Crescent Energy 10Q 2023 Q3 Quarterly report

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 September 30, 2023


☐			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 October 31, 2023, there were approximately 88,608,800 and 91,048,124 shares outstanding of the registrant's Class A and Class B common stock, 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			28
Item 3 . Quantitative and Qualitative Disclosures About Market Risk			46
Item 4. Controls and Procedures			47
Part II - Other Information
Item 1. Legal Proceedings			48
Item 1A. Risk Factors			48
Item 2. Unregistered Sales of Equity Securities and Use of Proceeds			48
Item 3. Defaults Upon Senior Securities			48
Item 4. Mine Safety Disclosures			48
Item 5. Other Information			48
Item 6. Exhibits			48
Signatures			51

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%.

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;

•risks related to the Western Eagle Ford Acquisitions (as defined herein), including the risk that we may fail to realize the expected benefits of the Western Eagle Ford Acquisitions;

•our ability to identify and select possible additional 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, including the Israel-Hamas conflict, 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 inflation and associated changes in monetary policy;

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

•epidemics or pandemics, including the effects of related public health concerns and the impact of continued actions taken by governmental authorities and other third parties in response thereto and any resultant 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, including the Western Eagle Ford Assets (as defined herein), 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 Western Eagle Ford Assets;

•our ability to successfully execute our growth strategies, including with respect to the Western Eagle Ford Acquisitions;

•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;

•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;

•information technology failures or cyberattacks;

•changes in tax laws;

•effects of competition; and

•seasonal weather conditions.

We caution you that these forward-looking statements are subject to all of the risks and uncertainties incident to the development, production, gathering and sale of oil, natural gas and NGLs, most of which are difficult to predict and many of which are beyond our control. These risks include, but are not limited to, commodity price volatility, inflation, lack of availability and cost of drilling and production equipment and services, project construction delays, environmental risks, drilling and other operating risks, lack of availability or capacity of midstream gathering and transportation infrastructure, regulatory changes, 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.

Part I – Financial Information

Item 1. Financial Statements


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

	September 30, 2023		December 31, 2022
ASSETS
Current assets:
Cash and cash equivalents	$	228,614	$	—
Restricted cash	33,422		8,000
Accounts receivable, net	577,982		457,071
Accounts receivable – affiliates	1,146		2,681
Derivative assets – current	4,278		14,878
Drilling advances	911		14,655

Prepaid expenses	50,547		13,241
Other current assets	6,214		6,213
Total current assets	903,114		516,739
Property, plant and equipment:
Oil and natural gas properties at cost, successful efforts method
Proved	8,153,621		7,113,819
Unproved	290,753		314,255
Oil and natural gas properties at cost, successful efforts method	8,444,374		7,428,074
Field and other property and equipment, at cost	189,605		176,831
Total property, plant and equipment	8,633,979		7,604,905
Less: accumulated depreciation, depletion, amortization and impairment	(2,620,453)		(2,167,135)
Property, plant and equipment, net	6,013,526		5,437,770


Investment in equity affiliates	10,780		15,038
Other assets	59,006		50,302
TOTAL ASSETS	$	6,986,426	$	6,019,849















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


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

	September 30, 2023		December 31, 2022
LIABILITIES, REDEEMABLE NONCONTROLLING INTERESTS AND EQUITY
Current liabilities:
Accounts payable and accrued liabilities	$	565,262	$	524,690
Accounts payable – affiliates	37,727		27,652
Derivative liabilities – current	243,199		312,975
Financing lease obligations – current	4,250		3,341
Other current liabilities	30,360		25,091
Total current liabilities	880,798		893,749
Long-term debt	1,912,187		1,247,558
Derivative liabilities – noncurrent	31,371		63,737
Asset retirement obligations	372,572		346,868
Deferred tax liability	234,166		147,348
Financing lease obligations – noncurrent	7,760		7,412
Other liabilities	31,632		14,183
Total liabilities	3,470,486		2,720,855
Commitments and contingencies (Note 9)
Redeemable noncontrolling interests	1,888,862		2,436,703
Equity:
Class A common stock, $0.0001 par value; 1,000,000,000 shares authorized, 89,680,353 and 49,433,154 shares issued, 88,608,800 and 48,282,163 shares outstanding as of September 30, 2023 and December 31, 2022, respectively	9		5
Class B common stock, $0.0001 par value; 500,000,000 shares authorized and 91,048,124 and 118,645,323 shares issued and outstanding as of September 30, 2023 and December 31, 2022, respectively	9		12
Preferred stock, $0.0001 par value; 500,000,000 shares authorized and 1,000 Series I preferred shares issued and outstanding as of September 30, 2023 and December 31, 2022	—		—
Treasury stock, at cost; 1,071,553 and 1,150,991 shares of Class A common stock as of September 30, 2023 and December 31, 2022, respectively	(17,143)		(18,448)
Additional paid-in capital	1,567,967		804,587
Retained earnings	50,906		61,957
Noncontrolling interests	25,330		14,178
Total equity	1,627,078		862,291
TOTAL LIABILITIES, REDEEMABLE NONCONTROLLING INTERESTS AND EQUITY	$	6,986,426	$	6,019,849

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

CRESCENT ENERGY COMPANY

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS

(Unaudited)

(in thousands, except per share amounts)


	Three Months Ended September 30,				Nine Months Ended September 30,
	2023		2022		2023		2022
Revenues:
Oil	$	504,660	$	550,823	$	1,270,244	$	1,525,899
Natural gas	72,097		235,830		286,172		586,318
Natural gas liquids	54,724		64,810		131,098		219,853
Midstream and other	10,917		13,494		37,360		40,231
Total revenues	642,398		864,957		1,724,874		2,372,301
Expenses:
Lease operating expense	120,791		121,554		364,796		322,752
Workover expense	16,148		21,126		47,402		56,102
Asset operating expense	27,116		20,791		65,206		54,653
Gathering, transportation and marketing	61,722		44,757		160,650		131,271
Production and other taxes	36,475		71,511		116,223		183,491
Depreciation, depletion and amortization	186,492		145,008		492,879		375,600
Exploration expense	—		1,909		1,541		3,848
Midstream and other operating expense	8,289		3,550		13,803		9,972
General and administrative expense	43,831		17,311		106,235		59,489
(Gain) loss on sale of assets	—		(127)		—		(5,114)
Total expenses	500,864		447,390		1,368,735		1,192,064
Income (loss) from operations	141,534		417,567		356,139		1,180,237
Other income (expense):
Gain (loss) on derivatives	(252,108)		205,130		(68,211)		(645,565)
Interest expense	(42,200)		(27,057)		(102,648)		(68,518)
Other income (expense)	917		(2,670)		1,206		(4,472)
Income (loss) from equity affiliates	116		834		396		4,086
Total other income (expense)	(293,275)		176,237		(169,257)		(714,469)
Income (loss) before taxes	(151,741)		593,804		186,882		465,768
Income tax benefit (expense)	20,639		(38,455)		(4,899)		(34,528)
Net income (loss)	(131,102)		555,349		181,983		431,240

Less: net (income) loss attributable to noncontrolling interests	(48)		(904)		(453)		(2,087)
Less: net (income) loss attributable to redeemable noncontrolling interests	78,280		(436,084)		(169,455)		(341,269)
Net income (loss) attributable to Crescent	$	(52,870)	$	118,361	$	12,075	$	87,884
Net income (loss) per share:
Class A common stock – basic	$	(0.67)	$	2.74	$	0.21	$	2.07
Class A common stock – diluted	$	(0.67)	$	2.74	$	0.21	$	2.07
Class B common stock – basic and diluted	$	—	$	—	$	—	$	—
Weighted average shares outstanding:
Class A common stock – basic	78,709		43,197		58,663		42,377
Class A common stock – diluted	78,709		43,210		59,142		42,382
Class B common stock – basic and diluted	91,048		125,797		109,244		126,950

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


CRESCENT ENERGY COMPANY
CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY
(Unaudited)
(in thousands)

	Crescent Energy Company
		Class A Common Stock			Class B Common Stock			Series I Preferred Stock			Treasury Stock			Additional Paid-in Capital		Retained Earnings (Accumulated Deficit)		Noncontrolling Interest		Total
	Shares	Amount	Shares		Amount	Shares		Amount	Shares		Amount




























Balance at January 1, 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
Net income (loss)		—	—		—	—		—	—		—	—		—		54,523		713		55,236

Distributions		—	—		—	—		—	—		—	—		—		—		(4,201)		(4,201)
Repurchase of noncontrolling interest		—	—		—	—		—	—		—	—		—		—		(4,060)		(4,060)
Dividend to Class A common stock		—	—		—	—		—	—		—	—		(7,133)		—		—		(7,133)
Equity-based compensation		—	—		—	—		—	—		—	—		1,080		—		(4)		1,076
Change in deferred taxes related to basis in OpCo (see Note 2)		—	—		—	—		—	—		—	—		(46,567)		—		—		(46,567)
Adjustment of redeemable noncontrolling interests to redemption amount (see Note 2)		—	—		—	—		—	—		—	—		194,980		—		—		194,980
Balance at June 30, 2022		41,954	$	4	127,536	$	13	1	$	—	1,151	$	(18,448)	$	683,541	$	(49,853)	$	6,049	$	621,306






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


CRESCENT ENERGY COMPANY
CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY
(Unaudited)
(in thousands)

	Crescent Energy Company
		Class A Common Stock			Class B Common Stock			Series I Preferred Stock			Treasury Stock			Additional Paid-in Capital		Retained Earnings (Accumulated Deficit)		Noncontrolling Interest		Total
	Shares	Amount	Shares		Amount	Shares		Amount	Shares		Amount
Balance at June 30, 2022		41,954	$	4	127,536	$	13	1	$	—	1,151	$	(18,448)	$	683,541	$	(49,853)	$	6,049	$	621,306
Net income (loss)		—	—		—	—		—	—		—	—		—		118,361		904		119,265

Distributions		—	—		—	—		—	—		—	—		—		—		(2,886)		(2,886)

Dividend to Class A common stock		—	—		—	—		—	—		—	—		—		(7,133)		—		(7,133)
Equity-based compensation		—	—		—	—		—	—		—	—		2,246		—		—		2,246
Change in deferred taxes related to basis differences associated with the Equity Transactions (see Note 2)		—	—		—	—		—	—		—	—		(5,599)		—		—		(5,599)
Change in equity associated with the Equity Transactions (see Note 1)		6,328	1		(8,891)	(1)		—	—		—	—		121,790		—		—		121,790
Balance at September 30, 2022		48,282	$	5	118,645	$	12	1	$	—	1,151	$	(18,448)	$	801,978	$	61,375	$	4,067	$	848,989

















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


CRESCENT ENERGY COMPANY
CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY
(Unaudited)
(in thousands)

	Crescent Energy Company
		Class A Common Stock			Class B Common Stock			Series I Preferred Stock			Treasury Stock			Additional Paid-in Capital		Retained Earnings (Accumulated Deficit)		Noncontrolling Interest		Total
	Shares	Amount	Shares		Amount	Shares		Amount	Shares		Amount
Balance at January 1, 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
Net income (loss)		—	—		—	—		—	—		—	—		—		5,151		256		5,407
Contributions		—	—		—	—		—	—		—	—		—		—		4,735		4,735
Distributions		—	—		—	—		—	—		—	—		—		—		(1,600)		(1,600)

Dividend to Class A common stock		—	—		—	—		—	—		—	—		—		(5,803)		—		(5,803)
Equity based compensation		80	—		—	—		—	—		(80)	1,305		6,695		—		2,118		10,118


Change in deferred taxes related to basis differences associated with the Class A Conversion		—	—		—	—		—	—		—	—		(69,708)		—		—		(69,708)
Change in equity associated with the Class A Conversion		27,597	3		(27,597)	(3)		—	—		—	—		618,732		—		—		618,732
Balance at June 30, 2023		75,959	$	8	91,048	$	9	1	$	—	1,071	$	(17,143)	$	1,362,118	$	112,891	$	20,475	$	1,478,358
Net income (loss)		—	—		—	—		—	—		—	—		—		(52,870)		48		(52,822)

Distributions		—	—		—	—		—	—		—	—		—		—		(1,032)		(1,032)

Dividend to Class A common stock		—	—		—	—		—	—		—	—		—		(9,115)		—		(9,115)
Equity based compensation		—	—		—	—		—	—		—	—		9,805		—		5,839		15,644


Change in deferred taxes related to basis differences associated with the Equity Issuance		—	—		—	—		—	—		—	—		(13,122)		—		—		(13,122)
Change in equity associated with the Equity Issuance		12,650	1		—	—		—	—		—	—		209,166		—		—		209,167
Balance at September 30, 2023		88,609	$	9	91,048	$	9	1	$	—	1,071	$	(17,143)	$	1,567,967	$	50,906	$	25,330	$	1,627,078

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

CRESCENT ENERGY COMPANY

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)

(in thousands)


	Nine Months Ended September 30,
		2023		2022
Cash flows from operating activities:
Net income (loss)		$	181,983	$	431,240
Adjustments to reconcile net income (loss) to net cash provided by operating activities
Depreciation, depletion and amortization		492,879		375,600
Deferred income tax expense (benefit)		3,988		27,428
(Gain) loss on derivatives		68,211		645,565
Net cash (paid) received on settlement of derivatives		(110,775)		(654,377)
Non-cash equity-based compensation expense		64,648		26,306
Amortization of debt issuance costs and discount		9,175		6,431
(Gain) loss on sale of oil and natural gas properties		—		(5,114)
Restructuring of acquired derivative contracts		—		(51,994)
Settlement of acquired derivative contracts		(48,977)		(39,046)
Other		(17,332)		(6,941)
Changes in operating assets and liabilities:
Accounts receivable		(105,430)		(189,512)
Accounts receivable – affiliates		1,310		18,809
Prepaid and other current assets		(10,587)		(22,011)
Accounts payable and accrued liabilities		67,396		213,428
Accounts payable – affiliates		12,741		24,560
Other		3,670		(3,018)
Net cash provided by operating activities		612,900		797,354
Cash flows from investing activities:
Development of oil and natural gas properties		(471,275)		(440,375)
Acquisitions of oil and natural gas properties		(622,698)		(627,539)
Proceeds from the sale of oil and natural gas properties		24,356		4,800
Purchases of restricted investment securities – HTM		(10,651)		(7,175)
Maturities of restricted investment securities – HTM		10,722		5,400
Other		3,308		3,955
Net cash used in investing activities		(1,066,238)		(1,060,934)
Cash flows from financing activities:
Proceeds from the issuance of Senior Notes, after premium, discount and underwriting fees		833,500		199,250
Revolving Credit Facility borrowings		1,678,000		1,118,000
Revolving Credit Facility repayments		(1,845,449)		(976,000)
Payment of debt issuance costs		(5,461)		(20,028)


Proceeds from the Equity Issuance after underwriting fees		145,665		—
Payment of Equity Issuance costs		(2,340)		—
Redeemable noncontrolling interest contributions		1,238		5,985
Redeemable noncontrolling interest distributions		(417)		—
Dividend to Class A common stock		(23,127)		(19,301)
Distributions to redeemable noncontrolling interests related to Class A common stock dividend		(45,333)		(58,705)
Distributions to redeemable noncontrolling interests related to Manager Compensation		(26,207)		(22,779)
Contributions from (distributions to) redeemable noncontrolling interests related to income taxes		4		(17,970)
Repurchase of redeemable noncontrolling interests related to Equity Transactions		—		(36,220)
Repurchase of noncontrolling interest		—		(4,060)
Noncontrolling interest distributions		(3,549)		(6,326)
Noncontrolling interest contributions		1,771		55
Cash paid for treasury stock acquired for equity-based compensation tax withholding		(72)		—
Other		(2,855)		(3,784)
Net cash provided by financing activities		705,368		158,117
Net change in cash, cash equivalents and restricted cash		252,030		(105,463)
Cash, cash equivalents and restricted cash, beginning of period		15,304		135,117
Cash, cash equivalents and restricted cash, end of period		$	267,334	$	29,654

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

CRESCENT ENERGY COMPANY

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

(Except as noted within the context of each footnote disclosure, the dollar amounts presented in the tabular data within these footnote disclosures are stated in thousands of dollars.)

Unless otherwise stated or the context otherwise indicates, all references to “we,” “us,” “our,” "Crescent" and the “Company” or similar expressions refer to Crescent Energy Company and its subsidiaries.

NOTE 1 – Organization and Basis of Presentation

Organization

Crescent is a growth-oriented U.S. independent energy company engaged in the acquisition, development and operation of oil and natural gas properties. Crescent’s portfolio of low-decline, cash-flow oriented assets comprises both mid-cycle unconventional and conventional assets with a long reserve life and deep inventory of low-risk, high-return development locations in the Eagle Ford and Uinta Basins. Crescent’s leadership is an experienced team of investment, financial and industry professionals that combines proven investment and operating expertise. For more than a decade, Crescent and its predecessors have executed on a consistent growth through acquisition strategy focused on cash flow, risk management and returns.

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," together with Class A Common Stock, "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”). Additionally, an affiliate of KKR & Co. Inc. ("KKR," and 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.

Equity Issuance

In September 2023, we conducted an underwritten public offering of 12.7 million shares of Class A Common Stock at a price to the public of $12.25 per share (not including underwriter discounts and commissions). This includes 1.7 million shares of Class A Common Stock that were issued upon the underwriters exercise of their 30-day option to purchase additional shares to cover over-allotments pursuant to the related underwriting agreement. Following the closing of these transactions (the "Equity Issuance"), shares of our Class A Common Stock represent approximately 49% of our outstanding shares of Common Stock. We received net proceeds of $145.7 million from the Equity Issuance, after deducting underwriting fees and expenses.

Class A Conversion

On June 30, 2023, an affiliate of KKR redeemed approximately 27.6 million OpCo Units (and we cancelled a corresponding number of shares of Class B Common Stock) for an equivalent number of shares of Class A Common Stock (the "Class A Conversion") and subsequently distributed such shares to certain of its legacy investors in privately-managed funds and accounts on July 3, 2023. We did not receive any proceeds or incur any material expenses associated with the Class A Conversion.

Equity Transactions

In September 2022, Independence Energy Aggregator L.P., the entity through which certain affiliated entities hold their interests in us, exchanged 6.3 million units representing membership interests in OpCo (together with a corresponding number of shares of our Class B Common Stock) for shares of our Class A Common Stock and agreed to sell 5.8 million shares of our Class A Common Stock at a price to the public of $15.00 per share, or a net price of $14.10 per share after deducting the underwriters' discounts and commissions (the "Offering"). We did not receive any cash proceeds from the Offering. Concurrent

with the closing of the Offering, we repurchased an aggregate of approximately 2.6 million OpCo Units from PT Independence Energy Holdings LLC for $36.2 million and cancelled a corresponding number of shares of our Class B Common Stock (the "Concurrent OpCo Unit Purchase," and, together with the Offering, the "Equity Transactions"). As a result of the Equity Transactions, the total number of shares of our Class A Common Stock increased by 6.3 million shares, including 0.6 million shares of our Class A Common Stock that were not included as part of the Offering but rather issued in exchange for shares of Class B Common Stock and distributed in-kind by Independence Energy Aggregator L.P. to affiliates, and the number of shares of our Class B Common Stock decreased by approximately 8.9 million. Redeemable noncontrolling interests decreased by $158.1 million while APIC increased by $121.8 million as a result of the Equity Transactions and to reflect the new ownership of OpCo.

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 September 30, 2023 is owned approximately 49% by Crescent and approximately 51% by holders of our redeemable noncontrolling interests, and (ii) Crescent Energy Finance LLC, OpCo's wholly owned subsidiary. Crescent and OpCo have no operations, or material cash flows, assets or liabilities other than their investment in Crescent Energy Finance LLC. The assets and liabilities of OpCo represent substantially all of our consolidated assets and liabilities with the exception of certain current and deferred taxes and certain liabilities under the Management Agreement (as defined within NOTE 11 – Related Party Transactions). Certain restrictions and covenants related to the transfer of assets from OpCo are discussed further in NOTE 7 – Debt.

The financial statements include undivided interests in oil and natural gas properties. We account for our share of oil and natural gas properties by reporting our proportionate share of assets, liabilities, revenues, costs and cash flows within the accompanying condensed consolidated balance sheets, condensed consolidated statements of operations, and condensed consolidated statements of cash flows.

NOTE 2 – Summary of Significant Accounting Policies

Use of Estimates

The preparation of financial statements in conformity with GAAP requires management to make use of estimates and assumptions that affect the reported amount of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. We use historical experience and various other assumptions and information that are believed to be reasonable under the circumstances in developing our estimates and judgments. Estimates and assumptions about future events and their effects cannot be predicted with certainty and, accordingly, these estimates may change as new events occur, as more experience is acquired, as additional information is obtained and as our operating environment changes. While we believe that the estimates and assumptions used in the preparation of the financial statements are appropriate, actual results may differ from these estimates. Our significant estimates include the fair value of acquired assets and liabilities, oil and natural gas reserves, impairment of proved and unproved oil and natural gas properties 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 as of September 30, 2023 is composed of (i) our deposit for the October Western Eagle Ford Acquisition and (ii) cash that is contractually required to be restricted to pay for the future abandonment of certain wells in California. Restricted cash is included in Restricted cash 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 September 30,
	2023		2022
	(in thousands)
Cash and cash equivalents	$	228,614	$	22,478
Restricted cash – current	33,422		—
Restricted cash – noncurrent	5,298		7,176
Total cash, cash equivalents and restricted cash	$	267,334	$	29,654

Redeemable Noncontrolling Interests

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

In September 2023, the proceeds from the Equity Issuance, including the exercise of the underwriters' over-allotment, were contributed by Crescent to OpCo in exchange for 12.7 million OpCo Units. As a result of the additional OpCo Units owned by Crescent, we reclassified $65.8 million from Redeemable noncontrolling interests to Additional paid-in capital.

In June 2023, the Class A Conversion reduced the number of shares of our Class B Common Stock outstanding by 27.6 million shares. A corresponding number of OpCo Units were transferred to Crescent, which reduced the value of our redeemable noncontrolling interests by $618.7 million.

From December 31, 2022 through September 30, 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
Net income attributable to redeemable noncontrolling interests	52,067
Contributions	709
Distributions	(417)
Distributions from OpCo related to Class A common stock dividend, Manager compensation and income taxes, net	(14,098)
Accrued OpCo distribution	(7,264)
Equity-based compensation	19,629

Change in redeemable noncontrolling interests associated with the Class A Conversion	(618,732)
Balance as of June 30, 2023	$	2,039,063
Net income attributable to redeemable noncontrolling interests	(78,280)
Contributions	529

Distributions from OpCo related to Class A common stock dividend, Manager compensation and income taxes, net	(10,962)
Accrued OpCo distribution	(7,030)
Equity-based compensation	11,383

Change in redeemable noncontrolling interests associated with the Equity Issuance	(65,841)

Balance as of September 30, 2023	$	1,888,862

Income Taxes

Crescent is a holding company, the sole material asset of which consists of 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 income taxes on its allocable share of any taxable income of OpCo. For the three and nine months ended September 30, 2023, we recognized income tax benefit of $20.6 million and income tax expense of $4.9 million for an effective tax rate of 13.6% and 2.6%, respectively. For the three and nine months ended September 30, 2022, we recognized income tax expense of $38.5 million and $34.5 million for an effective tax rate of 6.5% and 7.4%, 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 U.S. federal net operating loss ("NOL") carryforwards and recognized built-in-loss ("RBIL") property which are subject to limitation under Section 382. Pursuant to Sections 382 and 383 of the Internal Revenue Code, utilization of our NOL and RBIL carryforwards is subject to a small annual limitation. These annual limitations may result in the expiration of NOL and RBIL carryforwards prior to utilization and accordingly we have maintained a valuation allowance related to U.S. federal NOL and RBIL carryforwards that we do not believe are recoverable due to these Section 382 limitations.

During the three and nine months ended September 30, 2023, we decreased APIC by $13.1 million and $82.8 million, respectively, due to the change in our ownership interests and basis in OpCo as a result of the Equity Issuance and Class A Conversion. As of September 30, 2023 and December 31, 2022, we did not have any uncertain tax positions.

Supplemental Cash Flow Disclosures

The following are our supplemental cash flow disclosures for the nine months ended September 30, 2023 and 2022:


	Nine Months Ended September 30,
		2023		2022
	(in thousands)
Supplemental cash flow disclosures:
Interest paid, net of amounts capitalized		$	83,918	$	44,072
Income tax (refunds) payments		(1,430)		7,864
Non-cash investing and financing activities:
Capital expenditures included in accounts payable and accrued liabilities		$	71,543	$	78,080


Right-of-use assets obtained in exchange for leases		23,756		8,365

NOTE 3 – Acquisitions and Divestitures

Western Eagle Ford Acquisitions

In July 2023, we consummated the acquisition contemplated by the Purchase and Sale Agreement, dated as of May 2, 2023, between our subsidiary and Comanche Holdings, LLC ("Comanche Holdings") and SN EF Maverick, LLC ("SN EF Maverick," and together with Comanche Holdings, the "Seller"), pursuant to which we agreed to acquire operatorship and incremental working interests (the "July Western Eagle Ford Acquisition") in certain of our existing Western Eagle Ford assets from the Seller for aggregate cash consideration of approximately $593.4 million, including customary purchase price adjustments. We accounted for the July Western Eagle Ford Acquisition as an asset acquisition and recorded additional Property, plant and equipment of $612.7 million, Other current assets of $2.6 million, Accounts payable of $4.6 million, Other current liabilities of $5.0 million, asset retirement liability of $10.5 million and Other liabilities of $1.8 million.

In October 2023, we consummated the unrelated acquisition contemplated by the Purchase and Sale Agreement, dated as of August 22, 2023, between our subsidiary and an unaffiliated third party, pursuant to which we agreed to acquire certain incremental working interests in oil and natural gas properties (the "October Western Eagle Ford Acquisition," and together with the July Western Eagle Ford Acquisition, the "Western Eagle Ford Acquisitions") in certain of our existing Western Eagle Ford assets from the seller for aggregate cash consideration of approximately $250.0 million, subject to customary purchase price adjustments. The October Western Eagle Ford Acquisition is expected to be accounted for as an asset acquisition in the fourth quarter of 2023.

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 of the development and production assets formerly held by EP Energy E&P Company, L.P. in the State of Utah and certain related obligations. 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.

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

As of September 30, 2023, our commodity derivative instruments consisted of fixed price and basis swaps and collars which are described below:

Fixed Price and Basis Swaps: Fixed price swaps receive a fixed price and pay a floating market price to the counterparty on the notional amount. Our basis swaps fix the basis differentials between the index price at which we sell our production as compared to the index price used in the basis swap. Under a swap contract, we will receive payment if the settlement price is less than the fixed price and will 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. A portion of our collars give the counterparty an option to cancel the collar prior to the production period as indicated below.

The following table details our net volume positions by commodity as of September 30, 2023:


Production Period	Volumes	Weighted Average Fixed Price			Fair Value
Crude oil swaps (Bbls):	(in thousands)				(in thousands)
WTI
2023	3,863	$66.26			$	(83,570)
2024	12,021	$67.58			(153,035)

Brent
2023	133	$52.52			(4,950)
2024	276	$68.65			(4,253)

Crude oil collars – WTI (Bbls):
2023	721	$55.64	-	$74.16	(10,764)
2024	3,588	$64.62	-	$79.54	(14,666)
2025 (1)	1,460	$60.00	-	$85.00	(6,909)
Crude oil collars – Brent (Bbls):

2024	110	$65.00	-	$100.00	15
2025	365	$65.00	-	$91.61	(90)
Natural gas swaps (MMBtu):
2023	23,105	$2.97			(603)
2024	41,080	$3.69			12,092

Natural gas collars (MMBtu):

2024	18,300	$3.38	-	$4.56	5,099
2025	29,565	$3.00	-	$5.65	(1,236)



Crude oil basis swaps (Bbls):
2023	2,024	$1.28			253
2024	6,862	$1.49			367
Natural gas basis swaps (MMBtu):
2023	7,783	$(0.27)			11
2024	10,473	$(0.08)			(334)
Calendar Month Average ("CMA") roll swaps (Bbls):
2023	2,070	$0.28			(3,245)
2024	6,862	$0.36			(4,474)



Total					$	(270,292)

(1) Represents outstanding crude oil collar options exercisable by the counterparty until December 16, 2024.

We use derivative commodity instruments and enter into swap contracts that are governed by International Swaps and Derivatives Association ("ISDA") master agreements. The following table shows the effects of master netting arrangements on the fair value of our derivative contracts as of September 30, 2023 and December 31, 2022:


	Gross Fair Value		Effect of Counterparty Netting		Net Carrying Value
	(in thousands)
September 30, 2023
Assets:
Derivative assets – current	$	35,699	$	(31,421)	$	4,278
Derivative assets – noncurrent	22,261		(22,261)		—
Total assets	$	57,960	$	(53,682)	$	4,278
Liabilities:
Derivative liabilities – current	$	(274,620)	$	31,421	$	(243,199)
Derivative liabilities – noncurrent	(53,632)		22,261		(31,371)
Total liabilities	$	(328,252)	$	53,682	$	(274,570)

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 and nine months ended September 30, 2023 and 2022:


	Three Months Ended September 30,				Nine Months Ended September 30,
	2023		2022		2023		2022
	(in thousands)
Derivatives not designated as hedging instruments:
Realized gain (loss) on oil positions	$	(61,281)	$	(90,268)	$	(125,793)	$	(337,124)

Realized gain (loss) on natural gas positions	6,311		(115,595)		(3,545)		(259,070)
Realized gain (loss) on NGL positions	—		(5,849)		18,563		(58,183)

Total realized gain (loss) on derivatives	(54,970)		(211,712)		(110,775)		(654,377)
Unrealized gain (loss) on commodity hedges	(197,138)		416,842		42,564		8,812


Gain (loss) on derivatives	$	(252,108)	$	205,130	$	(68,211)	$	(645,565)

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 September 30, 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)
September 30, 2023
Financial assets:
Derivative assets	$	—	$	57,960	$	—	$	57,960
Financial liabilities:
Derivative liabilities	$	—	$	(328,252)	$	—	$	(328,252)

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 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 herein) was approximately $1,553.0 million and $661.5 million as of September 30, 2023 and December 31, 2022, respectively, based on quoted market prices.

NOTE 6 – Accounts Payable and Accrued Liabilities

Accounts payable and accrued liabilities consisted of the following as of September 30, 2023 and December 31, 2022:


	September 30, 2023		December 31, 2022
	(in thousands)
Accounts payable and accrued liabilities:
Accounts payable	$	105,675	$	104,343
Accrued lease and asset operating expense	70,026		58,375

Accrued capital expenditures	48,701		76,246
Accrued general and administrative expense	18,490		13,688
Accrued transportation expense	62,744		31,525
Accrued revenue and royalties payable	161,437		160,775
Accrued interest expense	32,751		11,672
Accrued severance taxes	53,966		55,496
Other	11,472		12,570
Total accounts payable and accrued liabilities	$	565,262	$	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 "Original 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).

In July 2023, we issued an additional $300.0 million aggregate principal amount of 2028 Notes (the "July 2028 Notes"). The proceeds of the offering were approximately $287.5 million, after deducting the initial purchasers' discount and offering expenses, but excluding accrued interest payable by purchasers of the July 2028 Notes, which we used to repay a portion of outstanding borrowings under our Revolving Credit Facility.

In September 2023, we issued an additional $150.0 million aggregate principal amount of 2028 Notes (the "September 2028 Notes," and together with the Original 2028 Notes and the July 2028 Notes, the "2028 Notes"). The proceeds of the offering were approximately $148.0 million after deducting the initial purchasers' discount and offering expenses, but excluding accrued interest payable by purchasers of the September 2028 Notes, which we used to repay a portion of outstanding borrowings under our Revolving Credit Facility. The July 2028 Notes and the September 2028 Notes are treated as a single series of securities under the indenture governing the Original 2028 Notes, will vote together as a single class with the Original 2028 Notes, and have substantially identical terms, other than the issue date and the issue price, as the Original 2028 Notes.

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

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 a secured overnight financing rate (“SOFR”) 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.

In connection with the closing of the July Western Eagle Ford Acquisition, we redetermined our Revolving Credit Facility, which reaffirmed our borrowing base at $2.0 billion with an elected commitment amount of $1.3 billion. At September 30, 2023, we had $392.0 million of borrowings and $11.4 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 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 0.5% 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 September 30, 2023 and December 31, 2022 was 8.00% 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 September 30, 2023 and December 31, 2022, we had letters of credit outstanding of $11.4 million and $9.8 million, respectively, which reduce the amount available to borrow under our Revolving Credit Facility.

Total Debt Outstanding

The following table summarizes our debt balances as of September 30, 2023 and December 31, 2022:


	Debt Outstanding		Letters of Credit Issued		Borrowing Base		Maturity
	(in thousands)
September 30, 2023
Revolving Credit Facility	$	392,000	$	11,419	$	2,000,000	9/23/2027
7.25% Senior Notes due 2026	700,000		—		—		5/1/2026
9.25% Senior Notes due 2028	850,000		—		—		2/15/2028
Less: Unamortized discount, premium and issuance costs	(29,813)
Total long-term debt	$	1,912,187

December 31, 2022
Revolving Credit Facility	$	559,449	$	9,770	$	2,000,000	9/23/2027
7.25% Senior Notes due 2026	700,000		—		—		5/1/2026
Less: Unamortized discount, premium and issuance costs	(11,891)
Total long-term debt	$	1,247,558

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 nine months ended September 30, 2023:


	As of September 30, 2023
	(in thousands)
Balance at beginning of period	$	365,614

Additions(1)	16,272
Retirements	(8,835)
Sale	(1,627)
Revisions	1,681
Accretion expense	20,477
Balance at end of period	393,582
Less: current portion	(21,010)
Balance at end of period, noncurrent portion	$	372,572

(1) For the nine months ended September 30, 2023, our ARO additions primarily related to properties acquired in the July Western Eagle Ford Acquisition. See NOTE 3 – Acquisitions and Divestitures for additional information.

NOTE 9 – Commitments and Contingencies

From time to time, we may be a plaintiff or defendant in a pending or threatened legal proceeding arising in the normal course of business. In accordance with ASC 450, Contingencies, an accrual is recorded for a material loss contingency when its occurrence is probable and damages are reasonably estimable based on the anticipated most likely outcome or the minimum amount within a range 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 September 30, 2023.

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. The following table summarizes compensation expense we recognized in connection with our incentive compensation awards for the periods indicated:


	Three Months Ended September 30,				Nine Months Ended September 30,
	2023		2022		2023		2022
	(in thousands)
ASC 710 profits interest awards	$	116	$	334	$	2,288	$	834
ASC 718 liability-classified profits interest awards	2,465		(2,321)		(14)		9,892
ASC 718 equity-classified profits interest awards	5,839		—		9,510		—
ASC 718 equity-classified RSU awards	405		399		1,196		793
ASC 718 equity-classified PSU awards	20,783		7,758		53,956		15,621
Total expense	$	29,608	$	6,170	$	66,936	$	27,140

Equity-classified RSU Awards

During the nine months ended September 30, 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. In addition, during the three and nine months ended September 30, 2023 we had 85,827 shares vest related to outstanding RSU awards.

Equity-classified PSU Awards

During the three and nine months ended September 30, 2023, in conjunction with the Equity Issuance, Class A Conversion and RSU award vesting, the number of shares of our Class A Common Stock increased by 12.7 million and 40.3 million shares, respectively. As a result, the number of equity-classified PSU target Class A Shares granted under the Crescent Energy Company 2021 Manager Incentive Plan increased by 1.3 million and 4.0 million shares for the three and nine months ended September 30, 2023, respectively. We accounted for this increase as a change in estimate and recognized additional expense of $9.7 million and $27.7 million for the three and nine months ended September 30, 2023, respectively.

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 an annual $55.5 million fee. The amount borne by us 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) and increased by $2.2 million during the three months ended September 30, 2023 in conjunction with our Equity Issuance. However, incremental Manager Compensation will not apply to the issuance of our shares upon the redemption or exchange of OpCo Units. During the three and nine months ended September 30, 2023, we recorded general and administrative expense of $6.8 million and $16.8 million, respectively, and made cash distributions of $7.3 million and $26.2 million, respectively, to our redeemable noncontrolling interests related to the Management Agreement. In addition, at September 30, 2023 we accrued $7.0 million distribution to redeemable noncontrolling interests that will be paid during the fourth quarter of 2023. During the three and nine months ended September 30, 2022, we recorded general and administrative expense of $3.8 million and $10.4 million, respectively, and made cash distributions of $10.0 million and $22.8 million, respectively, to our redeemable noncontrolling interests related to the Management

Agreement. At September 30, 2023 and December 31, 2022, we had $13.9 million and $13.3 million, respectively, 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 and nine months ended September 30, 2023, we recorded general and administrative expense of $20.8 million and $54.0 million, respectively, related to Incentive Compensation. During the three and nine months ended September 30, 2022, we recorded general and administrative expense of $7.8 million and $15.6 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 ("MSA") with entities owned by KKR Funds, pursuant to which our subsidiaries provide certain services to such KKR Funds, including the allocation of the production and sale of oil, natural gas and NGLs, collection and disbursement of revenues, operating expenses and general and administrative expenses in the respective oil and natural gas properties, and the payment of all capital costs associated with the ongoing operations of the oil and natural gas assets. Our subsidiaries settle balances due to or due from KKR Funds on a monthly basis. The administrative costs associated with these MSAs are allocated by us to KKR Funds based on (i) an actual basis for direct expenses we may incur on their behalf or (ii) an allocation of such charges between the various KKR Funds based on the estimated use of such services by each party. As of September 30, 2023 and December 31, 2022, we had a related party receivable of $0.1 million and $0.8 million, respectively, included within Accounts receivable – affiliates and a related party payable of $23.1 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 and nine months ended September 30, 2023, we incurred $1.5 million and $2.6 million, respectively, in fees to KKR Capital Markets LLC ("KCM"), an affiliate of KKR Group, in connection with transactions relating to the 2028 Notes, respectively. During the nine months ended September 30, 2022, we incurred $0.7 million in fees to KCM in connection with transactions relating to the 2026 Notes. We recorded these fees as debt issuance costs within Long-term debt on the condensed consolidated balance sheets. During the nine months ended September 30, 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.

During the three and nine months ended September 30, 2023, we paid KCM $2.2 million in underwriter discounts and commissions in connection with the Equity Issuance. During the three and nine months ended September 30, 2022, KCM received $1.3M from the proceeds of the transactions in underwriter discounts and commissions in connection with the Equity Transactions. We did not receive any cash proceeds. Refer to further discussion in NOTE 1 – Organization and Basis of Presentation regarding the Equity Transactions.

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 $0.3 million, increasing over the term of the lease, and the payment by one of our subsidiaries of certain other customary expenses. Upon lease commencement in April 2023, we recorded a $2.4 million right-of-use asset in Other assets, an operating lease liability of $0.1 million in Other current liabilities and $2.3 million in Other liabilities on the condensed consolidated balance sheets.

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 and nine months ended September 30, 2022 that were antidilutive.

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


	Three Months Ended September 30,				Nine Months Ended September 30,
	2023		2022		2023		2022
	(in thousands, except share and per share amounts)
Numerator:
Net income (loss)	$	(131,102)	$	555,349	$	181,983	$	431,240

Less: net (income) loss attributable to noncontrolling interests	(48)		(904)		(453)		(2,087)
Less: net (income) loss attributable to redeemable noncontrolling interests	78,280		(436,084)		(169,455)		(341,269)
Net income (loss) attributable to Crescent Energy - basic	(52,870)		118,361		12,075		87,884
Add: Reallocation of net income attributable to redeemable noncontrolling interest for the dilutive effect of RSUs	—		33		27		10
Add: Reallocation of net income attributable to redeemable noncontrolling interest for the dilutive effect of PSUs	—		—		306		—
Net income (loss) attributable to Crescent Energy - diluted	$	(52,870)	$	118,394	$	12,408	$	87,894
Denominator:
Weighted-average Class A common stock outstanding – basic	78,708,800		43,196,791		58,663,396		42,376,668
Add: dilutive effect of RSUs	—		13,524		39,016		5,173
Add: dilutive effect of PSUs	—		—		439,335		—
Weighted-average Class A common stock outstanding – diluted	78,708,800		43,210,315		59,141,747		42,381,841
Weighted-average Class B common stock outstanding – basic and diluted	91,048,124		125,796,892		109,244,079		126,950,234
Net income (loss) per share:
Class A common stock – basic	$	(0.67)	$	2.74	$	0.21	$	2.07
Class A common stock – diluted	$	(0.67)	$	2.74	$	0.21	$	2.07
Class B common stock – basic and diluted	$	—	$	—	$	—	$	—

NOTE 13 – Subsequent Events

Dividend

On November 6, 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 third quarter of 2023. The quarterly dividend is payable on December 4, 2023 to shareholders of record as of the close of business on November 20, 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.

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"), our Quarterly Report on Form 10-Q for the periods ended March 31, 2023 and June 30, 2023, as well as our unaudited condensed consolidated financial statements for the three and nine months ended September 30, 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 and nine months ended September 30, 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. Unless otherwise stated or the context otherwise indicates, all references to “we,” “us,” “our,” "Crescent" and the “Company” or similar expressions refer to Crescent Energy Company and its subsidiaries.

Business

We are a growth-oriented U.S. independent energy company engaged in the acquisition, development and operation of oil and natural gas properties. Our portfolio of low-decline, cash-flow oriented assets comprises both mid-cycle unconventional and conventional assets with a long reserve life and deep inventory of low-risk, high-return development locations in the Eagle Ford and Uinta Basins.

Our leadership is an experienced team of investment, financial and industry professionals that combines proven investment and operating expertise. For more than a decade, Crescent and its predecessors have executed on a consistent growth through acquisition strategy focused on cash flow, risk management and returns.

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, Hamas' attack against Israel and the ensuing conflict in the Middle East, 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 2023, OPEC announced production cuts to reduce the global oil supply. 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.

Continuing 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 and into 2023. 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 July 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. 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 is expected to be collected in 2025 based on calendar year 2024 emissions 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.

Acquisitions and divestitures

Acquisitions

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. 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.

Divestitures

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 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.

Sustainability

We seek to strategically improve assets we own and acquire to deliver enhanced financial returns, operations and stewardship. We believe that being a responsible operator will produce better outcome, creating a net benefit for society and the environment, while delivering attractive returns for our investors. We view exceptional sustainability performance as an opportunity to differentiate Crescent from its peers, mitigate risks and strengthen operational performance as well as benefit our stakeholders and the communities in which we operate. We invite you to review our 2022 Sustainability Report, which is available on Crescent’s website at https://www.crescentenergyco.com/#sustainability. However, please note that the contents of this Sustainability 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 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 $580 million to $630 million for our 2023 capital program, reflecting the additional capital directed to the Western Eagle Ford Acquisitions. 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 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 September 30,				Nine Months Ended September 30,
	2023		2022		2023		2022
Oil	80	%	64	%	75	%	66	%
Natural gas	11	%	28	%	17	%	25	%
NGLs	9	%	8	%	8	%	9	%

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 and nine months ended September 30, 2023 and 2022.

Production volumes sold

The following table presents historical sales volumes for our properties:


	Three Months Ended September 30,		Nine Months Ended September 30,
	2023	2022	2023	2022
Oil (MBbls)	6,667	6,348	17,797	16,114
Natural gas (MMcf)	33,009	33,735	95,085	96,102
NGLs (MBbls)	2,271	1,840	5,730	5,452
Total (MBoe)	14,440	13,811	39,375	37,583
Daily average (MBoe/d)	157	150	144	138

Total sales volume increased 629 MBoe and increased 1,792 MBoe during the three and nine months ended September 30, 2023, respectively, compared to the three and nine months ended September 30, 2022. Our third quarter 2023 total production increase was driven by our July Western Eagle Ford Acquisition partially offset by a slight natural gas production decrease driven by downtime at a natural gas processing plant. For the nine months ended September 30, 2023 compared to the same period in 2022, our total production increase was driven by our July Western Eagle Ford Acquisition and our Uinta Transaction.

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, the Israel-Hamas conflict, 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 conflicts in Ukraine and Israel. Additionally, natural gas prices have declined in 2023 due in part to relatively mild winter and extended downtime at a liquified natural gas export facility, which has caused high levels of U.S. gas storage compared with historical averages. Finally, 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 2023 as compared to the prior period.

In order to reduce the impact of fluctuations in oil and natural gas prices on revenues, we regularly enter into derivative contracts with respect to a portion of the estimated oil, natural gas and NGL production through various transactions that fix the future prices received. We plan to continue the practice of entering into economic hedging arrangements to reduce near-term exposure to commodity prices, protect cash flow and corporate returns and maintain our liquidity.

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


	Three Months Ended September 30,				Nine Months Ended September 30,
	2023		2022		2023		2022
Oil	64	%	58	%	62	%	65	%
Natural gas	54	%	61	%	55	%	67	%
NGLs	—	%	42	%	24	%	47	%

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 September 30,				Nine Months Ended September 30,
	2023		2022		2023		2022
Oil (Bbl):
Average NYMEX	$	82.26	$	91.56	$	77.39	$	98.09
Realized price (excluding derivative settlements)	75.70		86.77		71.37		94.69
Realized price (including derivative settlements) (1)	66.50		72.55		64.31		73.77
Natural Gas (Mcf):
Average NYMEX	$	2.55	$	8.20	$	2.69	$	6.77
Realized price (excluding derivative settlements)	2.18		6.99		3.01		6.10
Realized price (including derivative settlements)	2.38		3.56		2.97		3.41
NGLs (Bbl):
Realized price (excluding derivative settlements)	$	24.10	$	35.22	$	22.88	$	40.33
Realized price (including derivative settlements)	24.10		32.04		26.12		29.65

(1) The realized price presented above does not include the $14.0 million or $49.0 million impact from the settlement of acquired derivative contracts for the three and nine months ended September 30, 2023, respectively and does not include the $15.9 million or $ 39.0 million impact from the settlement of acquired derivative contracts for the three and nine months ended September 30, 2022, respectively.

Results of operations:

Three Months Ended September 30, 2023 Compared to Three Months Ended September 30, 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 September 30,
	2023		2022		$ Change		% Change
Revenues (in thousands):
Oil	$	504,660	$	550,823	$	(46,163)	(8)	%
Natural gas	72,097		235,830		(163,733)		(69)	%
Natural gas liquids	54,724		64,810		(10,086)		(16)	%
Midstream and other	10,917		13,494		(2,577)		(19)	%
Total revenues	$	642,398	$	864,957	$	(222,559)	(26)	%
Average realized prices, before effects of derivative settlements:
Oil ($/Bbl)	$	75.70	$	86.77	$	(11.07)	(13)	%
Natural gas ($/Mcf)	2.18		6.99		(4.81)		(69)	%
NGLs ($/Bbl)	24.10		35.22		(11.12)		(32)	%
Total ($/Boe)	43.73		61.65		(17.92)		(29)	%
Net sales volumes:
Oil (MBbls)	6,667		6,348		319		5	%
Natural gas (MMcf)	33,009		33,735		(726)		(2)	%
NGLs (MBbls)	2,271		1,840		431		23	%
Total (MBoe)	14,440		13,811		629		5	%
Average daily net sales volumes:
Oil (MBbls/d)	72		69		3		4	%
Natural gas (MMcf/d)	359		367		(8)		(2)	%
NGLs (MBbls/d)	25		20		5		25	%
Total (MBoe/d)	157		150		7		5	%

Oil revenue. Oil revenue decreased $46.2 million, or 8%, in the three months ended September 30, 2023, compared to the three months ended September 30, 2022. This was driven by lower realized oil prices that resulted in a decrease of $73.8 million (a decrease of 13% per Bbl), offset by a $27.6 million increase in daily sales volumes (3 MBbls/d, or 4%). Our net oil sales volumes increase was driven by our July Western Eagle Ford Acquisition.

Natural gas revenue. Natural gas revenue decreased $163.7 million, or 69%, in the three months ended September 30, 2023, compared to the three months ended September 30, 2022. This was driven by lower natural gas prices that resulted in a decrease of $158.7 million (a decrease of 69% per Mcf) and a $5.0 million decrease in sales volume (8 MMcf/d, or 2%). The decrease in sales volumes was primarily related to downtime at a gas processing plant and natural decline, partially offset by our July Western Eagle Ford Acquisition.

NGL revenue. NGL revenue decreased $10.1 million, or 16%, in the three months ended September 30, 2023, compared to the three months ended September 30, 2022. This was driven primarily by lower realized NGL prices that resulted in a decrease of $25.3 million (a decrease of 32% per Bbl) and a $15.2 million increase in sales volume (5 MBbls/d, or 25%). The increase in sales volumes was primarily related to our July Western Eagle Ford Acquisition.

Midstream and other revenue. Midstream and other revenue decreased $2.6 million, or 19%, in the three months ended September 30, 2023, compared to the three months ended September 30, 2022, driven primarily by lower sulfur revenues offset by additional oil blending revenue in 2023.

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:


	Three Months Ended September 30,
	2023		2022		$ Change		% Change
Expenses (in thousands):
Operating expense	$	270,541	$	283,289	$	(12,748)	(4)	%
Depreciation, depletion and amortization	186,492		145,008		41,484		29	%
General and administrative expense	43,831		17,311		26,520		153	%
Other operating costs	—		1,782		(1,782)		NM*
Total expenses	$	500,864	$	447,390	$	53,474	12	%
Selected expenses per Boe:
Operating expense	$	18.74	$	20.51	$	(1.77)	(9)	%


Depreciation, depletion and amortization	12.91		10.50		2.41		23	%

* NM = Not meaningful.

Operating expense. Operating expense decreased $12.7 million, or 4%, in the three months ended September 30, 2023, compared to the three months ended September 30, 2022, driven primarily by the following factors:

(i)Lease and asset operating expense increased $5.6 million, or 4%, in the three months ended September 30, 2023, compared to the three months ended September 30, 2022, and decreased $0.07 per Boe, or 1%, to $10.24 per Boe. This $5.6 million increase was driven primarily by expenses related to our July Western Eagle Ford Acquisition. Our additional Eagle Ford expenses were offset by certain costs that are indexed to oil commodity prices, such as CO2 purchase costs related to our CO2 flood asset in Wyoming. These contractually commodity indexed operating expenses move in tandem with oil commodity prices, and as oil price increases, commodity-linked contractual operating costs increase, and vice versa.

(ii)Gathering, transportation and marketing expense increased $17.0 million, or 38%, in the three months ended September 30, 2023, compared to the three months ended September 30, 2022, and increased $1.03 per Boe, or 32%, to $4.27 per Boe. The increase was driven by our July Western Eagle Ford Acquisition and higher gathering and transportation rates on a portion of our Rockies assets.

(iii)Production and other taxes decreased $35.0 million, or 49%, in the three months ended September 30, 2023, compared to the three months ended September 30, 2022, and decreased $2.65 per Boe, or 51%, to $2.53 per Boe. This net decrease was driven primarily by decreased oil and gas revenues, which decreased the tax base on which our production and other taxes are calculated.

(iv)Workover expense decreased $5.0 million, or 24%, in the three months ended September 30, 2023, compared to the three months ended September 30, 2022, and decreased $0.41 per Boe, or 27%, to $1.12 per Boe. This decrease was driven by lower commodity price related activity.

(v)Midstream and other operating expense increased $4.7 million, or 134%, in the three months ended September 30, 2023, compared to the three months ended September 30, 2022, primarily due to increased crude oil blending expense in the Rockies. The additional expense is more than offset by additional oil blending revenue included as part of our Midstream and other revenue.

Depreciation, depletion and amortization. In the three months ended September 30, 2023, depreciation, depletion and amortization increased $41.5 million, or 29%, compared to the three months ended September 30, 2022, driven primarily by the July Western Eagle Ford Acquisition and additional volumes in some of our higher DD&A rate areas.

General and administrative expense. General and administrative expense ("G&A") increased $26.5 million, or 153%, for the three months ended September 30, 2023, compared to the three months ended September 30, 2022, primarily driven by (i) an increase in equity-based non-cash compensation expense of $23.7 million for the grant of additional PSUs related to the increase in shares of Class A Common Stock from the Equity Issuance (as defined herein), and (ii) $3.6 million higher recurring G&A mostly due to 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. The increase in Manager Compensation is due to an increase in public ownership of Class A Common Stock as a result of (i) our Equity Issuance, which also increased the annual Manager

Compensation by $2.2 million to $55.5 million annually and (ii) share redemptions for our Class A Common Stock completed in the second quarter of 2023 and the second half of 2022, which did not increase the overall Manager Compensation, but did increase the portion of the Manager Compensation borne by us. The portion of the Manager Compensation borne by us proportionately increases for share redemptions of our Class A Common Stock and increases for new share issuances of our Class A Common Stock. While only the portion of the 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 the amount presented in G&A is represented by “Certain-redeemable noncontrolling interest distributions made by OpCo related to Manager Compensation”).


	Three Months Ended September 30,
	2023		2022		$ Change		% Change
General and administrative expense (in thousands):
Recurring general and administrative expense	$	13,505	$	9,917	$	3,588	36	%
Transaction and nonrecurring expenses	834		1,558		(724)		(46)	%
Equity-based compensation	29,492		5,836		23,656		405	%
Total general and administrative expense	$	43,831	$	17,311	$	26,520	153	%
General and administrative expense per Boe:
Recurring general and administrative expense	$	0.94	$	0.72	$	0.22	31	%
Transaction and nonrecurring expenses	0.06		0.11		(0.05)		(45)	%
Equity-based compensation	2.04		0.42		1.62		386	%

Other operating costs. Other operating costs include exploration expense and gain on sale of assets. We did not incur any other operating costs during the three months ended September 30, 2023. During the three months ended September 30, 2022 our other operating costs were $1.8 million, primarily due to $1.9 million of exploration expense and a $0.1 million gain on sale of assets.

Interest expense

During the three months ended September 30, 2023, we incurred interest expense of $42.2 million, as compared to $27.1 million in the three months ended September 30, 2022, a 56% increase. This increase was driven primarily by higher average debt balances driven by the July Western Eagle Ford Acquisition and higher interest rates associated with the issuance of the July 2028 Notes and the September 2028 Notes and our Revolving Credit Facility.

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 September 30,
	2023		2022		$ Change		% Change
Gain (loss) on derivatives (in thousands):
Gain (loss) on commodity derivatives	$	(252,108)	$	205,130	$	(457,238)	(223)	%

Gain (loss) on derivatives	$	(252,108)	$	205,130	$	(457,238)	(223)	%

Our loss on commodity derivatives during the three months ended September 30, 2023 increased by $457.2 million, or 223%, from a comparable gain during the three months ended September 30, 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 September 30, 2023 and September 30, 2022, we recognized income tax benefit of $20.6 million and income tax expense of $38.5 million, respectively, for an effective tax rate of 13.6% and 6.5%, 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.

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 September 30,
	2023		2022		$ Change		% Change
(in thousands)
Net income (loss)	$	(131,102)	$	555,349	$	(686,451)	(124)	%
Adjustments to reconcile to Adjusted EBITDAX:
Interest expense	42,200		27,057

Income tax expense (benefit)	(20,639)		38,455
Depreciation, depletion and amortization	186,492		145,008
Exploration expense	—		1,909
Non-cash (gain) loss on derivatives	197,138		(416,842)
Non-cash equity-based compensation expense	29,492		5,836
(Gain) loss on sale of assets	—		(127)
Other (income) expense	(917)		2,670
Certain redeemable noncontrolling interest distributions made by OpCo related to Manager Compensation	(7,030)		(9,471)
Transaction and nonrecurring expenses (1)	7,989		8,861
Settlement of acquired derivative contracts	(13,999)		(15,945)
Adjusted EBITDAX (non-GAAP)	$	289,624	$	342,760	$	(53,136)	(16)	%
Adjustments to reconcile to Levered Free Cash Flow:
Interest expense, excluding non-cash deferred financing cost amortization	(35,373)		(24,552)

Current income tax benefit (expense)	470		877
Tax-related redeemable noncontrolling interest contributions (distributions) made by OpCo	(20)		(803)
Development of oil and natural gas properties	(94,431)		(189,928)
Levered Free Cash Flow (non-GAAP)	$	160,270	$	128,354	$	31,916	25	%

(1)Transaction and nonrecurring expenses of $8.0 million for the three months ended September 30, 2023 were primarily related to our Western Eagle Ford Acquisitions and costs associated with the series of transactions pursuant to which we indirectly combined the businesses of Contango Oil & Gas Company and Independence Energy LLC (the "Merger Transactions"). Transaction and nonrecurring expenses of $8.9 million for the three months ended September 30, 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 Merger Transactions, (ii) severance costs subsequent to the Merger Transactions, (iii) merger integration costs and (iv) acquisition and debt transaction related costs.

Adjusted EBITDAX decreased by $53.1 million, or 16%, in the three months ended September 30, 2023, compared to the three months ended September 30, 2022, primarily driven by lower realized oil and natural gas prices, partially offset by higher production and Adjusted EBITDAX generated by our July Western Eagle Ford Acquisition.

Levered Free Cash Flow increased by $31.9 million, or 25%, in the three months ended September 30, 2023 compared to the three months ended September 30, 2022, primarily driven by $95.5 million of decreased capital expenditures related to lower drilling and completion activity in the third quarter of 2023 than the same period in 2022 as well as higher service costs in 2022, partially offset by our decreased Adjusted EBITDAX.

Nine Months Ended September 30, 2023 Compared to Nine Months Ended September 30, 2022

Revenues

The following table provides the components of our revenues, respective average realized prices and net sales volumes for the periods indicated:


	Nine Months Ended September 30,
		2023		2022		$ Change		% Change
Revenues (in thousands):
Oil		$	1,270,244	$	1,525,899	$	(255,655)	(17)	%
Natural gas		286,172		586,318		(300,146)		(51)	%
Natural gas liquids		131,098		219,853		(88,755)		(40)	%
Midstream and other		37,360		40,231		(2,871)		(7)	%
Total revenues		$	1,724,874	$	2,372,301	$	(647,427)	(27)	%
Average realized prices, before effects of derivative settlements:
Oil ($/Bbl)		$	71.37	$	94.69	$	(23.32)	(25)	%
Natural gas ($/Mcf)		3.01		6.10		(3.09)		(51)	%
NGLs ($/Bbl)		22.88		40.33		(17.45)		(43)	%
Total ($/Boe)		42.86		62.05		(19.19)		(31)	%
Net sales volumes:
Oil (MBbls)		17,797		16,114		1,683		10	%
Natural gas (MMcf)		95,085		96,102		(1,017)		(1)	%
NGLs (MBbls)		5,730		5,452		278		5	%
Total (MBoe)		39,375		37,583		1,792		5	%
Average daily net sales volumes:
Oil (MBbls/d)		65		59		6		10	%
Natural gas (MMcf/d)		348		352		(4)		(1)	%
NGLs (MBbls/d)		21		20		1		5	%
Total (MBoe/d)		144		138		6		4	%

Oil revenue. Oil revenue decreased $255.7 million, or 17%, in the nine months ended September 30, 2023, compared to the nine months ended September 30, 2022. This was driven by lower realized oil prices that resulted in a decrease of $415.0 million (a decrease of 25% per Bbl), partially offset by a $159.3 million increase in sales volume (6 MBbls/d or 10%). Our oil production increase was primarily driven by our July Western Eagle Ford Acquisition and our Uinta Transaction.

Natural gas revenue. Natural gas revenue decreased $300.1 million, or 51%, in the nine months ended September 30, 2023, compared to the nine months ended September 30, 2022. This was driven by lower natural gas prices that resulted in a decrease of $293.8 million (a decrease of 51% per Mcf) and a $6.3 million decrease in sales volume (4 MMcf/d, or 1%). Our natural gas volumes were down primarily due to natural decline and downtime at a natural gas processing plant, but these decreases were partially offset by our July Western Eagle Ford Acquisition and our Uinta Transaction.

NGL revenue. NGL revenue decreased $88.8 million, or 40%, in the nine months ended September 30, 2023, compared to the nine months ended September 30, 2022. This was driven primarily by lower realized NGL prices that resulted in a decrease of $100.0 million (a decrease of 43% per Bbl) and a $11.2 million increase in sales volume (1 MBbls/d, or 5%). The increase in our NGL volumes was primarily driven by our July Western Eagle Ford Acquisition.

Midstream and other revenue. Midstream and other revenue decreased $2.9 million, or 7%, in the nine months ended September 30, 2023, compared to the nine months ended September 30, 2022 due to lower sulfur revenues offset by additional oil blending revenue in 2023.

Expenses


	Nine Months Ended September 30,
		2023		2022		$ Change		% Change
Expenses (in thousands):
Operating expense		$	768,080	$	758,241	$	9,839	1	%
Depreciation, depletion and amortization		492,879		375,600		117,279		31	%
General and administrative expense		106,235		59,489		46,746		79	%
Other operating costs		1,541		(1,266)		2,807		NM*
Total expenses		$	1,368,735	$	1,192,064	$	176,671	15	%
Selected expenses per Boe:
Operating expense		$	19.51	$	20.17	$	(0.66)	(3)	%


Depreciation, depletion and amortization		12.52		9.99		2.53		25	%

* NM = Not meaningful.

Operating expense. Operating expense increased $9.8 million, or 1%, in the nine months ended September 30, 2023, compared to the nine months ended September 30, 2022, driven primarily by the following factors:

(i)Lease and asset operating expense increased $52.6 million, or 14%, in the nine months ended September 30, 2023, compared to the nine months ended September 30, 2022, and increased $0.88 per Boe, or 9%, to $10.92 per Boe. This $52.6 million increase was driven primarily by higher production during the nine months ended September 30, 2023, due in part to (i) our July Western Eagle Ford Acquisition, (ii) our Uinta Transaction and (iii) 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 increased $29.4 million, or 22%, in the nine months ended September 30, 2023, compared to the nine months ended September 30, 2022, and increased $0.59 per Boe, or 17%, to $4.08 per Boe. This increase was driven primarily by the Uinta Transaction and our July Western Eagle Ford Acquisition.

(iii)Production and other taxes decreased $67.3 million, or 37%, in the nine months ended September 30, 2023, compared to the nine months ended September 30, 2022 and decreased $1.93 per Boe, or 40%, to $2.95 per Boe. This decrease was driven primarily by decreased oil and gas revenues, which decreased the tax base on which our production and other taxes are calculated.

(iv)Workover expense decreased $8.7 million, or 16%, in the nine months ended September 30, 2023, compared to the nine months ended September 30, 2022, and decreased $0.29 per Boe, or 19%, to $1.20 per Boe. This decrease was primarily caused by lower commodity price related activity.

(v)Midstream and other operating expense increased $3.8 million, or 38%, in the nine months ended September 30, 2023, compared to the nine months ended September 30, 2022 primarily due to increased crude oil blending expense in the Rockies. The additional expense is more than offset by additional oil blending revenue included as part of our Midstream and other revenue.

Depreciation, depletion and amortization. In the nine months ended September 30, 2023, depreciation, depletion and amortization increased $117.3 million, or 31%, compared to the nine months ended September 30, 2022, driven primarily by the July Western Eagle Ford Acquisition and Uinta Transaction, partially offset by lower production in other areas.

General and administrative expense. General and administrative expense ("G&A") increased $46.7 million, or 79%, for the nine months ended September 30, 2023, compared to the nine months ended September 30, 2022, primarily driven by (i) an increase in non-cash equity-based compensation expense of $38.3 million and (ii) 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. The increase in Manager Compensation is due to an increase in public ownership of Class A Common Stock as a result of (i) our Equity Issuance, which also increased the annual Manager Compensation by $2.2 million to $55.5 million annually, and (ii) share redemptions for our Class A Common Stock completed in the second quarter of 2023 and the second half of 2022, which did not increase the overall Manager Compensation, but do increase the portion of the

Manager Compensation borne by us. While only the portion of the 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 the amount presented in G&A is represented by “Certain-redeemable noncontrolling interest distributions made by OpCo related to Manager Compensation”). These increases were partially offset by $1.9 million in lower transaction and nonrecurring related expenses.


	Nine Months Ended September 30,
		2023		2022		$ Change		% Change
General and administrative expense (in thousands):
Recurring general and administrative expense		$	36,526	$	26,232	$	10,294	39	%
Transaction and nonrecurring expenses		5,061		6,951		(1,890)		(27)	%
Equity-based compensation		64,648		26,306		38,342		146	%
Total general and administrative expense		$	106,235	$	59,489	$	46,746	79	%
General and administrative expense per Boe:
Recurring general and administrative expense		$	0.93	$	0.70	$	0.23	33	%
Transaction and nonrecurring expenses		0.13		0.18		(0.05)		(28)	%
Equity-based compensation		1.64		0.70		0.94		134	%

Other operating costs. Other operating costs include exploration expense and gain on sale of assets. Other operating costs increased by $2.8 million, compared to the nine months ended September 30, 2022, primarily driven by a $5.1 million lower gain on sale of assets recognized during the nine months ended September 30, 2023, partially offset by $2.3 million in lower exploration expenses.

Interest expense

In the nine months ended September 30, 2023, we incurred interest expense of $102.6 million, as compared to $68.5 million in the nine months ended September 30, 2022, a 50% increase. This increase was driven primarily by higher average debt balances driven by the Western Eagle Ford Acquisitions and higher interest rates associated with the issuance of the July 2028 Notes and the September 2028 Notes and our Revolving Credit Facility.

Gain (loss) on derivatives


	Nine Months Ended September 30,
		2023		2022		$ Change		% Change
Gain (loss) on derivatives (in thousands):
Gain (loss) on commodity derivatives		$	(68,211)	$	(645,565)	$	577,354	(89)	%

Gain (loss) on derivatives		$	(68,211)	$	(645,565)	$	577,354	(89)	%

Our losses on commodity derivatives during the nine months ended September 30, 2023 decreased $577.4 million, or 89%, from a loss of $645.6 million during the nine months ended September 30, 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 nine months ended September 30, 2023 and September 30, 2022, we recognized income tax expense of $4.9 million and expense of $34.5 million, respectively, for an effective tax rate of 2.6% and 7.4%, 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)


	Nine Months Ended September 30,
		2023		2022		$ Change		% Change
(in thousands)
Net income (loss)		$	181,983	$	431,240	$	(249,257)	(58)	%
Adjustments to reconcile to Adjusted EBITDAX:
Interest expense		102,648		68,518

Income tax expense (benefit)		4,899		34,528
Depreciation, depletion and amortization		492,879		375,600
Exploration expense		1,541		3,848
Non-cash (gain) loss on derivatives		(42,564)		(8,812)
Non-cash equity-based compensation expense		64,648		26,306
(Gain) loss on sale of assets		—		(5,114)
Other (income) expense		(1,206)		4,472
Certain redeemable noncontrolling interest distributions made by OpCo related to Manager Compensation		(23,765)		(29,599)
Transaction and nonrecurring expenses (1)		14,188		25,968
Settlement of acquired derivative contracts		(48,977)		(39,046)
Adjusted EBITDAX (non-GAAP)		$	746,274	$	887,909	$	(141,635)	(16)	%
Adjustments to reconcile to Levered Free Cash Flow:
Interest expense, excluding non-cash deferred financing cost amortization		(93,473)		(62,087)

Current income tax benefit (expense)		(911)		(7,099)
Tax-related redeemable noncontrolling interest contributions (distributions) made by OpCo		108		(17,970)
Development of oil and natural gas properties		(444,245)		(468,796)
Levered Free Cash Flow (non-GAAP)		$	207,753	$	331,957	$	(124,204)	(37	%)

(1)Transaction and nonrecurring expenses of $14.2 million for the nine months ended September 30, 2023 were primarily related to the Western Eagle Ford Acquisitions and the Merger Transactions. Transaction and nonrecurring expenses of $26.0 million for the nine months ended September 30, 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 Merger Transactions, (ii) severance costs subsequent to the Merger Transactions, (iii) merger integration costs and (iv) acquisition and debt transaction related costs.

Adjusted EBITDAX decreased by $141.6 million, or 16%, in the nine months ended September 30, 2023, compared to the nine months ended September 30, 2022, primarily driven by lower realized prices, partially offset by additional production and Adjusted EBITDAX generated by the July Western Eagle Ford Acquisition and the Uinta Transaction.

Levered Free Cash Flow decreased by $124.2 million, or 37%, in the nine months ended September 30, 2023 compared to the nine months ended September 30, 2022, primarily driven by our decreased Adjusted EBITDAX, partially offset by $24.6 million of decreased capital expenditures related to timing of our operations.

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 opportunistic capital market offerings. Our primary expected uses of capital are for dividends to shareholders, debt repayment, development of our existing assets and acquisitions.

Our development program is designed to prioritize the generation of meaningful free cash flow and attractive risk-adjusted returns and is inherently flexible, with the ability to scale our capital program as necessary to react to the existing market environment and ongoing asset performance. See “—Development program and capital budget” above for additional discussion of our capital program.

We plan to continue our practice of entering into economic hedging arrangements to reduce the impact of the near-term volatility of commodity prices and the resulting impact on our cash flow from operations. A key tenet of our focused risk management efforts is an active economic hedge strategy to mitigate near-term price volatility while maintaining long-term exposure to underlying commodity prices. Our commodity derivative program focuses on entering into forward commodity contracts when investment decisions regarding reinvestment in existing assets or new acquisitions are finalized, targeting economic hedges for a portion of expected production generated by the capital investment as well as adding incremental derivatives to our production base over time. Our active derivative program allows us to protect margins and corporate returns through commodity cycles.

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


	September 30, 2023		December 31, 2022
	(in thousands)
Cash and cash equivalents	$	228,614	$	—
Long-term debt	1,912,187		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:


	Nine Months Ended September 30,
		2023		2022
		(in thousands)
Net cash provided by operating activities		$	612,900	$	797,354
Net cash used in investing activities		(1,066,238)		(1,060,934)
Net cash provided by financing activities		705,368		158,117

Net cash provided by operating activities. Net cash provided by operating activities for the nine months ended September 30, 2023 decreased by $184.5 million, or 23%, compared to the nine months ended September 30, 2022 primarily due to lower realized pricing and working capital changes. In addition, net cash provided by operating activity for the nine months ended September 30, 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 nine months ended September 30, 2023 slightly increased by $5.3 million, or a nominal percent, compared to the nine months ended September 30, 2022. Our Acquisitions of oil and natural gas properties of $622.7 million in 2023 was driven by our July Western Eagle Ford Acquisition, while the 2022 acquisitions of $627.5 million was driven by the Uinta Transaction. Our cash expenditures related to the Development of oil and natural gas properties increased by $30.9 million, but was mostly offset by $19.6 million of additional Proceeds from the sale of oil and natural gas properties.

Net cash provided by financing activities. Net cash provided by financing activities for the nine months ended September 30, 2023 was $705.4 million, an increase of $547.3 million, driven by additional debt borrowings in 2023 of $324.8 million, $145.7 million from our Equity Issuance and $54.2 million of cash outflows in 2022 related to redeemable NCI repurchases and tax distributions.

Debt agreements

Senior Notes

In February 2023, we issued $400.0 million aggregate principal amount of 9.250% senior notes due 2028 (the "Original 2028 Notes") at par. In July 2023 we issued an additional $300 million aggregate principal amount of 9.250% senior notes due 2028 (the "July 2028 Notes") and in September 2023 we issued an additional $150.0 million aggregate principal amount of 9.250% senior notes due 2028 (the "September 2028 Notes," and together with the July 2028 Notes and the September 2028 Notes, the "2028 Notes"). These three issuances of the 2028 Senior Notes are treated as a single series of securities under the indenture governing the Original 2028 Notes, will vote together as a single class, and have substantially identical terms, other than the issue date and the issue price. 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 Senior 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 at certain redemption prices.

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 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 Energy Finance LLC entered into the Revolving Credit Facility. The Revolving Credit Facility matures on September 23, 2027. At September 30, 2023, we had $392.0 million of outstanding borrowings under the Revolving Credit Facility and $11.4 million in outstanding letters of credit. Our elected

commitment amount was $1.3 billion and we had $0.9 billion of available borrowings under the Revolving Credit Facility as of September 30, 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 September 30, 2023 and December 31, 2022 was 8.00% and 6.98%, respectively.

The borrowing base under the Revolving Credit Facility was $2.0 billion as of September 30, 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. However, the terms of the Fifth Amendment to the Revolving Credit Facility provide for an exception to such automatic reduction in the case of issuances of senior unsecured notes in an aggregate principal amount less than $500 million prior to the fall 2023 borrowing base redetermination date, and accordingly we do not expect a borrowing base reduction in connection with the issuance of the New 2028 Notes.

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 September 30, 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.

Equity Issuance

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 our approximate $580 million to $630 million 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.

The table below presents our capital expenditures and related metrics that we use to evaluate our business for the periods presented:


	Nine Months Ended September 30,
		2023		2022
		(in thousands)
Total development of oil and natural gas properties		$	444,245	$	468,796
Change in accruals or other non-cash adjustments		27,030		(28,421)
Cash used in development of oil and natural gas properties		471,275		440,375
Cash used in acquisition of oil and natural gas properties		622,698		627,539
Non-cash acquisition of oil and natural gas properties		—		—
Total expenditures on acquisition and development of oil and natural gas properties		$	1,093,973	$	1,067,914

The decrease in our development costs in 2023 is primarily related to the timing of our operations. We used cash of $622.7 million in the nine months ended September 30, 2023 for the acquisition of oil and natural gas properties, as compared to $627.5 million in 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 September 30, 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 cash dividends of $0.41 per share of our Class A Common Stock to shareholders during the nine months ended September 30, 2023.

The payment of quarterly cash dividends is subject to management’s evaluation of our financial condition, results of operations and cash flows in connection with such payments and approval by our Board of Directors. In light of current economic conditions, management will evaluate any future increases in cash dividend on a quarterly basis.

Critical accounting policies and estimates

This discussion and analysis of our financial and results of operations are based upon our unaudited condensed consolidated financial statements. A complete list of our significant accounting policies is described in Note 2 – Summary of Significant Accounting Policies in our audited financial statements as of and for the year ended December 31, 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 September 30, 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

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

We define Levered Free Cash Flow as Adjusted EBITDAX less interest expense, excluding non-cash 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. 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.

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 September 30, 2023, our derivative portfolio had an aggregate notional value of approximately $2.0 billion, and the fair market value of our commodity derivative contracts was a net liability of $270.3 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 September 30, 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 $191.7 million. If prices decreased by 10%, our derivative position would change by approximately $181.4 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 September 30, 2023, we had $392.0 million of variable rate debt outstanding. Assuming no change in the amount outstanding, the impact on interest expense of a 1% increase or decrease in the average interest rate would be an approximate $2.9 million increase or decrease in interest expense on our variable rate debt outstanding for the nine months ended September 30, 2023.

Item 4. Controls and Procedures

Limitations on effectiveness of controls and procedures

We maintain disclosure controls and procedures ("Disclosure Controls") within the meaning of Rules 13a-15(e) and 15d-15(e) of the Exchange Act. Our Disclosure Controls are designed to ensure that information required to be disclosed by us in the reports we file or submit under the Exchange Act, such as this Quarterly Report, is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms.

Our Disclosure Controls are also designed to ensure that such information is accumulated and communicated to our management, including our Chief Executive Officer and Chief Financial Officer, as appropriate, to allow timely decisions regarding required disclosure. In designing and evaluating our Disclosure Controls, management recognizes that any controls and procedures, no matter how well designed and operated, can provide only reasonable assurance of achieving the desired control objectives.

Evaluation of disclosure controls and procedures

As required by Rules 13a-15 and 15d-15 under the Exchange Act, our Chief Executive Officer and Chief Financial Officer carried out an evaluation of the effectiveness of the design and operation of our disclosure controls and procedures as of September 30, 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 September 30, 2023 that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.

Part II – Other Information

Item 1. Legal Proceedings

The Company may, from time to time, be involved in litigation and claims arising out of its operations in the normal course of business. We are currently unaware of any proceedings that, in the opinion of management, will individually or in the aggregate have a material adverse effect on our financial position, results of operations or cash flows. Additional information required for this Item is provided in Notes to condensed consolidated financial statements, Note 9 – Commitments and Contingencies in Part I, Item 1. Financial Statements of this Quarterly Report, which is incorporated by reference into this Item.

Item 1A. Risk Factors

There are a number of risks that we believe are applicable to our business and the oil and gas industry in which we operate. These risks are described elsewhere in this report or our other filings with the SEC, including the section entitled “Item 1A. Risk Factors” beginning on page 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 and adversely affected.

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

Not applicable.

Item 3. Defaults Upon Senior Securities

None.

Item 4. Mine Safety Disclosures

Not applicable.

Item 5. Other Information

During the three months ended September 30, 2023, no director or officer of the Company adopted or terminated a “Rule 10b5-1 trading arrangement” or “non-Rule 10b5-1 trading arrangement,” as each term is defined in Item 408(a) of Regulation S-K.

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).
4.2			First Supplemental Indenture, dated as of January 14, 2022, among Crescent Energy Finance LLC, the guarantors named therein, and U.S. Bank Trust Company, National Association, as successor to U.S. Bank National Association, as trustee (incorporated by reference to Exhibit 4.2 to the Company’s Current Report on Form 8-K, filed with the Securities and Exchange Commission on February 10, 2022).
4.3			Second Supplemental Indenture, dated as of February 10, 2022, among Crescent Energy Finance LLC, the guarantors named therein, and U.S. Bank Trust Company, National Association, as trustee (incorporated by reference to Exhibit 4.3 to the Company’s Current Report on Form 8-K, filed with the Securities and Exchange Commission on February 10, 2022).
4.4			Third Supplemental Indenture, dated as of April 1, 2022, among Crescent Energy Finance LLC, the guarantors named therein, and U.S. Bank Trust Company, National Association, as trustee (incorporated by reference to Exhibit 4.4 to the Company's Quarterly Report on Form 10-Q, filed with the Securities and Exchange Commission on May 10, 2022).
4.5			Fourth Supplemental Indenture, dated as of April 20, 2022, among Crescent Energy Finance LLC, the guarantors named therein, and U.S. Bank Trust Company, National Association, as trustee (incorporated by reference to Exhibit 4.5 to the Company's Quarterly Report on Form 10-Q, filed with the Securities and Exchange Commission on May 10, 2022).
4.6			Fifth Supplemental Indenture, dated as of October 12, 2022, among Crescent Energy Finance LLC, the guarantors named therein, and U.S. Bank Trust Company, National Association, as trustee (incorporated by reference to Exhibit 4.6 to the Company's Quarterly Report on Form 10-Q, filed with the Securities and Exchange Commission on November 9, 2022).
4.7			Sixth Supplemental Indenture, dated as of March 6, 2023, among Crescent Energy Finance LLC, the guarantors named therein, and U.S. Bank Trust Company, National Association, as trustee (incorporated by reference to Exhibit 4.10 to the Company's Annual Report on Form 10-K, filed with the Securities and Exchange Commission on March 7, 2023).
4.8			Indenture, dated as of February 1, 2023, among Crescent Energy Finance LLC, the guarantors named therein, and U.S. Bank Trust Company, National Association, as trustee (incorporated by reference to Exhibit 4.1 to the Company’s Current Report on Form 8-K, filed with the Securities and Exchange Commission on February 1, 2023).
4.9			First Supplemental Indenture, dated as of July 20, 2023, among Crescent Energy Finance LLC, the guarantors named therein, and U.S. Bank Trust Company, National Association, as trustee (incorporated by reference to Exhibit 4.2 to the Company's Current Report on Form 8-K, filed with the Securities and Exchange Commission on July 21, 2023).
4.10			S econd Supplemental I ndenture, dated as of September 12, 2023, among Cre scent 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 F orm 8-K, filed with the Securities and Exch ange Commission on September 12, 2023).
10.1			Fifth Amendment to Credit Agreement, dated July 3, 2023, by and among Crescent Energy Finance LLC, certain subsidiaries of Crescent Energy Finance LLC, as guarantors, Wells Fargo Bank, National Association, as administrative agent, collateral agent and a letter of credit issuer, and the other lenders and letter of credit issuers party thereto (incorporated by reference to Exhibit 10.1 to the Company's Current Report on Form 8-K, filed with the Securities and Exchange Commission on July 10, 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.

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)

November 6, 2023						/s/ David Rockecharlie
						David Rockecharlie
						Chief Executive Officer
						(Principal Executive Officer)

November 6, 2023						/s/ Brandi Kendall
						Brandi Kendall
						Chief Financial Officer
						(Principal Financial Officer)

Positive
Negative
Uncertain
Constraining
Legalese
Litigous
Readability	H.S. junior Avg

Crescent Energy (CRGY) 10-Q2023 Q3 Quarterly report

Content analysis