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, 2022

OR

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

For the transition period from            to

Commission file number 001-41132

Crescent Energy Company

(Exact name of registrant as specified in its charter)

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

600 Travis Street, Suite 7200

Houston, Texas 77002

(713) 337-4600

(Address, including zip code, and telephone number, including area code, of registrant’s principal executive offices)

Securities registered pursuant to Section 12(b) of the Act:

Title of each class	Trading Symbol	Name of each exchange on which registered
Class A Common Stock, par value $0.0001	CRGY	New York Stock Exchange

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

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

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

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

If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 7(a)(2)(B) of the Securities Act. ☐

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act): Yes ☐ No ☒

As of October 31, 2022, there were approximately 48,282,163 and 118,645,323 shares of the registrant's Class A and Class B common stock outstanding, respectively.

Table of Contents

Glossary	2
Cautionary Statement Regarding Forward-Looking Statements	3
Part I - Financial Information
Item 1. Financial Statements	5
Item 2. Management's Discussion and Analysis of Financial Condition and Results of Operations	31
Item 3. Quantitative and Qualitative Disclosures About Market Risk	51
Item 4. Controls and Procedures	52
Part II - Other Information
Item 1. Legal Proceedings	54
Item 1A. Risk Factors	54
Item 2. Unregistered Sales of Equity Securities and Use of Proceeds	54
Item 3. Defaults Upon Senior Securities	55
Item 4. Mine Safety Disclosures	55
Item 5. Other Information	55
Item 6. Exhibits	55
Signatures	57

1

GLOSSARY

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

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

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

Boe/d — Barrels of oil equivalent per day.

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

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

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

MBbls — One thousand Bbls or other liquid hydrocarbons.

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

MBoe — One thousand Boe.

MBoe/d — One thousand Boe per day.

Mcf — One thousand cubic feet of natural gas.

Mcf/d — One thousand Mcf per day.

MMBoe — One million Boe.

MMBtu — One million Btus.

MMcf — One million Mcf.

MMcf/d — One million Mcf per day.

NYMEX — The New York Mercantile Exchange.

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

Proved reserves — Proved reserves are those quantities of oil and natural gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible—from a given date forward, from known reservoirs and under existing economic conditions, operating methods and government regulations—prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. The project to extract the hydrocarbons must have commenced or the operator must be reasonably certain that it will commence the project within a reasonable time.

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

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

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

2

Cautionary Statement Regarding Forward-Looking Statements

The information in this Quarterly Report on Form 10-Q (this "Quarterly Report") contains or incorporates by reference information that includes or is based upon "forward-looking statements" within the meaning of Section 27A of the Securities Act of 1933, as amended (the "Securities Act"), and Section 21E of the Securities Exchange Act of 1934, as amended (the "Exchange Act"). All statements, other than statements of historical facts, included herein concerning, among other things, planned capital expenditures, increases in oil, natural gas and natural gas liquids (“NGL”) production, the number of anticipated wells to be drilled or completed after the date hereof, future cash flows and borrowings, pursuit of potential acquisition opportunities, our financial position, business strategy and other plans and objectives for future operations, are forward-looking statements. These forward-looking statements are identified by their use of terms and phrases such as “may,” “expect,” “estimate,” “project,” “plan,” “believe,” “intend,” “achievable,” “anticipate,” “will,” “continue,” “potential,” “should,” “could,” and similar terms and phrases. Although we believe that the expectations reflected in these forward-looking statements are reasonable, they do involve certain assumptions, risks and uncertainties. Our results could differ materially from those anticipated in these forward-looking statements as a result of certain factors, including, among others:

•commodity price volatility;

•our business strategy;

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

•our ability to identify and select possible acquisition and disposition opportunities;

•capital requirements and uncertainty of obtaining additional funding on terms acceptable to us;

•risks and restrictions related to our debt agreements and the level of our indebtedness;

•our reliance on KKR Energy Assets Manager LLC as our external manager;

•our hedging strategy and results;

•realized oil, natural gas and NGL prices;

•political and economic conditions and events in foreign oil, natural gas and NGL producing countries, including embargoes, continued hostilities in the Middle East and other sustained military campaigns, the armed conflict in Ukraine and associated economic sanctions on Russia, conditions in South America, Central America and China and acts of terrorism or sabotage;

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

•timing and amount of our future production of oil, natural gas and NGLs;

•a decline in oil, natural gas and NGL production, and the impact of general economic conditions on the demand for oil, natural gas and NGLs and the availability of capital;

•unsuccessful drilling and completion (“D&C”) activities and the possibility of resulting write downs;

•our ability to meet our proposed drilling schedule and to successfully drill wells that produce oil, natural gas and NGLs in commercially viable quantities;

•shortages of equipment, supplies, services and qualified personnel and increased costs for such equipment, supplies, services and personnel;

•adverse variations from estimates of reserves, production, prices and expenditure requirements, and our inability to replace our reserves through exploration and development activities;

•incorrect estimates associated with properties we acquire relating to estimated proved reserves, the presence or recoverability of estimated oil, natural gas and NGL reserves and the actual future production rates and associated costs of such acquired properties;

•hazardous, risky drilling operations, including those associated with the employment of horizontal drilling techniques, and adverse weather and environmental conditions;

•limited control over non-operated properties;

•title defects to our properties and inability to retain our leases;

•our ability to successfully develop our large inventory of undeveloped acreage;

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

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

•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;

•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;

•changes in tax laws;

•effects of competition; and

3

•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, 2021 ("Annual Report") and our reports and registration statements filed from time to time with the SEC.

Reserve engineering is a process of estimating underground accumulations of hydrocarbons that cannot be measured in an exact way. The accuracy of any reserve estimates depends on the quality of available data, the interpretation of such data and price and cost assumptions made by reserve engineers. In addition, the results of drilling, testing and production activities may justify revisions of estimates that were made previously. If significant, such revisions would change the schedule of any further production and development program. Accordingly, reserve estimates may differ significantly from the quantities of oil, natural gas and NGLs that are ultimately recovered.

Should one or more of the risks or uncertainties described in this Quarterly Report occur, or should underlying assumptions prove incorrect, our actual results and plans could differ materially from those expressed in any forward-looking statements. All forward-looking statements, expressed or implied, included in this Quarterly Report are expressly qualified in their entirety by this cautionary statement. This cautionary statement should also be considered in connection with any subsequent written or oral forward-looking statements that we or persons acting on our behalf may issue. Except as otherwise required by applicable law, we disclaim any duty to update any forward-looking statements, all of which are expressly qualified by the statements in this section, to reflect events or circumstances after the date of this Quarterly Report.

4

Part I – Financial Information

Item 1. Financial Statements 

CRESCENT ENERGY COMPANY
CONDENSED CONSOLIDATED BALANCE SHEETS
(Unaudited)
(in thousands, except share data)
	September 30, 2022		December 31, 2021
ASSETS
Current assets:
Cash and cash equivalents	$	22,478	$	128,578
Accounts receivable, net	518,531		321,855
Accounts receivable – affiliates	1,532		20,341
Derivative assets - current	7,120		—
Drilling advances	10,220		200
Prepaid and other current assets	20,595		8,644
Total current assets	580,476		479,618
Property, plant and equipment:
Oil and natural gas properties at cost, successful efforts method
Proved	7,299,737		6,043,602
Unproved	331,294		308,721
Oil and natural gas properties at cost, successful efforts method	7,631,031		6,352,323
Field and other property and equipment, at cost	177,181		144,318
Total property, plant and equipment	7,808,212		6,496,641
Less: accumulated depreciation, depletion, amortization and impairment	(2,300,795)		(1,941,528)
Property, plant and equipment, net	5,507,417		4,555,113
Goodwill	76,826		76,564
Derivative assets – noncurrent	—		579
Investment in equity affiliates	14,509		15,415
Other assets	50,366		30,173
TOTAL ASSETS	$	6,229,594	$	5,157,462
The accompanying notes to financial statements are an integral part of these condensed consolidated financial statements

5

CRESCENT ENERGY COMPANY
CONDENSED CONSOLIDATED BALANCE SHEETS
(Unaudited)
(in thousands, except share data)
	September 30, 2022		December 31, 2021
LIABILITIES, REDEEMABLE NONCONTROLLING INTERESTS AND EQUITY
Current liabilities:
Accounts payable and accrued liabilities	$	596,115	$	337,881
Accounts payable – affiliates	39,962		8,675
Derivative liabilities – current	384,038		253,525
Financing lease obligations – current	2,446		1,606
Other current liabilities	17,324		14,438
Total current liabilities	1,039,885		616,125
Long-term debt	1,372,334		1,030,406
Derivative liabilities – noncurrent	89,343		133,471
Asset retirement obligations	290,122		258,102
Deferred tax liability	141,643		82,537
Financing lease obligations – noncurrent	5,032		3,512
Other liabilities	22,253		13,652
Total liabilities	2,960,612		2,137,805
Commitments and contingencies (Note 9)
Redeemable noncontrolling interests	2,419,993		2,325,013
Equity:
Class A common stock, $0.0001 par value; 1,000,000,000 shares authorized, 49,433,154 and 43,105,376 shares issued, and 48,282,163 and 41,954,385 shares outstanding as of September 30, 2022 and December 31, 2021, respectively	5		4
Class B common stock, $0.0001 par value; 500,000,000 shares authorized and 118,645,323 and 127,536,463 shares issued and outstanding as of September 30, 2022 and December 31, 2021, respectively	12		13
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, 2022 and December 31, 2021	—		—
Treasury stock, at cost; 1,150,991 shares of Class A common stock as of September 30, 2022 and December 31, 2021	(18,448)		(18,448)
Additional paid-in capital	801,978		720,016
Retained earnings (accumulated deficit)	61,375		(19,376)
Noncontrolling interests	4,067		12,435
Total equity	848,989		694,644
TOTAL LIABILITIES, REDEEMABLE NONCONTROLLING INTERESTS AND EQUITY	$	6,229,594	$	5,157,462

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

6

CRESCENT ENERGY COMPANY

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS

(Unaudited)

(in thousands, except per share amounts)

	Three Months Ended September 30,				Nine Months Ended September 30,
	2022		2021		2022		2021
Revenues:
Oil	$	550,823	$	222,074	$	1,525,899	$	627,817
Natural gas	235,830		86,779		586,318		230,271
Natural gas liquids	64,810		47,322		219,853		121,613
Midstream and other	13,494		9,553		40,231		34,017
Total revenues	864,957		365,728		2,372,301		1,013,718
Expenses:
Lease operating expense	121,554		58,338		322,752		175,966
Workover expense	21,126		2,932		56,102		7,823
Asset operating expense	20,791		10,810		54,653		24,306
Gathering, transportation and marketing	44,757		44,634		131,271		136,056
Production and other taxes	71,511		28,090		183,491		80,276
Depreciation, depletion and amortization	145,008		73,025		375,600		233,122
Exploration expense	1,909		754		3,848		833
Midstream operating expense	3,550		2,518		9,972		8,848
General and administrative expense	17,311		11,024		59,489		33,775
Gain on sale of assets	(127)		(1)		(5,114)		(9,418)
Total expenses	447,390		232,124		1,192,064		691,587
Income (loss) from operations	417,567		133,604		1,180,237		322,131
Other income (expense):
Gain (loss) on derivatives	205,130		(282,222)		(645,565)		(885,032)
Interest expense	(27,057)		(12,984)		(68,518)		(37,810)
Other income (expense)	(2,670)		(48)		(4,472)		(54)
Income from equity affiliates	834		—		4,086		—
Total other income (expense)	176,237		(295,254)		(714,469)		(922,896)
Income (loss) before taxes	593,804		(161,650)		465,768		(600,765)
Income tax benefit (expense)	(38,455)		(393)		(34,528)		(407)
Net income (loss)	555,349		(162,043)		431,240		(601,172)
Less: net (income) loss attributable to Predecessor	—		160,567		—		585,804
Less: net (income) loss attributable to noncontrolling interests	(904)		1,476		(2,087)		15,368
Less: net (income) loss attributable to redeemable noncontrolling interests	(436,084)		—		(341,269)		—
Net income (loss) attributable to Crescent Energy	$	118,361	$	—	$	87,884	$	—
Net income (loss) per share:
Class A common stock – basic	$	2.74			$	2.07
Class A common stock – diluted	$	2.74			$	2.07
Class B common stock – basic and diluted	$	—			$	—
Weighted average shares outstanding:
Class A common stock – basic	43,197				42,377
Class A common stock - diluted	43,210				42,382
Class B common stock – basic and diluted	125,797				126,950

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

7

CRESCENT ENERGY COMPANY
CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY
(Unaudited)
(in thousands)
	Predecessor			Crescent Energy Company
	Class A Units	Members' Equity		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, 2021	1,220	$	2,716,892	—	$	—	—	$	—	—	$	—	—	$	—	$	—	$	—	$	176,268	$	2,893,160
Net loss attributable to Predecessor	—	(155,629)		—	—		—	—		—	—		—	—		—		—		(10,639)		(166,268)
Contributions	—	3,064		—	—		—	—		—	—		—	—		—		—		—		3,064
Distributions	—	(9,448)		—	—		—	—		—	—		—	—		—		—		(289)		(9,737)
Equity-based compensation	—	—		—	—		—	—		—	—		—	—		—		—		1,568		1,568
Balance at March 31, 2021	1,220	$	2,554,879	—	$	—	—	$	—	—	$	—	—	$	—	$	—	$	—	$	166,908	$	2,721,787
Net loss attributable to Predecessor	—	(269,608)		—	—		—	—		—	—		—	—		—		—		(3,253)		(272,861)
Contributions	—	4,100		—	—		—	—		—	—		—	—		—		—		35,461		39,561
Distributions	—	(13,761)		—	—		—	—		—	—		—	—		—		—		11		(13,750)
Noncontrolling Interest Carve-out	—	—		—	—		—	—		—	—		—	—		—		—		(121,872)		(121,872)
Equity-based compensation	—	—		—	—		—	—		—	—		—	—		—		—		1,564		1,564
April 2021 Exchange	10	62,051		—	—		—	—		—	—		—	—		—		—		(62,051)		—
Balance at June 30, 2021	1,230	$	2,337,661	—	$	—	—	$	—	—	$	—	—	$	—	$	—	$	—	$	16,768	$	2,354,429
Net loss attributable to Predecessor	—	(160,567)		—	—		—	—		—	—		—	—		—		—		(1,476)		(162,043)
Distributions	—	(11,838)		—	—		—	—		—	—		—	—		—		—		(268)		(12,106)
Equity-based compensation	—	—		—	—		—	—		—	—		—	—		—		—		57		57
Repurchase of noncontrolling interest	—	—		—	—		—	—		—	—		—	—		—		—		(1,414)		(1,414)
Balance at September 30, 2021	1,230	$	2,165,256	—	$	—	—	$	—	—	$	—	—	$	—	$	—	$	—	$	13,667	$	2,178,923
The accompanying notes are an integral part of these condensed consolidated financial statements

8

CRESCENT ENERGY COMPANY
CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY
(Unaudited)
(in thousands)
	Predecessor			Crescent Energy Company
	Class A Units	Members' Equity		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

9

CRESCENT ENERGY COMPANY
CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY
(Unaudited)
(in thousands)
	Predecessor			Crescent Energy Company
	Class A Units	Members' Equity		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

10

CRESCENT ENERGY COMPANY

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)

(in thousands)

	Nine Months Ended September 30,
	2022		2021
Cash flows from operating activities:
Net income (loss)	$	431,240	$	(601,172)
Adjustments to reconcile net income (loss) to net cash provided by operating activities
Depreciation, depletion and amortization	375,600		233,122
Deferred income tax expense (benefit)	27,428		—
(Gain) loss on derivatives	645,565		885,032
Net cash (paid) received on settlement of derivatives	(654,377)		(389,142)
Non-cash equity-based compensation expense	26,306		14,054
Amortization of debt issuance costs and discount	6,431		6,809
Gain on sale of oil and natural gas properties	(5,114)		(9,418)
Restructuring of acquired derivative contracts	(51,994)		—
Settlement of acquired derivative contracts	(39,046)		—
Other	(6,941)		3,256
Changes in operating assets and liabilities:
Accounts receivable	(189,512)		(67,588)
Accounts receivable – affiliates	18,809		(9,363)
Prepaid and other current assets	(22,011)		27,898
Accounts payable and accrued liabilities	213,428		60,112
Accounts payable – affiliates	24,560		(4,720)
Other	(3,018)		(248)
Net cash provided by operating activities	797,354		148,632
Cash flows from investing activities:
Development of oil and natural gas properties	(440,375)		(83,697)
Acquisitions of oil and natural gas properties	(627,539)		(65,391)
Proceeds from the sale of oil and natural gas properties	4,800		22,053
Purchases of restricted investment securities – HTM	(7,175)		(6,746)
Maturities of restricted investment securities – HTM	5,400		8,121
Other	3,955		(1,116)
Net cash used in investing activities	(1,060,934)		(126,776)
Cash flows from financing activities:
Proceeds from the issuance of Senior Notes, after premium, discount and underwriting fees	199,250		490,625
Revolving Credit Facility borrowings	1,118,000		386,062
Revolving Credit Facility repayments	(976,000)		(108,000)
Payment of debt issuance costs	(20,028)		(10,880)
Prior Credit Agreement borrowings	—		53,900
Prior Credit Agreement repayments	—		(804,975)
Redeemable noncontrolling interest contributions	5,985		—
Member distributions and other	(3,784)		(35,294)
Dividend to Class A common stock	(19,301)		—
Distributions to redeemable noncontrolling interests related to Class A common stock dividend	(58,705)		—
Distributions to redeemable noncontrolling interests related to Manager Compensation	(22,779)		—
Distributions to redeemable noncontrolling interests related to income taxes	(17,970)		—
Repurchase of redeemable noncontrolling interests related to Equity Transactions	(36,220)		—
Repurchase of noncontrolling interest	(4,060)		(1,414)
Noncontrolling interest distributions	(6,326)		(546)
Noncontrolling interest contributions	55		35,461
Net cash provided by financing activities	158,117		4,939
Net change in cash, cash equivalents and restricted cash	(105,463)		26,795
Cash, cash equivalents and restricted cash, beginning of period	135,117		41,420
Cash, cash equivalents and restricted cash, end of period	$	29,654	$	68,215

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

11

CRESCENT ENERGY COMPANY

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(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 for time periods prior to the Merger Transactions refer to Crescent Energy OpCo LLC (f/k/a Independence Energy LLC) and its subsidiaries, our predecessor for accounting purposes. For time periods subsequent to the Merger Transactions, these terms refer to Crescent Energy Company and its subsidiaries.

NOTE 1 – Organization and Basis of Presentation

Organization

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

Merger Transactions

On December 7, 2021, we completed a series of transactions, pursuant to which the business of Contango Oil & Gas Company ("Contango") and the business of Independence Energy LLC ("Independence") combined indirectly under a new publicly traded holding company named "Crescent Energy Company" (the "Merger Transactions"). Our Class A common stock, par value $0.0001 per share ("Class A Common Stock") is listed on The New York Stock Exchange under the symbol “CRGY.” The combined company is structured as an “Up-C,” with all of our assets and operations (including those of Contango) indirectly held by our operating subsidiary, Crescent Energy OpCo LLC ("OpCo"). Crescent is a holding company, the sole material asset of which consists of economic, non-voting limited liability company interests in OpCo ("OpCo Units"), and is responsible for all operational, management and administrative decisions related to OpCo’s business. We are the sole managing member of OpCo. Because the unit holders of OpCo lack the characteristics of a controlling financial interest, OpCo is determined to be a variable interest entity. Crescent is considered the primary beneficiary of OpCo as it has both the power to direct OpCo and the right to receive benefits from OpCo. As a result, Crescent consolidates the financial results of OpCo and its subsidiaries. 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. Former Contango shareholders own shares of Class A Common Stock, which have both voting and economic rights. The former owners of our predecessor, Independence Energy LLC, own OpCo Units and corresponding shares of Class B common stock, par value $0.0001 per share ("Class B Common Stock"), which shares of Class B Common Stock have voting (but no economic) rights. 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”).

Upon closing of the Merger Transactions, (a) former owners of Independence owned approximately 75% of OpCo, 100% of the total outstanding Class B Common Stock and approximately 75% of the total outstanding Class A Common Stock and Class B Common Stock taken together, (b) former stockholders of Contango owned Class A Common Stock representing approximately 25% of the outstanding Class A Common Stock and Class B Common Stock, taken together and (c) Crescent owned approximately 25% of the OpCo Units. Additionally, Independence Energy Aggregator LP, an affiliate of certain former owners of Independence, is the sole holder of Crescent's non-economic Series I preferred stock, $0.0001 par value per share, which entitles the holder thereof to appoint the board of directors of Crescent (the "Board of Directors") and to certain other approval rights.

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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 5.75 million shares of our Class A Common Stock (the "Offering") 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. 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. After the Equity Transactions, shares of our Class A Common Stock represent approximately 29% of the outstanding shares of Class A Common Stock and Class B Common Stock, taken together, and we own approximately 29% of the outstanding OpCo Units. 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.

In connection with the Merger Transactions, we underwent a reorganization (the “Crescent Reorganization”), whereby Independence merged with and into OpCo (the “Isla Merger”). The financial statements include the accounts of Independence from the date of the Isla Merger, which is the date the Company obtained a controlling financial interest in Independence on a consolidated basis. As required by GAAP, the contribution of Independence in connection with the Isla Merger and, more broadly, the Merger Transactions was accounted for as a reorganization of entities under common control, in a manner similar to a pooling of interests, with all assets and liabilities transferred to us at their carrying amounts. Because the Isla Merger resulted in a change in the reporting entity, and in order to furnish comparative financial information prior to the Isla Merger, our financial statements have been retrospectively recast to reflect the historical accounts of Independence, our accounting predecessor (the "Predecessor"), on a combined basis.

Crescent is a holding company that conducts substantially all of its business through its consolidated subsidiaries, including (i) OpCo, which at September 30, 2022 is owned approximately 29% by Crescent and approximately 71% by holders of our redeemable noncontrolling interests representing former owners of Independence, 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. See “—Merger Transactions” above for more information regarding our corporate structure.

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

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of the financial statements and the reported amounts of revenues and expenses during the reporting period. We use historical experience and various other assumptions and information that are believed to be reasonable under the circumstances in developing our estimates and judgments. Estimates and assumptions about future events and their effects cannot be predicted with certainty and, accordingly, these estimates may change as new events occur, as more experience is acquired, as additional information is obtained and as our operating environment changes. While we believe that the estimates and assumptions used in the preparation of the financial statements are appropriate, actual results may differ from these estimates. Our significant estimates include the fair value of acquired assets and liabilities, oil and natural gas reserves, impairment of proved and unproved oil and natural gas properties and valuation of derivative instruments.

Restricted Cash

Restricted cash consists of funds earmarked for a special purpose and therefore not available for immediate and general use. The majority of our restricted cash is composed of cash that is contractually required to be restricted to pay for the future abandonment of certain wells in California. Restricted cash is included in Prepaid and other current assets and Other assets on our condensed consolidated balance sheets.

The following table provides a reconciliation of cash and restricted cash presented on our balance sheets to amounts shown in the statements of cash flows:

	As of September 30,
	2022		2021
	(in thousands)
Cash and cash equivalents	$	22,478	$	63,541
Restricted cash – noncurrent	7,176		4,674
Total cash, cash equivalents and restricted cash	$	29,654	$	68,215

Redeemable Noncontrolling Interests

In connection with the Merger Transactions, 127.5 million OpCo Units were issued to the former owners of Independence. The former owners of Independence also own all outstanding shares of our Class B Common Stock. Pursuant to the OpCo LLC Agreement, holders of OpCo Units, other than the Company, may redeem all or a portion of their OpCo Units, together with a corresponding number of shares of Class B Common Stock, for either (a) shares of Class A Common Stock or (b) an approximately equivalent amount of cash as determined pursuant to the terms of the OpCo LLC Agreement, at the election of the Company. In connection with the exercise of such redemption, a corresponding number of shares of Class B Common Stock will be cancelled. The redemption election is not considered to be within the control of the Company because the holders of Class B Common Stock and their affiliates control the Company through direct representation on the Board of Directors. As a result, we present the noncontrolling interests in OpCo as redeemable noncontrolling interests outside of permanent equity. Redeemable noncontrolling interest is recorded at the greater of the carrying value or redemption amount with a corresponding adjustment to additional paid-in capital. The redemption amount is based on the 10-day volume-weighted average closing price (“VWAP”) 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.

In September 2022, our Equity Transactions, including 0.6 million shares 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 reduced the number of shares of our Class B Common Stock outstanding by 8.9 million shares. The reduction was a result of the exchange of 6.3 million shares of Class B Common Stock into shares of Class A Common Stock and the repurchase of 2.6 million shares of Class B Common Stock for $36.2 million.

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From December 31, 2021 through September 30, 2022, we recorded adjustments to the value of our redeemable noncontrolling interests as shown below:

	Redeemable Noncontrolling Interests
	(in thousands)
Balance as of December 31, 2021	$	2,325,013
Net loss attributable to redeemable noncontrolling interests	(321,477)
Distribution from OpCo	(15,323)
Accrued OpCo distribution	(10,064)
Equity-based compensation	2,931
Adjustment of redeemable noncontrolling interests to redemption amount (1)	194,980
Balance as of March 31, 2022	$	2,176,060
Net income attributable to redeemable noncontrolling interests	226,662
Contributions	5,985
Distribution from OpCo	(33,376)
Accrued OpCo distribution	(16,220)
Equity-based compensation	3,282
Adjustment of redeemable noncontrolling interests to carrying value (1)	(194,980)
Balance at June 30, 2022	$	2,167,413
Net income attributable to redeemable noncontrolling interests	436,084
Distribution from OpCo	(21,967)
Accrued OpCo distribution	(9,471)
Equity-based compensation	5,999
Cancellation of OpCo Units associated with Equity Transactions	(158,065)
Balance at September 30, 2022	$	2,419,993

(1)Based on 127,536,463 shares of Class B Common Stock outstanding and the 10-day VWAP of Class A Common Stock of $17.06 at March 31, 2022. The increase to redeemable noncontrolling interests was offset by a $195.0 million decrease in APIC. At June 30, 2022, we reversed this adjustment because the carrying value of our redeemable noncontrolling interests was greater than the redemption value.

Income Taxes

For the three and nine months ended September 30, 2021, we were organized as a limited liability company and treated as a flow-through entity for U.S. federal income tax purposes. As a result, the tax provision for the three and nine months ended September 30, 2021 was minimal. Subsequent to the Merger Transactions, the Company is a corporation that is subject to U.S. federal, state and local income taxes on its allocable share of any taxable income from OpCo. 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.

As part of the Merger Transactions, we acquired federal and state net operating losses ("NOLs") which are subject to Section 382 limitation. Pursuant to Sections 382 and 383 of the Internal Revenue Code, utilization of our NOLs and credits is subject to

15

a small annual limitation. These annual limitations may result in the expiration of NOLs and credits prior to utilization. As of September 30, 2022, we have a $26.1 million valuation allowance related to the federal and state NOLs incurred that we do not believe are recoverable due to Section 382 limitations.

During the three months ended September 30, 2022, we decreased APIC and increased our deferred tax liability by $5.6 million primarily as the result of the Equity Transactions and the resultant change in our ownership interests and basis in OpCo. During the nine months ended September 30, 2022 we decreased APIC by $31.9 million primarily related to a change in the deferred tax liability related to our estimated basis in our ownership interests in OpCo and the Equity Transactions, offset by other changes in our deferred tax liability related to ownership interests in OpCo. As of September 30, 2022 and December 31, 2021, 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, 2022 and 2021:

	Nine Months Ended September 30,
	2022		2021
	(in thousands)
Supplemental cash flow disclosures:
Interest paid, net of amounts capitalized	$	44,072	$	13,608
Income tax (refunds) payments	7,864		407
Non-cash investing and financing activities:
Capital expenditures included in accounts payable and accrued liabilities	$	78,080	$	36,568
Equity consideration for acquisitions, net of cash acquired	—		7,164
April 2021 Exchange	—		62,051
Noncontrolling Interest Carve-Out	—		(121,872)
Capitalized non-cash equity-based compensation	—		3,373

Recent Accounting Standards

In March 2020, the Financial Accounting Standards Board ("FASB") issued ASU 2020-04, Reference Rate Reform (Topic 848) - Facilitation of the Effects of Reference Rate Reform on Financial Reporting (“ASU 2020-04”). ASU 2020-04 provides optional guidance, for a limited period of time, to ease the potential burden in accounting for (or recognizing the effects of) reference rate reform on financial reporting. The amendments in ASU 2020-04 provide optional expedients and exceptions for applying GAAP to contracts, hedging relationships and other transactions affected by reference rate reform if certain criteria are met. The amendments in this ASU apply only to contracts, hedging relationships and other transactions that reference the London Interbank Offer Rate ("LIBOR"), or another reference rate, expected to be discontinued because of reference rate reform. The guidance was effective beginning March 12, 2020 and can be applied prospectively through December 31, 2022. In January 2021, the FASB issued ASU 2021-01, Reference Rate Reform - Scope, which clarified the scope and application of the original guidance. The Company is currently assessing the potential impact of ASU 2020-04 on our consolidated financial statements.

NOTE 3 – Acquisitions and Divestitures

Uinta Transaction

In March 2022, we consummated the acquisition contemplated by the Membership Interest Purchase Agreement dated February 15, 2022 (the “Purchase Agreement” and the transactions contemplated therein, the “Uinta Transaction”) between certain of our subsidiaries, including OpCo, and Verdun Oil Company II LLC, a Delaware limited liability company, pursuant to which we purchased all of the issued and outstanding membership interests of Uinta AssetCo, LLC, a Texas limited liability company that holds all development and production assets of, and certain obligations formerly held by EP Energy E&P Company, L.P. located in the State of Utah. Upon closing of the Uinta Transaction, we paid $621.3 million in cash consideration and transaction fees and assumed certain commodity derivatives. The Uinta Transaction was funded with cash on hand and borrowings under our Revolving Credit Facility (as defined below). We accounted for the Uinta Transaction as an asset acquisition and recorded an additional $852.5 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

16

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.

Contango Merger

In December 2021, we acquired all of Contango's outstanding common stock through the issuance of 39,834,461 shares of Class A Common Stock (the "Contango Merger") and settled Contango's equity-based compensation plans through the issuance of 3,270,915 shares of Class A Common Stock, of which 1,150,991 shares of treasury stock were withheld to meet employee payroll tax withholding obligations. Contango's properties are primarily located in Oklahoma, Texas, Wyoming and Louisiana. We accounted for the Contango Merger as a business combination using the acquisition method under GAAP. The fair value of consideration transferred totaled $654.6 million based on the closing share price of Contango's common stock on the date of the Merger Transactions as shares of our Class A Common Stock were not yet publicly traded. The purchase price allocation for the acquisition is preliminary for assets acquired and liabilities assumed. During the nine months ended September 30, 2022, we recognized measurement period adjustments for the Contango Merger that increased Accounts receivable, net by $5.8 million, reduced Oil and natural gas properties - proved by $0.2 million, and increased Accounts payable and accrued liabilities by $5.8 million, with an offsetting adjustment to Goodwill on our condensed consolidated balance sheets. We expect to complete a final valuation analysis during the fourth quarter of 2022. As a result of the acquisition, we recognized $76.8 million of goodwill that is primarily attributable to deferred tax liabilities associated with the transaction and expected synergies from our combined operations. This goodwill is not expected to be deductible for income tax reporting purposes.

(in thousands)	Contango
Consideration transferred:
Equity consideration	$	654,616
Total	$	654,616
Assets acquired and liabilities assumed:
Cash and cash equivalents	$	14,202
Accounts receivable, net	151,533
Prepaid and other current assets	8,275
Oil and natural gas properties – proved	1,001,942
Field and other property and equipment	6,955
Investment in equity affiliates	15,047
Goodwill	76,826
Other assets	3,514
Accounts payable and accrued liabilities	(192,534)
Derivative liabilities – current	(44,002)
Long-term debt	(140,000)
Deferred tax liability	(83,250)
Derivative liabilities – noncurrent	(14,592)
Asset retirement obligations	(142,100)
Other liabilities	(7,200)
Fair value of net assets acquired	$	654,616

Central Basin Platform Acquisition

In December 2021, we acquired from an unrelated third-party certain operated producing oil and natural gas properties predominately located in the Central Basin Platform in Texas and New Mexico, with additional properties in the southwestern Permian and Powder River Basins, for total cash consideration of $60.4 million, including customary purchase price

17

adjustments (the "Central Basin Platform Acquisition"). The purchase price was funded using cash on hand and borrowings under our Revolving Credit Facility. We accounted for the Central Basin Platform Acquisition as an asset acquisition and recorded an additional $73.7 million of proved oil and natural gas properties, including an ARO asset of $12.6 million.

DJ Basin Acquisition

In March 2021, we acquired a portfolio of oil and natural gas mineral assets located in the DJ Basin from an unrelated third-party operator for total consideration of $60.8 million (the "DJ Basin Acquisition"). The DJ Basin Acquisition was funded using cash on hand and borrowings under our prior credit agreements. We accounted for the DJ Basin Acquisition as an asset acquisition and the purchase price was allocated 35.6% to proved oil and natural gas properties and 64.4% to unproved oil and natural gas properties. In conjunction with the DJ Basin Acquisition, we issued equity-based compensation, a portion of which is classified within permanent equity as noncontrolling interest and the remainder of which is classified as other liabilities, to certain parties of the transaction.

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 nine months ended September 30, 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 Contango 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 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. The carrying value of our equity method investment in Chama at September 30, 2022 was $4.1 million.

Claiborne Parish Divestiture

In December 2021, we entered into a purchase and sale agreement with an unaffiliated third-party that encompassed the sale of certain producing properties and oil and natural gas leases in Claiborne Parish, Louisiana in exchange for cash consideration, net of closing adjustments, of $4.3 million.

Arkoma Basin Divestiture

In May 2021, we executed a purchase and sale agreement with an unaffiliated third-party that encompassed the sale of certain producing properties and oil and natural gas leases in the Arkoma Basin in exchange for cash consideration, net of closing adjustments, of $22.1 million. We recorded an $8.8 million gain on sale of assets in 2021 related to the transaction.

NOTE 4 – Derivatives

In the normal course of business, we are exposed to certain risks including changes in the prices of oil, natural gas and NGLs which may impact the cash flows associated with the sale of our future oil and natural gas production. We enter into derivative contracts with lenders under our Revolving Credit Facility that consists of either a single derivative instrument or a combination of instruments to manage our exposure to these risks.

As of September 30, 2022, our commodity derivative instruments consisted of fixed price swaps and collars which are described below:

Fixed Price and Basis Swaps: Fixed price swaps receive a fixed price and pay a floating market price to the counterparty on the notional amount. Our basis swaps fix the basis differentials between the index price at which we sell our production as compared to the index price used in the basis swap. Under a swap contract, we will receive payment if the settlement price is less than the fixed price and will make a payment to the counterparty if the settlement price is greater than the fixed price.

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

The following table details our net volume positions by commodity as of September 30, 2022:

Production Period	Volumes	Weighted Average Fixed Price			Fair Value
Crude oil swaps (Bbls):	(in thousands)				(in thousands)
WTI
2022	3,301	$64.08			$	(46,646)
2023	9,710	$60.00			(115,421)
2024	5,721	$63.82			(16,008)
Brent
2022	126	$56.36			(3,377)
2023	527	$52.52			(12,202)
2024	276	$68.65			(868)
Crude oil collars – WTI (Bbls):
2023	1,155	$48.68	-	$57.87	(18,071)
Natural gas swaps (MMBtu):
2022	20,180	$2.78			(82,379)
2023	62,248	$2.73			(165,728)
2024	9,604	$4.14			(5,247)
NGL swaps (Bbls):
2022	736	$32.55			95
2023	1,379	$40.80			13,745
Crude oil basis swaps (Bbls):
2022	1,413	$(0.15)			(3,252)
Natural gas basis swaps (MMBtu):
2022	6,230	$(0.16)			2,766
Calendar Month Average ("CMA") roll swaps (Bbls):
2022	364	$1.08			31
Natural gas collars (MMBtu):
2023	550	$2.63	-	$3.01	(1,725)
2024	18,300	$3.38	-	$4.56	(11,974)
Total					$	(466,261)

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We use derivative commodity instruments and enter into swap contracts that are governed by International Swaps and Derivatives Association master agreements. The following table shows the effects of master netting arrangements on the fair value of our derivative contracts as of September 30, 2022 and December 31, 2021:

	Gross Fair Value		Effect of Counterparty Netting		Net Carrying Value
	(in thousands)
September 30, 2022
Assets:
Derivative assets – current	$	27,574	$	(20,454)	$	7,120
Derivative assets – noncurrent	21,488		(21,488)		—
Total assets	$	49,062	$	(41,942)	$	7,120
Liabilities:
Derivative liabilities – current	$	(404,492)	$	20,454	$	(384,038)
Derivative liabilities – noncurrent	(110,831)		21,488		(89,343)
Total liabilities	$	(515,323)	$	41,942	$	(473,381)
December 31, 2021
Assets:
Derivative assets – current	$	2,983	$	(2,983)	$	—
Derivative assets – noncurrent	4,834		(4,255)		579
Total assets	$	7,817	$	(7,238)	$	579
Liabilities:
Derivative liabilities – current	$	(256,508)	$	2,983	$	(253,525)
Derivative liabilities – noncurrent	(137,726)		4,255		(133,471)
Total liabilities	$	(394,234)	$	7,238	$	(386,996)

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, 2022 and 2021:

	Three Months Ended September 30,				Nine Months Ended September 30,
	2022		2021		2022		2021
	(in thousands)
Derivatives not designated as hedging instruments:
Realized gain (loss) on oil positions	$	(90,268)	$	(49,121)	$	(337,124)	$	(115,107)
Realized gain (loss) on early settlement of certain oil positions	—		—		—		(198,688)
Realized gain (loss) on natural gas positions	(115,595)		(22,653)		(259,070)		(25,020)
Realized gain (loss) on NGL positions	(5,849)		(20,978)		(58,183)		(45,146)
Realized gain (loss) on interest hedges	—		(351)		—		(7,373)
Total realized gain (loss) on derivatives	(211,712)		(93,103)		(654,377)		(391,334)
Unrealized gain (loss) on commodity hedges	416,842		(189,119)		8,812		(501,045)
Unrealized gain (loss) on interest hedges	—		—		—		7,347
Total unrealized gain (loss) on derivatives	416,842		(189,119)		8,812		(493,698)
Gain (loss) on derivatives	$	205,130	$	(282,222)	$	(645,565)	$	(885,032)

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NOTE 5 – Fair Value Measurements

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

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

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

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

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

Recurring Fair Value Measurements

The following table presents the fair value of our derivative assets and liabilities that were accounted for at fair value on a recurring basis as of September 30, 2022 and December 31, 2021 by level within the fair value hierarchy:

	Fair Value Measurement Using
	Level 1		Level 2		Level 3		Total
	(in thousands)
September 30, 2022
Financial assets:
Derivative assets	$	—	$	49,062	$	—	$	49,062
Financial liabilities:
Derivative liabilities	$	—	$	(515,323)	$	—	$	(515,323)
December 31, 2021
Financial assets:
Derivative assets	$	—	$	7,817	$	—	$	7,817
Financial liabilities:
Derivative liabilities	$	—	$	(394,234)	$	—	$	(394,234)

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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 below) as of September 30, 2022 and December 31, 2021 was approximately $629.6 million and $521.5 million based on quoted market prices.

NOTE 6 – Accounts Payable and Accrued Liabilities

Accounts payable and accrued liabilities consisted of the following as of September 30, 2022 and December 31, 2021: 

	September 30, 2022		December 31, 2021
	(in thousands)
Accounts payable and accrued liabilities:
Accounts payable	$	138,922	$	87,336
Accrued lease and asset operating expense	58,582		55,228
Accrued capital expenditures	48,330		60,647
Accrued general and administrative expense	13,936		12,193
Accrued transportation expense	27,539		20,639
Accrued revenue and royalties payable	194,733		75,827
Accrued interest expense	24,615		6,325
Accrued severance taxes	71,207		5,062
Other	18,251		14,624
Total accounts payable and accrued liabilities	$	596,115	$	337,881

NOTE 7 – Debt

Senior Notes

In May 2021, Independence Energy Finance LLC (n/k/a Crescent Energy Finance LLC), our wholly owned subsidiary, issued $500.0 million aggregate principal amount of 7.250% senior notes due 2026 (the "Original 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 "New Notes" and, together with the Original Notes, the "Senior Notes"). Both issuances of the 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 Senior 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.

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

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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 Senior Notes indenture contains 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.

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

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

In connection with the Senior Notes issuance in May 2021, we entered into 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. We have entered into amendments to the Revolving Credit Facility, which have (i) increased our elected commitment amount from $700.0 million to $1.3 billion, (ii) increased our borrowing base from $1.3 billion to $2.0 billion, (iii) increased our maximum credit amount from $1.5 billion to $3.0 billion, (iv) extended the maturity date from May 6, 2025 to September 23, 2027 and (v) reduced the applicable margin by 0.50% so that loans under the Revolving Credit Facility will be priced based on SOFR 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 credit facility contains terms that if certain conditions regarding our outstanding Senior Notes exist in January 2026, it will mature in January 2026 prior to the extended maturity date. At September 30, 2022, we had $685.0 million of borrowings and $12.2 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.

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Interest

Borrowings under the Revolving Credit Facility bear interest at either (i) a U.S. dollar alternative base rate (based on the prime rate, the federal funds effective rate or an adjusted secured overnight financing rate (“SOFR”)), plus an applicable margin or (ii) SOFR, plus an applicable margin, at the election of the borrowers. The applicable margin varies based upon our borrowing base utilization then in effect. The fee payable for the unused revolving commitments 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, 2022 was 5.39%.

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, 2022, we had letters of credit outstanding of $12.2 million, which reduce the amount available to borrow under our Revolving Credit Facility.

Total Debt Outstanding

The following table summarizes our debt balances as of September 30, 2022 and December 31, 2021:

	Debt Outstanding		Letters of Credit Issued		Borrowing Base		Maturity
	(in thousands)
September 30, 2022
Revolving Credit Facility	$	685,000	$	12,224	$	2,000,000	9/23/2027
7.250% Senior Notes due 2026	700,000		—		—		5/1/2026
Less: Unamortized discount and issuance costs	(12,666)
Total long-term debt	$	1,372,334
December 31, 2021
Revolving Credit Facility	$	543,000	$	20,653	$	1,300,000	5/6/2025
7.250% Senior Notes due 2026	500,000		—		—		5/1/2026
Less: Unamortized discount and issuance costs	(12,594)
Total long-term debt	$	1,030,406

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NOTE 8 – Asset Retirement Obligations

Our ARO liabilities are based on our net ownership in wells and facilities and management’s estimate of the costs to abandon and remediate those wells and facilities together with management’s estimate of the future timing of the costs to be incurred. The following table summarizes activity related to our ARO liabilities for the nine months ended September 30, 2022:

	As of September 30, 2022
	(in thousands)
Balance at beginning of period	$	266,007
Acquisitions	37,203
Additions	533
Retirements	(6,949)
Sale	(12,718)
Change in estimate	1,968
Accretion expense	15,399
Balance at end of period	301,443
Less: current portion	(11,321)
Balance at end of period, noncurrent portion	$	290,122

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, 2022.

On February 14, 2022, the New Mexico Energy, Minerals and Natural Resources Department’s Oil Conservation Division announced a civil penalty of $0.9 million to Contango related to certain regulatory infractions. The parties are discussing a resolution to the matter.

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:

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	Three Months Ended September 30,				Nine Months Ended September 30,
	2022		2021		2022		2021
	(in thousands)
ASC 710 profits interest awards	$	334	$	—	$	834	$	—
ASC 718 liability-classified profits interest awards	(2,321)		4,834		9,892		13,006
ASC 718 equity-classified profits interest awards	—		57		—		1,621
ASC 718 equity-classified RSU awards	399		—		793		—
ASC 718 equity-classified PSU awards	7,758		—		15,621		—
Total expense (income)	$	6,170	$	4,891	$	27,140	$	14,627

Our incentive compensation awards may contain certain service-based, performance-based, and market-based vesting conditions, which are further discussed below.

ASC 710 compensation awards

Incentive unit awards

Certain of our subsidiaries have issued incentive awards that require continuous service in order to receive distributions, and do not represent an equity interest. As these incentive awards are similar to a cash bonus plan, compensation cost is measured based on the present value of expected benefits that are probable of being paid and recognized over the period services are provided. Compensation cost is remeasured at each reporting period based on expected future benefits.

ASC 718 stock-based compensation awards

Liability-classified profits interest awards

Certain of our subsidiaries issue profits interests that are liability-classified stock-based compensation awards. These awards contain different vesting conditions ranging from performance-based conditions that vest upon the achievement of certain return thresholds to time-based service requirements ranging from one year to four years. Each of these profits interests is liability-classified because of certain features within these awards that predominantly contain characteristics of liability instruments. Compensation cost for these awards is presented within General and administrative expense on the condensed consolidated statements of operations with a corresponding credit to Other long-term liabilities on the condensed consolidated balance sheets.

Equity-classified profits interest awards

Certain of our subsidiaries issue equity-classified profits interests awards. These awards contain different vesting conditions ranging from performance-based conditions that vest upon the achievement of certain return thresholds to time-based service requirements ranging from one year to four years. Each of these profits interests is equity-classified because of certain features within these awards that predominantly contain characteristics of equity instruments. 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 on the condensed consolidated balance sheets.

Equity-classified RSU Awards

During the nine months ended September 30, 2022, we granted 130,334 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 $18.41 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 on the condensed consolidated balance sheets.

Equity-classified PSU Awards

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In conjunction with the Merger Transactions, we granted equity-classified PSUs under the Crescent Energy Company 2021 Manager Incentive Plan. The PSU performance periods are three years with the performance period end dates ranging from 2024 through December 2028. Each of these units represent the right to receive a target 2% of our issued and outstanding Class A Common Stock on each unit's performance period end date, modified by an amount ranging from 0% to 240% based on certain absolute and relative shareholder return components. 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 on the condensed consolidated balance sheets.

In conjunction with the Offering, we increased our Class A Common Stock share count by 6.3 million shares. As a result, the number of PSU target Class A Shares increased by 0.6 million shares, and we recognized a stock-based compensation award change in estimate in connection with such increase. As a result of this change in estimate, we recognized an additional expense of $0.2 million during the three and nine months ended September 30, 2022.

NOTE 11 – Related Party Transactions

KKR Group

Management Agreement

In connection with the Merger Transactions, we 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") equal to $15.4 million per annum, which represents our pro rata portion (based on our relative ownership of OpCo) of $53.3 million. This pro rata amount will increase over time as our ownership percentage of OpCo increases. In addition, as our business and assets expand, Manager Compensation may increase by an amount equal to 1.5% per annum of the net proceeds from all future issuances of our equity securities (including in connection with acquisitions). However, incremental Manager Compensation will not apply to the issuance of our shares upon the redemption or exchange of OpCo Units. During the three 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. In addition, at September 30, 2022 we accrued $9.5 million for distributions to our redeemable noncontrolling interests in OpCo related to the Management Agreement which will be paid during the fourth quarter of 2022.

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, 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

27

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, 2022 and December 31, 2021, we had a related party receivable of $0.3 million and $3.3 million, respectively, included within Accounts receivable – affiliates and a related party payable of $39.7 million and $7.0 million, respectively, included within Accounts payable – affiliates on our condensed consolidated balance sheets associated with KKR Funds transactions.

Secondary Offering

In September 2022, KCM received $1.3 million in underwriter discounts and commissions in connection with the Offering. Refer to further discussion in NOTE 1 – Organization and Basis of Presentation regarding the Equity Transactions.

Other Transactions

During the nine months ended September 30, 2022, we incurred $0.7 million in fees to KKR Capital Markets LLC ("KCM"), an affiliate of KKR Group, in connection with the New Notes (as defined below). 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.

FDL

Certain of our consolidated subsidiaries previously entered into an Oil and Natural Gas Property Operating and Services Agreement (the “FDL Agreement”) with FDL Operating LLC ("FDL"). As of December 31, 2021, we had a net related party receivable due from FDL totaling $16.9 million, included within Accounts receivable - affiliates on our condensed consolidated balance sheets, which was settled during the nine months ended September 30, 2022.

On April 1, 2021, certain minority investors, including FDL Operating LLC ("FDL") management, exchanged 100% of their interests in our Barnett basin natural gas assets for 9,508 of our predecessor Class A units, representing 0.77% of our consolidated ownership. Since we already consolidate the results of these assets, this transaction was accounted for as an equity transaction and reflected as a reclassification from noncontrolling interests to members' equity with no gain or loss recognized on the exchange (the "April 2021 Exchange").

In September 2021, we provided notice that we were terminating the FDL Agreement effective on March 31, 2022 and, as part of the termination principal terms, we agreed to pay up to $6.7 million in wind down costs and additional severance costs for certain qualifying, dedicated employees. We recorded general and administrative expense of $3.3 million in the fourth quarter of 2021 associated with the termination and had $2.3 million deposited in an escrow account to fund these wind down costs at September 30, 2022.

In May 2022, we repurchased all of the noncontrolling interests and working interests in our assets held directly by affiliates of FDL for aggregate consideration of approximately $8.8 million, effectively purchasing the remainder of FDL's management ownership of certain of our consolidated subsidiaries. Subsequent to this transaction, FDL is no longer a related party and we have no remaining relationship with FDL other than the payment of wind down costs, which we expect to be fully funded by the amount already deposited in escrow and recorded as Other assets on our 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.

As described in NOTE 1 – Organization and Basis of Presentation, our financial statements have been retrospectively recast to reflect the historical accounts of Independence on a combined basis due to the Merger Transactions. Net income (loss) for

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periods prior to the Merger Transactions is allocated to our Predecessor as our Predecessor's Class A Units were exchanged for shares of Class B Common Stock in connection with the Merger Transactions. Net income (loss) attributable to Crescent Energy is allocated to Class A Common Stock and Class B Common Stock based on the participation rights of each class to share in undistributed earnings and losses after giving effect to dividends declared during the period, if any.

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,
	2022		2021		2022		2021
	(in thousands, except share and per share amounts)
Numerator:
Net income (loss)	$	555,349	$	(162,043)	$	431,240	$	(601,172)
Less: net loss attributable to Predecessor	—		160,567		—		585,804
Less: net (income) loss attributable to noncontrolling interests	(904)		1,476		(2,087)		15,368
Less: net (income) loss attributable to redeemable noncontrolling interests	(436,084)		—		(341,269)		—
Net income (loss) attributable to Crescent Energy - basic	118,361		—		87,884		—
Add: Reallocation of net income attributable to redeemable noncontrolling interest for the dilutive effect of RSUs	33		—		10		—
Net income (loss) attributable to Crescent Energy - diluted	$	118,394	$	—	$	87,894	$	—
Denominator:
Weighted-average Class A common stock outstanding – basic	43,196,791				42,376,668
Add: dilutive effect of RSUs	13,524				5,173
Weighted-average Class A common stock outstanding – diluted	43,210,315				42,381,841
Weighted-average Class B common stock outstanding – basic and diluted	125,796,892				126,950,234
Net income (loss) per share:
Class A common stock – basic	$	2.74			$	2.07
Class A common stock – diluted	$	2.74			$	2.07
Class B common stock – basic and diluted	$	—			$	—

NOTE 13 – Subsequent Events

Dividend

On November 9, 2022, the Board of Directors approved a quarterly cash dividend of $0.17 per share, or $0.68 per share on an annualized basis, to be paid to shareholders of our Class A Common Stock with respect to the third quarter of 2022. The quarterly dividend is payable on December 7, 2022 to shareholders of record as of the close of business on November 23, 2022. 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.

Permian Basin Divestiture

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On November 4, 2022, we entered into a definitive purchase and sale agreement with an unaffiliated third party to sell certain of our non-core producing properties and related oil and natural gas leases in Ector County in the Permian Basin in exchange for cash consideration, subject to customary purchase price adjustments, of $80.0 million. The net book value for these assets is $77.7 million, including ARO liability of $3.9 million as of September 30, 2022. Subject to customary closing conditions, this transaction is expected to close by year-end 2022.

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

Management's Discussion and Analysis of Financial Condition and Results of Operations ("MD&A") is intended to provide the reader of the financial statements with a narrative from the perspective of management on the financial condition, results of operations, liquidity and certain other factors that may affect the Company's operating results. The following discussion and analysis should be read in conjunction with Management's Discussion and Analysis of Financial Condition and Results of Operations in our Annual Report on Form 10-K for the year ended December 31, 2021 ("Annual Report"), our Quarterly Reports on Form 10-Q for the periods ended March 31, 2022 and June 30, 2022, as well as our unaudited condensed consolidated financial statements for the three and nine months ended September 30, 2022 and 2021. 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, 2022 and 2021. 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 for time periods prior to the Merger Transactions refer to Crescent Energy OpCo LLC (f/k/a Independence Energy LLC) and its subsidiaries, our predecessor for accounting purposes. For time periods subsequent to the Merger Transactions, these terms refer to Crescent Energy Company and its subsidiaries.

Business

We are a well-capitalized U.S. independent energy company with a portfolio of assets in key proven regions across the lower 48 states, including the Eagle Ford, Rockies, Barnett and Permian.

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

Merger Transactions and Reorganization

On December 7, 2021, we completed a series of transactions, pursuant to which the business of Contango Oil & Gas Company (“Contango”) and the business of Independence Energy LLC (“Independence”) combined under a new publicly traded holding company named "Crescent Energy Company" (the “Merger Transactions”). Our Class A common stock, par value $0.0001 per share (“Class A Common Stock") is listed on The New York Stock Exchange under the symbol “CRGY.” The combined company is structured as an “Up-C,” with all of our assets and operations (including those of Contango) indirectly held by our operating subsidiary, Crescent Energy OpCo LLC ("OpCo"). Crescent Energy Company ("Crescent") is a holding company, the sole material asset of which consists of economic, non-voting limited liability company interests in OpCo ("OpCo Units"), and is responsible for all operational, management and administrative decisions related to OpCo’s business. We are the sole managing member of OpCo. Crescent consolidates the financial results of OpCo and its subsidiaries. Former Contango shareholders own shares of Class A Common Stock, which have both voting and economic rights. The former owners of our predecessor, Independence Energy LLC, own economic, non-voting OpCo Units and corresponding shares of Class B common stock, par value $0.0001 per share ("Class B Common Stock," together with Class A Common Stock, the "Common Stock"), which shares of Class B Common Stock have voting (but no economic) rights. 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.

In connection with the Merger Transactions, we underwent a reorganization (the “Crescent Reorganization”), whereby Independence merged with and into OpCo (the “Isla Merger”). The financial statements include the accounts of Independence from the date of the Isla Merger, which is the date the Company obtained a controlling financial interest in Independence on a consolidated basis. Because the Isla Merger resulted in a change in the reporting entity, and in order to furnish comparative

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financial information prior to the Isla Merger, our financial statements have been retrospectively recast to reflect the historical accounts of Independence, our accounting predecessor (the "Predecessor"), on a combined basis.

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. In particular, the global spread of the COVID-19 virus during 2020 and 2021 had a negative impact on the global demand for oil and natural gas and caused significant commodity market volatility. While the increase in domestic vaccination programs and reduced spread of the COVID-19 virus has contributed to an improvement in the economy and higher realized prices for commodities, the current price environment remains uncertain as responses to the COVID-19 pandemic and newly emerging variants of the virus continue to evolve. Given the dynamic nature of these events, we cannot reasonably estimate the period of time that the COVID-19 pandemic and related market conditions will persist. 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.

In addition, in February 2022, Russia launched a large-scale invasion of Ukraine that has led to significant armed hostilities. As a result, the United States, the United Kingdom, the member states of the European Union and other public and private actors have levied severe sanctions on Russian financial institutions, businesses and individuals. This conflict, and the resulting sanctions, have contributed to significant increases and volatility in the price for oil and natural gas, with the posted price for WTI reaching a high of over $120 per barrel. Such volatility may lead to a more difficult investing and planning environment for us and our customers. While the near-term impact of these events resulted in higher oil and gas prices in 2022, the geopolitical and macroeconomic consequences of this invasion and associated sanctions cannot be predicted, and such events, or any further hostilities in Ukraine or elsewhere, could severely impact the world economy and may adversely affect our financial condition. Furthermore, the United States has experienced a significant inflationary environment in 2022 that, along with international geopolitical risks, has contributed to concerns of a potential recession that has caused oil and gas prices to retreat from their earlier highs in 2022 and has created further volatility.

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 has been steadily increasing since 2021. 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, and to the extent elevated inflation remains, we may experience further cost increases for our operations, including oilfield services, labor costs and equipment if our drilling activity increases. Higher oil and natural gas prices may cause the costs of materials and services to continue to rise. We cannot predict any future trends in the rate of inflation and a significant increase in inflation, to the extent we are unable to recover higher costs through higher oil and natural gas prices and revenues, would negatively impact our business, financial condition and results of operations. See Part II, 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 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 GHGs through a methane emissions charge, including onshore petroleum and natural gas production. The methane emissions charge will start in calendar year 2024 and the fee is based on certain thresholds established in the IRA 2022. The methane emissions charge could increase our operating costs and adversely affect our business and results of operations. See Part II, Item 1A. Risk Factors for additional information. Finally, the IRA 2022 includes a new corporate alternative minimum tax of 15% on the adjusted financial statement income ("AFSI") of corporations with average AFSI exceeding $1.0 billion over a three-year period. While we are evaluating the impact of the new corporate alternative minimum tax will have, we do not believe that it will have a material impact on our near-term taxes.

Equity Transactions

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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 5.75 million shares of our Class A Common Stock (the "Offering") at a price to the public of $15.00 per share, or a net of $14.10 per share after deducting the underwriters' discounts and commissions. 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 8.9 million. After the Equity Transactions, shares of our Class A Common Stock represent approximately 29% of the outstanding shares of Class A Common Stock and Class B Common Stock, taken together, and we own approximately 29% of the outstanding OpCo Units. 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.

Acquisitions and divestitures

Acquisitions

In March 2022, we consummated the acquisition contemplated by the Membership Interest Purchase Agreement dated February 15, 2022 (the “Purchase Agreement” and 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. Such assets include an aggregate approximately 145,000 net acres, primarily located in Duchesne and Uintah Counties, Utah, with approximately 400 currently producing wells. Upon closing of the Uinta Transaction on March 30, 2022, we paid $621.3 million in cash consideration and related transaction fees and assumed certain commodity derivatives. The Uinta Transaction was funded with cash on hand and borrowings under our Revolving Credit Facility. In connection with the closing of the Uinta Transaction, we entered into an amendment to our Revolving Credit Facility to, among other things, increase the borrowing base to $1.8 billion and the elected commitment amount to $1.3 billion. We incurred financing costs of $13.4 million associated with this amendment.

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.

In December 2021, we acquired from an unrelated third-party certain operated producing oil and natural gas properties predominately located in the Central Basin Platform in Texas and New Mexico, with additional properties in the southwestern Permian and Powder River Basins, for total cash consideration of $60.4 million, including customary purchase price adjustments (the "Central Basin Platform Acquisition"). The purchase price was funded using cash on hand and borrowings under our Revolving Credit Facility (as defined below).

In May 2021, certain of our consolidated subsidiaries redeemed the noncontrolling equity interests held in such subsidiaries by a third-party investor in exchange for the third-party investor’s proportionate share of the underlying oil and natural gas interests held by its consolidated subsidiaries as part of the "Noncontrolling Interest Carve-out." Additionally, the third-party investor contributed cash of approximately $35.5 million to repay its proportionate share of the underlying debt outstanding under our prior credit agreements and other liabilities. The percentage ownership of these certain consolidated subsidiaries owned by the third-party investor ranges from 2.21% to 7.38%.

In April 2021, certain minority investors exchanged 100% of their interests in our Barnett basin natural gas assets for 9,508 of our Class A Units, representing 0.77% of our consolidated ownership pursuant to (the "April 2021 Exchange"). Since we already consolidate the results of these assets, this transaction was accounted for as an equity transaction and reflected as a reclassification from noncontrolling interests to members’ equity with no gain or loss recognized on the April 2021 Exchange.

In March 2021, we acquired a portfolio of oil and natural gas mineral assets located in the DJ Basin from an unrelated third-party operator for total consideration of $60.8 million (the "DJ Basin Acquisition"). The DJ Basin Acquisition was funded using

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cash on hand and borrowings under our prior credit agreements. We accounted for the DJ Basin Acquisition as an asset acquisition.

Divestitures

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 in the Permian Basin in exchange for cash consideration, subject to customary purchase price adjustments, of $80.0 million. The net book value for these assets is $77.7 million, including ARO liability of $3.9 million as of September 30, 2022. Subject to customary closing conditions, this transaction is expected to close by year-end 2022.

In April 2022, our equity method investment, Exaro Energy III, LLC ("Exaro") entered into a purchase and sale agreement to sell its operations in the Jonah Field in Wyoming. During the nine months ended September 30, 2022 we received a distribution from Exaro Energy of $6.8 million primarily as a result of the sale.

In February 2022, we contributed all of the assets and prospects in the Gulf of Mexico formerly owned by Contango to Chama Energy LLC ("Chama"), in exchange for a 9.4% interest in Chama, which we valued at approximately $3.8 million. As a result, we derecognized these contributed assets and liabilities from our condensed consolidated balance sheets and recorded an equity method investment for our interest in Chama, as well as a $4.5 million gain related to on the deconsolidation of these assets and liabilities. John Goff, the Chairman of our Board of Directors, holds an approximate interest of 17.5% in Chama, and the remaining interests are held by other 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. The carrying value of our equity method investment in Chama at September 30, 2022 was $4.1 million.

In December 2021, we entered into an assignment, conveyance and bill of sale with an unaffiliated third-party that encompassed the sale of certain producing properties and oil and natural gas leases in Claiborne Parish, Louisiana in exchange for cash consideration, net of closing adjustments, of $4.3 million.

In May 2021, we executed a purchase and sale agreement with an unaffiliated third-party that encompassed the sale of certain producing properties and oil and natural gas leases in the Arkoma Basin in exchange for cash consideration, net of closing adjustments, of $22.1 million.

Environmental, social and corporate governance ("ESG") initiatives

We view exceptional ESG performance as an opportunity to differentiate Crescent from our peers, mitigate risks and strengthen operational performance as well as benefit our stakeholders and the communities in which we operate. In September 2022, we released our 2021 ESG report. The report included benchmarks for measuring future performance, consistent with Crescent's commitment to aligning with the SASB and Task Force on Climate-related Financial Disclosures frameworks, noted the progress of our key ESG priorities and detailed our goals to reduce greenhouse gas ("GHG") emissions in support of an economy-wide transition to a net-zero world. We also established an ESG Advisory Council to advise management and our Board of Directors on ESG-related issues. We are working to reduce GHG emissions by implementing ambitious methane reduction targets and eliminating routine flaring, among other initiatives. In February 2022, we joined the Oil & Gas Methane Partnership ("OGMP") 2.0 Initiative to enhance reporting of methane emissions reduction programs. Our inaugural OGMP 2.0 submission was rated the highest-level, "Gold Standard."

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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 $600 million to $700 million, excluding acquisitions, for our 2022 capital program. The majority of our program is allocated to D&C, with approximately 80% allocated to our operated assets primarily in the Eagle Ford and Uinta basins. We expect to fund our 2022 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, 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,
	2022		2021		2022		2021
Oil	64	%	63	%	66	%	64	%
Natural gas	28	%	24	%	25	%	24	%
NGLs	8	%	13	%	9	%	12	%

In addition, revenue from our midstream assets is supported by commercial agreements that have established minimum volume commitments. These midstream revenues comprise the majority of our midstream and other revenue. Midstream and other revenue accounts for 3% or less of our total revenues for the three and nine months ended September 30, 2022 and 2021.

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Production volumes sold

The following table presents historical sales volumes for our properties:

	Three Months Ended September 30,		Nine Months Ended September 30,
	2022	2021	2022	2021
Oil (MBbls)	6,348	3,197	16,114	9,866
Natural gas (MMcf)	33,735	21,620	96,102	64,925
NGLs (MBbls)	1,840	1,551	5,452	4,488
Total (MBoe)	13,811	8,351	37,583	25,175
Daily average (MBoe/d)	150	91	138	92

Total sales volume increased 5,460 MBoe and 12,408 MBoe during the three and nine months ended September 30, 2022, respectively, compared to the three and nine months ended September 30, 2021. The increase is primarily due to the Merger Transactions, DJ Basin Acquisition and Central Basin Platform Acquisition (collectively, the "2021 Acquisitions") and our Uinta Transaction, which contributed an additional 2,977 MBoe and 2,878 MBoe for the three months ended September 30, 2022, respectively, and 8,813 MBoe and 5,234 MBoe for the nine months ended September 30, 2022, respectively. Sales volumes from our other assets decreased by 395 and 1,639 MBoe during the three and nine months ended September 30, 2022, respectively, compared to the three and nine months ended September 30, 2021, primarily as a result of the natural decline from our existing asset base, partially offset by new operated Eagle Ford and Uinta well completions in 2022.

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. The outbreak of the COVID-19 virus followed by certain actions taken by OPEC caused crude oil prices to decline significantly beginning in the first half of 2020 and prices remained below pre-pandemic levels for a prolonged period of time. Commodity prices were higher in the three and nine months ended September 30, 2022, compared with the three and nine months ended September 30, 2021, reflecting the ongoing recovery in the oil and gas industry in 2022 due to increasing demand as more states and countries re-open and national and global economies recover from the global COVID-19 pandemic and a premium due to the reduction in crude oil supply resulting from sanctions imposed on Russia in response to its large-scale invasion of Ukraine in February 2022. Although commodity prices have increased substantially in 2022, uncertainty persists regarding OPEC’s actions, increased U.S. drilling, the continued effect from the COVID-19 pandemic, inflation and the armed conflict in Ukraine.

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,
	2022		2021		2022		2021
Oil	58	%	80	%	65	%	81	%
Natural gas	61	%	86	%	67	%	84	%
NGLs	42	%	65	%	47	%	69	%

The following table sets forth the average NYMEX oil and natural gas prices and our average realized prices for the periods presented:

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	Three Months Ended September 30,				Nine Months Ended September 30,
	2022		2021		2022		2021
Oil (Bbl):
Average NYMEX	$	91.56	$	70.62	$	98.09	$	64.83
Realized price (excluding derivative settlements)	86.77		69.46		94.69		63.63
Realized price (including derivative settlements) (1)	72.55		54.10		73.77		51.97
Natural Gas (Mcf):
Average NYMEX	$	7.37	$	4.36	$	6.50	$	3.62
Realized price (excluding derivative settlements)	6.99		4.01		6.10		3.55
Realized price (including derivative settlements)	3.56		2.97		3.41		3.16
NGLs (Bbl):
Realized price (excluding derivative settlements)	$	35.22	$	30.53	$	40.33	$	27.10
Realized price (including derivative settlements)	32.04		16.99		29.65		17.04

(1)     For the three and nine months ended September 30, 2021, the realized price excludes the impact of the settlement of certain of our outstanding derivative oil commodity contracts associated with calendar years 2022 and 2023 for $198.7 million in June 2021. Subsequent to the settlement, we entered into new commodity derivative contracts at prevailing market prices.

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Results of operations:

Three Months Ended September 30, 2022 Compared to Three Months Ended September 30, 2021

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,
	2022		2021		$ Change		% Change
Revenues (in thousands):
Oil	$	550,823	$	222,074	$	328,749	148	%
Natural gas	235,830		86,779		149,051		172	%
Natural gas liquids	64,810		47,322		17,488		37	%
Midstream and other	13,494		9,553		3,941		41	%
Total revenues	$	864,957	$	365,728	$	499,229	137	%
Average realized prices, before effects of derivative settlements:
Oil ($/Bbl)	$	86.77	$	69.46	$	17.31	25	%
Natural gas ($/Mcf)	6.99		4.01		2.98		74	%
NGLs ($/Bbl)	35.22		30.51		4.71		15	%
Total ($/Boe)	61.65		42.65		19.00		45	%
Net sales volumes:
Oil (MBbls)	6,348		3,197		3,151		99	%
Natural gas (MMcf)	33,735		21,620		12,115		56	%
NGLs (MBbls)	1,840		1,551		289		19	%
Total (MBoe)	13,811		8,351		5,460		65	%
Average daily net sales volumes:
Oil (MBbls/d)	69		35		34		97	%
Natural gas (MMcf/d)	367		235		132		56	%
NGLs (MBbls/d)	20		17		3		18	%
Total (MBoe/d)	150		91		59		65	%

Oil revenue. Oil revenue increased $328.7 million, or 148%, in the three months ended September 30, 2022, compared to the three months ended September 30, 2021. This was driven primarily by higher realized oil prices that resulted in an increase of $109.9 million (an increase of 25% per Bbl) and a $218.8 million increase in sales volume (34 MBbls/d or 97%). The increase in sales volumes is primarily related to our 2021 Acquisitions and our Uinta Transaction, which contributed an additional 963 MBbls and 2,086 MBbls, respectively, combined with an increase from our existing asset base of 102 MBbls driven by new operated Eagle Ford and Uinta well completions in 2022.

Natural gas revenue. Natural gas revenue increased $149.1 million, or 172% in the three months ended September 30, 2022, compared to the three months ended September 30, 2021. This was driven primarily by higher natural gas prices that resulted in an increase of $100.5 million (an increase of 74% per Mcf) and a $48.6 million increase in sales volume (132 MMcf/d, or 56%). The increase in sales volumes were primarily related to our 2021 Acquisitions and our Uinta Transaction, which contributed an additional 9,439 MMcf and 4,758 MMcf, respectively, partially offset by the natural decline from our existing asset base of 2,082 MMcf.

NGL revenue. NGL revenue increased $17.5 million, or 37%, in the three months ended September 30, 2022, compared to the three months ended September 30, 2021. This was driven primarily by higher realized NGL prices that resulted in an increase of $8.7 million (an increase of 15% per Bbl) and a $8.8 million increase in sales volume (3 MBbls/d, or 18%).

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Midstream and other revenue. Midstream and other revenue increased $3.9 million, or 41%, in the three months ended September 30, 2022, compared to the three months ended September 30, 2021, driven primarily by higher midstream revenue related to the 2021 Acquisitions.

Expenses

The following table summarizes our expenses for the periods indicated and includes a presentation on a per Boe basis, as we use this information to evaluate our performance relative to our peers and to identify and measure trends we believe may require additional analysis:

	Three Months Ended September 30,
	2022		2021		$ Change		% Change
Expenses (in thousands):
Operating expense	$	283,289	$	147,322	$	135,967	92	%
Depreciation, depletion and amortization	145,008		73,025		71,983		99	%
General and administrative expense	17,311		11,024		6,287		57	%
Other operating costs	1,782		753		1,029		NM*
Total expenses	$	447,390	$	232,124	$	215,266	93	%
Selected expenses per Boe:
Operating expense, excluding production and other taxes	$	15.33	$	14.28	$	1.05	7	%
Production and other taxes	5.18		3.36		1.82		54	%
Depreciation, depletion and amortization	10.50		8.74		1.76		20	%

* NM = Not meaningful.

Operating expense. Operating expense increased $136.0 million, or 92%, in the three months ended September 30, 2022, compared to the three months ended September 30, 2021, driven primarily by the following factors:

(i)Lease and asset operating expense increased $73.2 million, or 106%, in the three months ended September 30, 2022, compared to the three months ended September 30, 2021. Additionally, lease and asset operating expense per Boe increased $2.03 per Boe from $8.28 per Boe to $10.31 per Boe. This $73.2 million increase was driven primarily by higher production during the three months ended September 30, 2022, due in part to the 2021 Acquisitions and Uinta Transaction, which contributed $44.8 million and $8.6 million to the increase, respectively, general inflationary costs across our assets and 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 prices increase, higher contractually commodity-linked operating costs are offset by higher realizations.

(ii)Gathering, transportation and marketing expense increased $0.1 million, or a nominal percentage, in the three months ended September 30, 2022, compared to the three months ended September 30, 2021. Additionally, gathering, transportation and marketing expense per Boe decreased $2.10 per Boe from $5.34 per Boe to $3.24 per Boe. The decrease on a per Boe basis was driven primarily by lower sulfur processing and transportation expenses.

(iii)Production and other taxes increased $43.4 million, or 155%, in the three months ended September 30, 2022, compared to the three months ended September 30, 2021 and increased $1.82 per Boe, an increase of 54%, to $5.18 per Boe. This increase was driven primarily by higher oil and natural gas revenues, which increased the tax base upon which production and other taxes are calculated.

(iv)Workover expense increased $18.2 million, or 621%, in the three months ended September 30, 2022, compared to the three months ended September 30, 2021. Additionally, workover expense per Boe increased $1.18 per Boe from $0.35 per Boe to $1.53 per Boe. This increase was driven by (i) higher well workover activities that meet our internal return thresholds due to the higher commodity price environment, (ii) general inflationary costs across our assets and (iii) additional costs from our 2021 Acquisitions and Uinta Transaction, which contributed $8.6 million and $4.2 million to the increase, respectively.

(v)Midstream operating expense increased $1.0 million, or 41%, in the three months ended September 30, 2022, compared to the three months ended September 30, 2021.

Depreciation, depletion and amortization. In the three months ended September 30, 2022, depreciation, depletion and amortization increased $72.0 million, or 99%, compared to the three months ended September 30, 2021, driven primarily by

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$26.8 million and $43.3 million of additional depreciation, depletion and amortization due to our 2021 Acquisitions and our Uinta Transaction.

General and administrative expense. General and administrative expense ("G&A") increased $6.3 million, or 57%, for the three months ended September 30, 2022, compared to the three months ended September 30, 2021, primarily driven by (i) an increase in equity-based compensation expense of $0.9 million due to awards that were granted as part of the Merger Transactions offset by the changes in the fair value of the Company's liability-classified profits interest awards and (ii) $3.8 million related to 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, offset by $1.7 million in lower transaction and nonrecurring related expenses. While only the portion borne by us impacts our consolidated statements of operations, we include the full Manager Compensation 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,
	2022		2021		$ Change		% Change
General and administrative expense (in thousands):
Recurring general and administrative expense	$	9,917	$	2,871	$	7,046	245	%
Transaction and nonrecurring expenses	1,558		3,262		(1,704)		(52)	%
Equity-based compensation	5,836		4,891		945		19	%
Total general and administrative expense	$	17,311	$	11,024	$	6,287	57	%
General and administrative expense per Boe:
Recurring general and administrative expense	$	0.72	$	0.34	$	0.38	112	%
Transaction and nonrecurring expenses	0.11		0.39		(0.28)		(72)	%
Equity-based compensation	0.42		0.59		(0.17)		(29)	%

Other operating costs. Other operating costs include exploration expense and gain on sale of assets. Other operating costs changed by $1.0 million, compared to the three months ended September 30, 2021, primarily driven by $1.2 million higher exploration expense recognized during the three months ended September 30, 2022.

Interest expense

In the three months ended September 30, 2022, we incurred interest expense of $27.1 million, as compared to $13.0 million in the three months ended September 30, 2021, a 108% increase. This increase was driven primarily by higher interest rates associated with the issuance of the Senior Notes (as defined below) and an increase in our weighted average debt outstanding during the period related to the Uinta Transaction.

Gain (loss) on derivatives

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

	Three Months Ended September 30,
	2022		2021		$ Change		% Change
Gain (loss) on derivatives (in thousands):
Gain (loss) on commodity derivatives	$	205,130	$	(281,871)	$	487,001	(173)	%
Gain (loss) on interest rate derivatives	—		(351)		351		(100)	%
Gain (loss) on derivatives	$	205,130	$	(282,222)	$	487,352	(173)	%

Our gain on commodity derivatives during the three months ended September 30, 2022 changed by $487.0 million, or 173%, from a comparable loss during the three months ended September 30, 2021 primarily due to changes in commodity prices relative to our strike price.

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Income tax benefit (expense)

For the three months ended September 30, 2021, we were organized as a limited liability company and treated as a flow-through entity for U.S. federal income tax purposes. As a result, the tax provision for the three months ended September 30, 2021 was minimal. Subsequent to the Merger Transactions, we are a corporation that is subject to U.S. federal and state and income taxes on its allocable share of any taxable income from OpCo. For the three months ended September 30, 2022 we recognized income tax expense of $38.5 million for an effective tax rate of 6.5%. 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,
	2022		2021		$ Change		% Change
(in thousands)
Net income (loss)	$	555,349	$	(162,043)	$	717,392	(443)	%
Adjustments to reconcile to Adjusted EBITDAX:
Interest expense	27,057		12,984
Realized (gain) loss on interest rate derivatives	—		351
Income tax expense (benefit)	38,455		393
Depreciation, depletion and amortization	145,008		73,025
Exploration expense	1,909		754
Non-cash (gain) loss on derivatives	(416,842)		189,119
Non-cash equity-based compensation expense	5,836		4,318
(Gain) loss on sale of assets	(127)		(1)
Other (income) expense	2,670		49
Certain redeemable noncontrolling interest distributions made by OpCo related to Manager Compensation	(9,471)		—
Transaction and nonrecurring expenses (1)	8,861		7,619
Early settlement of derivative contracts	—		—
Adjusted EBITDAX (non-GAAP)	$	358,705	$	126,568	$	232,137	183	%
Adjustments to reconcile to Levered Free Cash Flow:
Interest expense, excluding non-cash deferred financing cost amortization	(24,552)		(9,043)
Realized (gain) loss on interest rate derivatives	—		(351)
Current income tax benefit (expense)	877		(393)
Tax-related redeemable noncontrolling interest distributions made by OpCo	(803)		—
Development of oil and natural gas properties	(189,928)		(42,899)
Levered Free Cash Flow (non-GAAP)	$	144,299	$	73,882	$	70,417	95	%

(1)Transaction and nonrecurring expenses of $8.9 million for the three months ended September 30, 2022 were primarily related to (i) merger integration costs and (ii) transition service agreement costs incurred for the Uinta Transaction. Transaction and nonrecurring expenses of $7.6 million for the three months ended September 30, 2021 were primarily related to legal, consulting and other fees incurred for the Merger Transactions.

Adjusted EBITDAX increased by $232.1 million, or 183%, in the three months ended September 30, 2022, compared to the three months ended September 30, 2021, primarily driven by higher revenue associated with our oil, natural gas and NGL production as a result of increased (i) realized prices and (ii) sales volume driven by our 2021 Acquisitions, our Uinta

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Transaction and new operated Eagle Ford and Uinta well completions in 2022. This increase was partially offset by a corresponding increase in operating costs due to higher production volumes, commodity prices and our 2021 Acquisitions and our Uinta Transaction.

Levered Free Cash Flow increased by $70.4 million, or 95%, in the three months ended September 30, 2022 compared to the three months ended September 30, 2021, primarily driven by our increased Adjusted EBITDAX offset by $147.0 million of increased capital expenditures related to our additional reinvestment activities.

Nine Months Ended September 30, 2022 Compared to Nine Months Ended September 30, 2021

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,
	2022		2021		$ Change		% Change
Revenues (in thousands):
Oil	$	1,525,899	$	627,817	$	898,082	143	%
Natural gas	586,318		230,271		356,047		155	%
Natural gas liquids	219,853		121,613		98,240		81	%
Midstream and other	40,231		34,017		6,214		18	%
Total revenues	$	2,372,301	$	1,013,718	$	1,358,583	134	%
Average realized prices, before effects of derivative settlements:
Oil ($/Bbl)	$	94.69	$	63.63	$	31.06	49	%
Natural gas ($/Mcf)	6.10		3.55		2.55		72	%
NGLs ($/Bbl)	40.33		27.10		13.23		49	%
Total ($/Boe)	62.05		38.92		23.13		59	%
Net sales volumes:
Oil (MBbls)	16,114		9,866		6,248		63	%
Natural gas (MMcf)	96,102		64,925		31,177		48	%
NGLs (MBbls)	5,452		4,488		964		21	%
Total (MBoe)	37,583		25,175		12,408		49	%
Average daily net sales volumes:
Oil (MBbls/d)	59		36		23		64	%
Natural gas (MMcf/d)	352		238		114		48	%
NGLs (MBbls/d)	20		16		4		25	%
Total (MBoe/d)	138		92		46		50	%

Oil revenue. Oil revenue increased $898.1 million, or 143%, in the nine months ended September 30, 2022, compared to the nine months ended September 30, 2021. This was driven primarily by higher realized oil prices that resulted in an increase of $500.5 million (an increase of 49% per Bbl) and a $397.6 million increase in sales volume (23 MBbls/d or 64%). The increase in sales volumes primarily related to our 2021 Acquisitions and Uinta Transaction, which contributed an additional 2,881 MBbls and 3,679 MBbls, respectively, partially offset by the natural decline from our existing asset base of 312 MBbls.

Natural gas revenue. Natural gas revenue increased $356.0 million, or 155% in the nine months ended September 30, 2022, compared to the nine months ended September 30, 2021. This was driven primarily by higher natural gas prices that resulted in an increase of $245.3 million (an increase of 72% per Mcf) and a $110.7 million increase in sales volume (114 MMcf/d, or 48%). The increase in sales volumes was primarily related to our 2021 Acquisitions and Uinta Transaction, which contributed an additional 28,113 MMcf and 9,328 MMcf, respectively, partially offset by the natural decline from our existing asset base of 6,264 MMcf.

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NGL revenue. NGL revenue increased $98.2 million, or 81%, in the nine months ended September 30, 2022, compared to the nine months ended September 30, 2021. This was driven primarily by higher realized NGL prices that resulted in an increase of $72.1 million (an increase of 49% per Bbl) and a $26.1 million increase in sales volume (4 MBbls/d, or 25%).

Midstream and other revenue. Midstream and other revenue increased $6.2 million, or 18%, in the nine months ended September 30, 2022, compared to the nine months ended September 30, 2021, driven primarily by higher midstream revenue related to the 2021 Acquisitions.

Expenses

The following table summarizes our expenses for the periods indicated and includes a presentation on a per Boe basis, as we use this information to evaluate our performance relative to our peers and to identify and measure trends we believe may require additional analysis:

	Nine Months Ended September 30,
	2022		2021		$ Change		% Change
Expenses (in thousands):
Operating expense	$	758,241	$	433,275	$	324,966	75	%
Depreciation, depletion and amortization	375,600		233,122		142,478		61	%
General and administrative expense	59,489		33,775		25,714		76	%
Other operating costs	(1,266)		(8,585)		7,319		NM*
Total expenses	$	1,192,064	$	691,587	$	500,477	72	%
Selected expenses per Boe:
Operating expense, excluding production and other taxes	$	15.29	$	14.02	$	1.27	9	%
Production and other taxes	4.88		3.19		1.69		53	%
Depreciation, depletion and amortization	9.99		9.26		0.73		8	%

* NM = Not meaningful.

Operating expense. Operating expense increased $325.0 million, or 75%, in the nine months ended September 30, 2022, compared to the nine months ended September 30, 2021, driven primarily by the following factors:

(i)Lease and asset operating expense increased $177.1 million, or 88%, in the nine months ended September 30, 2022, compared to the nine months ended September 30, 2021. Additionally, lease and asset operating expense per Boe increased $2.08 per Boe from $7.96 per Boe to $10.04 per Boe. This $177.1 million increase was driven primarily by higher production during the nine months ended September 30, 2022, due in part to the 2021 Acquisitions and Uinta Transaction, which contributed $117.5 million and $17.1 million to the increase, respectively, general inflationary costs across our assets and 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 prices increase, higher contractually commodity-linked operating costs are offset by higher realizations.

(ii)Gathering, transportation and marketing expense decreased $4.8 million, or 4%, in the nine months ended September 30, 2022, compared to the nine months ended September 30, 2021. Additionally, gathering, transportation and marketing expense per Boe decreased $1.91 per Boe from $5.40 per Boe to $3.49 per Boe. This decrease was driven primarily by lower sulfur processing and transportation expenses.

(iii)Production and other taxes increased $103.2 million, or 129%, in the nine months ended September 30, 2022, compared to the nine months ended September 30, 2021 and increased $1.69 per Boe, an increase of 53%, to $4.88 per Boe. This increase was driven primarily by higher oil and natural gas revenues, which increased the tax base upon which production and other taxes are calculated.

(iv)Workover expense increased $48.3 million, or 617%, in the nine months ended September 30, 2022, compared to the nine months ended September 30, 2021. Additionally, workover expense per Boe increased $1.18 per Boe from $0.31 per Boe to $1.49 per Boe. This increase was driven primarily by (i) higher well workover activities that meet our internal return thresholds due to the higher commodity price environment, (ii) general inflationary costs across our assets and (iii) additional costs from our 2021 Acquisitions and Uinta Transaction, which contributed $28.9 million and $7.1 million to the increase, respectively. The 2021 Acquisitions increase includes additional costs related to a standard turnaround at our natural gas processing plant in Wyoming.

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(v)Midstream operating expense increased $1.1 million, or 13%, in the nine months ended September 30, 2022, compared to the nine months ended September 30, 2021.

Depreciation, depletion and amortization. In the nine months ended September 30, 2022, depreciation, depletion and amortization increased $142.5 million, or 61%, compared to the nine months ended September 30, 2021, driven primarily by $82.0 million and $76.6 million of additional depreciation, depletion and amortization due to our 2021 Acquisitions and Uinta Transaction, respectively, partially offset by a lower depletion rate on increased reserves of our other assets.

General and administrative expense. General and administrative expense ("G&A") increased $25.7 million, or 76%, for the nine months ended September 30, 2022, compared to the nine months ended September 30, 2021, primarily driven by (i) an increase in equity-based compensation expense of $11.7 million due to awards that were granted as part of the Merger Transactions offset by the changes in the fair value of the Company's liability-classified profits interest awards and (ii) $10.4 million related to 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, offset by $3.8 million in lower transaction and nonrecurring related expenses. While only the portion borne by us impacts our consolidated statements of operations, we include the full Manager Compensation 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”).

	Nine Months Ended September 30,
	2022		2021		$ Change		% Change
General and administrative expense (in thousands):
Recurring general and administrative expense	$	26,232	$	8,445	$	17,787	211	%
Transaction and nonrecurring expenses	6,951		10,703		(3,752)		(35)	%
Equity-based compensation	26,306		14,627		11,679		80	%
Total general and administrative expense	$	59,489	$	33,775	$	25,714	76	%
General and administrative expense per Boe:
Recurring general and administrative expense	$	0.70	$	0.34	$	0.36	106	%
Transaction and nonrecurring expenses	0.18		0.43		(0.25)		(58)	%
Equity-based compensation	0.70		0.58		0.12		21	%

Other operating costs. Other operating costs include exploration expense and gain on sale of assets. Other operating costs changed by $7.3 million, compared to the nine months ended September 30, 2021, primarily driven by a $4.3 million lower gain on sale of assets recognized during the nine months ended September 30, 2022 and $3.0 million in higher exploration expenses.

Interest expense

In the nine months ended September 30, 2022, we incurred interest expense of $68.5 million, as compared to $37.8 million in the nine months ended September 30, 2021, an 81% increase. This increase was driven primarily by higher interest rates associated with the issuance of the Senior Notes (as defined below) and an increase in our weighted average debt outstanding during the period.

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Gain (loss) on derivatives

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

	Nine Months Ended September 30,
	2022		2021		$ Change		% Change
Gain (loss) on derivatives (in thousands):
Gain (loss) on commodity derivatives	$	(645,565)	$	(885,006)	$	239,441	(27)	%
Gain (loss) on interest rate derivatives	—		(26)		26		(100)	%
Gain (loss) on derivatives	$	(645,565)	$	(885,032)	$	239,467	(27)	%

Our loss on commodity derivatives during the nine months ended September 30, 2022 decreased $239.4 million, or 27%, compared to the nine months ended September 30, 2021 primarily due to changes in commodity prices relative to our strike price. In addition, in June 2021, we incurred additional losses on derivatives from the settlement of certain derivative oil contracts for $198.7 million. The derivative losses that were realized were offset by the higher revenue prices that we received during the nine months ended September 30, 2022.

Income from equity affiliates

Our income from equity method investments was $4.1 million for the nine months ended September 30, 2022 primarily due to a gain on sale of substantially all of the oil and gas assets held by Exaro.

Income tax benefit (expense)

For the nine months ended September 30, 2021, we were organized as a limited liability company and treated as a flow-through entity for U.S. federal income tax purposes. As a result, the tax provision for the nine months ended September 30, 2021 was minimal. Subsequent to the Merger Transactions we are a corporation that is subject to U.S. federal and state and income taxes on its allocable share of any taxable income from OpCo. For the nine months ended September 30, 2022 we recognized income tax expense of $34.5 million for an effective tax rate of 7.4%. 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:

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	Nine Months Ended September 30,
	2022		2021		$ Change		% Change
(in thousands)
Net income (loss)	$	431,240	$	(601,172)	$	1,032,412	(172)	%
Adjustments to reconcile to Adjusted EBITDAX:
Interest expense	68,518		37,810
Realized (gain) loss on interest rate derivatives	—		7,373
Income tax expense (benefit)	34,528		407
Depreciation, depletion and amortization	375,600		233,122
Exploration expense	3,848		833
Non-cash (gain) loss on derivatives	(8,812)		493,698
Non-cash equity-based compensation expense	26,306		14,054
(Gain) loss on sale of assets	(5,114)		(9,418)
Other (income) expense	4,472		55
Certain redeemable noncontrolling interest distributions made by OpCo related to Manager Compensation	(29,599)		—
Transaction and nonrecurring expenses (1)	25,968		12,438
Early settlement of derivative contracts (2)	—		198,688
Adjusted EBITDAX (non-GAAP)	$	926,955	$	387,888	$	539,067	139	%
Adjustments to reconcile to Levered Free Cash Flow:
Interest expense, excluding non-cash deferred financing cost amortization	(62,087)		(28,460)
Realized (gain) loss on interest rate derivatives	—		(7,373)
Current income tax benefit (expense)	(7,099)		(407)
Tax-related redeemable noncontrolling interest distributions made by OpCo	(17,970)		—
Development of oil and natural gas properties	(468,796)		(107,998)
Levered Free Cash Flow (non-GAAP)	$	371,003	$	243,650	$	127,353	52	%

(1)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 Merger Transactions, (ii) severance costs subsequent to the Merger Transactions, (iii) merger integration costs and (iv) acquisition and debt transaction related costs. Transaction and nonrecurring expenses of $12.4 million for the nine months ended September 30, 2021 were primarily related to legal, consulting and other fees incurred for (i) the redemption by certain of our consolidated subsidiaries of the noncontrolling equity interests held in such subsidiaries by a certain third-party investor in exchange for its proportionate share of the underlying oil and natural gas interests held directly or indirectly by such subsidiaries, (ii) the redemption by certain of our consolidated subsidiaries of the noncontrolling equity interests held in such subsidiaries by certain third-party investors in exchange for our membership interests in April 2021 and (iii) the Merger Transactions.

(2)Represents the settlement in June 2021 of certain outstanding derivative oil commodity contracts for open positions associated with calendar years 2022 and 2023. Subsequent to the settlement, we entered into commodity derivative contracts at prevailing market prices.

Adjusted EBITDAX increased by $539.1 million, or 139%, in the nine months ended September 30, 2022, compared to the nine months ended September 30, 2021, primarily driven by higher revenue associated with our oil, natural gas and NGL production as a result of increased (i) realized prices and (ii) sales volume driven by our 2021 Acquisitions, our Uinta Transaction and new operated Eagle Ford and Uinta well completions in 2022. This increase was partially offset by a corresponding increase in operating costs due to higher production volumes and commodity prices, as well as higher realized losses on our commodity derivatives.

Levered Free Cash Flow increased by $127.4 million, or 52%, in the nine months ended September 30, 2022 compared to the nine months ended September 30, 2021, primarily driven by our increased Adjusted EBITDAX offset by $360.8 million of increased capital expenditures related to our reinvestment activities.

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Liquidity and capital resources

Our primary sources of liquidity are cash flow from operations and borrowings under a senior secured reserve-based revolving credit agreement (as amended, restated, amended and restated or otherwise modified to date, the “Revolving Credit Facility”) with Wells Fargo Bank, N.A., as administrative agent for the lenders and letter of credit issuer, and the lenders from time to time party thereto. Our primary use of capital is 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 plan 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 effort is an active economic hedge strategy to mitigate near-term price volatility while maintaining long-term exposure to underlying commodity prices. Our commodity derivative program focuses on entering into forward commodity contracts when investment decisions regarding reinvestment in existing assets or new acquisitions are finalized, targeting economic hedges for a portion of expected production as well as adding incremental derivatives to our production base over time. Our active derivative program allows us to preserve capital and protect margins and corporate returns through commodity cycles.

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

	September 30, 2022		December 31, 2021
	(in thousands)
Cash and cash equivalents	$	22,478	$	128,578
Long-term debt	1,372,334		1,030,406

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,
	2022		2021
	(in thousands)
Net cash provided by operating activities	$	797,354	$	148,632
Net cash used in investing activities	(1,060,934)		(126,776)
Net cash provided by financing activities	158,117		4,939

Net cash provided by operating activities. Net cash provided by operating activities for the nine months ended September 30, 2022 increased by $648.7 million, or 436%, compared to the nine months ended September 30, 2021 primarily due to higher EBITDAX and the restructuring of certain derivative contracts in 2021, partially offset by the 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, 2022 increased by $934.2 million, or 737%, compared to the nine months ended September 30, 2021, primarily due to $562.1 million of additional acquisitions of oil and natural gas properties in 2022, driven by the Uinta Transaction, and an additional $356.7 million of cash development capital expenditures as we have resumed reinvestment activity in light of higher commodity prices.

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Net cash provided by financing activities. Net cash provided by financing activities for the nine months ended September 30, 2022 was $158.1 million, as compared to $4.9 million in the nine months ended September 30, 2021. This increase was primarily due to net cash inflows from our debt transactions, including the issuance of our 7.250% senior notes due 2026 (the "New Notes") in February 2022 and additional borrowings from our Revolving Credit Facility to fund our Uinta Transaction. These net cash inflows in 2022 were partially offset by $99.5 million in distributions to redeemable noncontrolling interests and $19.3 million in dividends to holders of our Class A Common Stock.

Debt agreements

Senior Notes

On May 6, 2021, Crescent Energy Finance LLC ("Crescent Finance") issued $500.0 million aggregate principal amount of senior notes due 2026 at par (the "Original Notes"). In February 2022, Crescent Finance issued an additional $200.0 million aggregate principal amount of our senior notes due 2026 at 101% of par (the "New Notes" and, together with the Original Notes, the "Senior Notes"). Both issuances of the Senior Notes are treated as a single series and vote together as a single class, and have identical terms and conditions, other than the issue date, the issue price and the first interest payment. The Senior Notes bear interest at an annual rate of 7.250%, which is payable on May 1 and November 1 of each year and mature on May 1, 2026.

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

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

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 Senior Notes, Crescent Finance entered into the Revolving Credit Facility. The Revolving Credit Facility matures on September 23, 2027. At September 30, 2022, we had $685.0 million of outstanding borrowings under the Revolving Credit Facility and $12.2 million in outstanding letters of credit.

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, 2022 was 5.39%.

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)

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the issuance of certain permitted junior lien debt and other permitted additional debt, (b) the sale or other disposition of borrowing base properties if the aggregate net present value, discounted at 9% per annum (“PV-9”) of such properties sold or disposed of is in excess of 5.0% of the borrowing base then in effect and (c) early termination or set-off of swap agreements (x) the administrative agent relied on in determining the borrowing base or (y) if the value of such swap agreements so terminated is in excess of 5.0% of the borrowing base then in effect.

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

The Revolving Credit Facility contains certain covenants that restrict the payment of cash dividends, certain borrowings, sales of assets, loans to others, investments, merger activity, commodity swap agreements, liens and other transactions without the adherence to certain financial covenants or the prior consent of our lenders. We are subject to (i) maximum leverage ratio and (ii) current ratio financial covenants calculated as of the last day of each fiscal quarter. The Revolving Credit Facility also contains representations, warranties, indemnifications and affirmative and negative covenants, including events of default relating to nonpayment of principal, interest or fees, inaccuracy of representations or warranties in any material respect when made or when deemed made, violation of covenants, bankruptcy and insolvency events, certain unsatisfied judgments and a change of control. If an event of default occurs and we are unable to cure such default, the lenders will be able to accelerate maturity and exercise other rights and remedies. We expect to remain in compliance with these covenants for the foreseeable future.

Prior Credit Agreements

Certain of our subsidiaries had revolving credit facilities with syndicates of lenders with original expiration dates between 2022 and 2024 (the “Prior Credit Agreements”). The amounts we were able to borrow under each of the Prior Credit Agreements was limited by a borrowing base, which was based on our oil and natural gas properties, proved reserves and total indebtedness, as well as other factors, and was consistent with customary lending criteria. On May 6, 2021, we terminated the Prior Credit Agreements with the proceeds from the issuance of the Senior Notes, the redemption of certain noncontrolling equity interests in exchange for a third-party investor’s proportionate share of underlying oil and natural gas interests held by its consolidated subsidiaries and borrowings under our Revolving Credit Facility.

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 2022 capital program 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:

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	Nine Months Ended September 30,
	2022		2021
	(in thousands)
Total development of oil and natural gas properties	$	468,796	$	107,998
Change in accruals or other non-cash adjustments	(28,421)		(24,301)
Cash used in development of oil and natural gas properties	440,375		83,697
Cash used in acquisition of oil and natural gas properties	627,539		65,391
Non-cash acquisition of oil and natural gas properties	—		10,537
Total expenditures on acquisition and development of oil and natural gas properties	$	1,067,914	$	159,625

Our development of oil and natural gas properties was higher during the nine months ended September 30, 2022, compared to the nine months ended September 30, 2021. Due to the low commodity price environment experienced throughout 2020 resulting from the COVID-19 pandemic and the actions from OPEC, we significantly reduced our development capital expenditures starting in the second quarter of 2020 but resumed development activities in the second half of 2021 as commodity prices recovered. During the nine months ended September 30, 2022, commodity prices remained at or above levels prior to the COVID-19 pandemic. Our budget for 2022 reflects the current price environment. We used cash of $627.5 million in 2022 for the acquisition of oil and natural gas properties, primarily related to our Uinta Transaction, as compared to $65.4 million in 2021, primarily related to our DJ Basin Acquisition (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, 2022, 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 indenture governing the Senior Notes.

We paid cash dividends of $0.46 per share of our Class A Common Stock to shareholders during the nine months ended September 30, 2022.

On November 9, 2022, the Board of Directors approved a quarterly cash dividend of $0.17 per share, or $0.68 per share on an annualized basis, to be paid to shareholders of our Class A Common Stock with respect to the third quarter of 2022. The quarterly dividend is payable on December 7, 2022 to shareholders of record as of the close of business on November 23, 2022. OpCo unitholders will also receive a distribution based on their pro rata ownership of OpCo Units.

The payment of quarterly cash dividends is subject to management’s evaluation of our financial condition, results of operations and cash flows in connection with such payments and approval by our Board of Directors. In light of current economic conditions, management will evaluate any future 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, 2021 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, 2022.

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:

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

We define Levered Free Cash Flow as Adjusted EBITDAX less interest expense, excluding non-cash deferred financing cost amortization, realized gain (loss) on interest rate derivatives, current income tax benefit (expense), tax-related redeemable noncontrolling interest distributions made by OpCo and development of oil and natural gas properties. Levered Free Cash Flow does not take into account amounts incurred on acquisitions. 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.

Item 3. Quantitative and Qualitative Disclosures About Market Risk

We are exposed to market risk, including the effects of adverse changes in commodity prices and interest rates as described below. The primary objective of the following information is to provide quantitative and qualitative information about our potential exposure to market risks. The term “market risk” refers to the risk of loss arising from adverse changes in commodity prices and interest rates. The disclosures are not meant to be precise indicators of expected future losses but rather indicators of reasonably possible losses.

Commodity price risk

Our major market risk exposure is in the pricing that we receive for our oil, natural gas and NGLs production.

Pricing for oil, natural gas and NGLs has been volatile and unpredictable for several years, and we expect this volatility to continue in the future. The prices we receive for our production depend on many factors outside of our control, such as the strength of the global economy and global supply and demand for the commodities we produce.

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To reduce the impact of fluctuations in oil, natural gas and NGLs prices on our cash flows, we regularly enter into commodity derivative contracts with respect to certain of our oil, natural gas and NGL production through various transactions that limit the risks of fluctuations of future prices. A key tenet of our focused risk management effort is an active economic hedge strategy to mitigate near-term price volatility while maintaining long-term exposure to underlying commodity prices. Our hedging program allows us to preserve capital, protect margins and corporate returns through commodity cycles and return capital to investors. Future transactions may include price swaps whereby we will receive a fixed price for our production and pay a variable market price to the contract counterparty. Additionally, we may enter into collars, whereby we receive the excess, if any, of the fixed

floor over the floating rate or pay the excess, if any, of the floating rate over the fixed ceiling. These economic hedging activities are intended to limit our near-term exposure to product price volatility and to maintain stable cash flows, a strong balance sheet and attractive corporate returns.

As of September 30, 2022, our derivative portfolio had an aggregate notional value of approximately $1.7 billion, and the fair market value of our commodity derivative contracts was a net liability of $0.5 billion. 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, 2022, 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 $203.0 million. If prices decreased by 10%, our derivative position would change by approximately $202.7 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 its 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, 2022, we had $685.0 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 approximately $5.1 million increase or decrease in interest expense for the nine months ended September 30, 2022.

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

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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, 2022. 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, 2022 that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.

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Part II – Other Information

Item 1. Legal Proceedings

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

Item 1A. Risk Factors

There are a number of risks that we believe are applicable to our business and the oil and gas industry in which we operate. These risks are described elsewhere in this report or our other filings with the SEC, including the section entitled “Item 1A. Risk Factors” beginning on page 37 in our Annual Report. If any of the risks and uncertainties described within our Annual Report or elsewhere in this Quarterly Report actually occur, our business, financial condition or results of operations could be materially adversely affected.

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.

The U.S. inflation rate has been steadily increasing since 2021 and into 2022. These inflationary pressures have resulted in and may result in additional increases to the costs of our oilfield goods, services and personnel, which in turn cause our capital expenditures and operating costs to rise. Sustained levels of high inflation have likewise caused the U.S. Federal Reserve and other central banks to increase interest rates multiple times in 2022 and the U.S. Federal Reserve has indicated its intention to continue to raise benchmark interest rates throughout the remainder of 2022 and into 2023 in an effort to curb inflationary pressure on the costs of goods and services across the U.S., which could have the effects of raising the cost of capital and depressing economic growth, either of which—or the combination thereof—could hurt the financial and operating results of our business. To the extent elevated inflation remains, we may experience further cost increases for our operations, including oilfield services, labor costs and equipment if our drilling activity increases.

Higher oil and natural gas prices may cause the costs of materials and services to continue to rise. We cannot predict any future trends in the rate of inflation and a significant increase in inflation, to the extent we are unable to recover higher costs through higher oil and natural gas prices and revenues, would negatively impact our business, financial condition and results of operations.

The Inflation Reduction Act of 2022 could accelerate the transition to a low-carbon economy and will impose new costs on our operations.

On August 16, 2022, President Biden signed the IRA 2022 into law pursuant to the budget reconciliation process. 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 the first ever federal fee on the emission of GHGs through a methane emissions charge. The IRA 2022 amends the federal Clean Air Act to impose a fee on the emission of methane from sources required to report their GHG emissions to the U.S. Environmental Protection Agency (“EPA”), including those sources in the onshore petroleum and natural gas production and gathering and boosting source categories. The methane emissions charge will start in calendar year 2024 at $900 per ton of methane, increase to $1,200 in 2025, and be set at $1,500 for 2026 and each year thereafter. Calculation of 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.

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

None.

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Item 3. Defaults Upon Senior Securities

None.

Item 4. Mine Safety Disclosures

Not applicable.

Item 5. Other Information

Not applicable.

Item 6. Exhibits

Exhibit No.	Description
2.1	Transaction Agreement, dated as of June 7, 2021, by and among Contango Oil & Gas Company, Independence Energy LLC, IE PubCo Inc., IE OpCo LLC, IE L Merger Sub LLC and IE C Merger Sub Inc. (incorporated by reference to Exhibit 2.1 to the Company's proxy statement/prospectus, filed with the Securities and Exchange Commission on October 8, 2021).
2.2	Membership Interest Purchase Agreement, dated as of February 15, 2022, by and between Verdun Oil Company II LLC and Javelin VentureCo, LLC, and Crescent Energy OpCo LLC, as guarantor (incorporated by reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K filed with the Securities and Exchange Commission on February 16, 2022).
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 7, 2022, among Crescent Energy Finance LLC, the guarantors named therein, and U.S. Bank Trust Company, National Association, as trustee
10.1	Fourth Amendment to Credit Agreement, dated as of September 23, 2022, among Crescent Energy Finance LLC, certain subsidiaries of Crescent Energy Company, as guarantors, Wells Fargo Bank, National Association, as administrative agent, and the other lenders 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 September 29, 2022).
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

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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

* 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.

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Signatures

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

	CRESCENT ENERGY COMPANY
	(Registrant)
November 9, 2022	/s/ David Rockecharlie
	David Rockecharlie
	Chief Executive Officer
	(Principal Executive Officer)
November 9, 2022	/s/ Brandi Kendall
	Brandi Kendall
	Chief Financial Officer
	(Principal Financial Officer)

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