation Linkbase Document
101.LAB**	XBRL Label Linkbase Document
101.PRE**	XBRL Presentation Linkbase Document
101.DEF**	XBRL Definition Linkbase Document
104**	Cover Page Interactive Data File (formatted as Inline XBRL and contained in Exhibit 101).

* Filed herewith

** These files are furnished and deemed not filed or part of a registration statement or prospectus for purposes of Sections 11 or 12 of the Securities Act of 1933, as amended, are deemed not filed for purposes of Section 18 of the Securities Act of 1934, as amended, and otherwise are not subject to liability under those sections.

†    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.

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Signatures

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.

	CRESCENT ENERGY COMPANY
	(Registrant)
May 10, 2023	/s/ David Rockecharlie
	David Rockecharlie
	Chief Executive Officer
	(Principal Executive Officer)
May 10, 2023	/s/ Brandi Kendall
	Brandi Kendall
	Chief Financial Officer
	(Principal Financial Officer)

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