Crescent Energy Co - Quarter Report: 2022 June (Form 10-Q)

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 June 30, 2022


☐			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 July 31, 2022, there were approximately 41,954,385 and 127,536,463 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			29
Item 3 . Quantitative and Qualitative Disclosures About Market Risk			48
Item 4. Controls and Procedures			49
Part II - Other Information
Item 1. Legal Proceedings			51
Item 1A. Risk Factors			51
Item 2. Unregistered Sales of Equity Securities and Use of Proceeds			51
Item 3. Defaults Upon Senior Securities			51
Item 4. Mine Safety Disclosures			51
Item 5. Other Information			51
Item 6. Exhibits			51
Signatures			53

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 the sulfur content is approximately 0.3%.

Cautionary Statement Regarding Forward-Looking Statements

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

•commodity price volatility;

•our business strategy;

•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

•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.

Part I – Financial Information

Item 1. Financial Statements


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

	June 30, 2022		December 31, 2021
ASSETS
Current assets:
Cash and cash equivalents	$	54,580	$	128,578
Accounts receivable, net	594,478		321,855
Accounts receivable – affiliates	1,714		20,341
Prepaid and other current assets	22,274		8,844
Total current assets	673,046		479,618
Property, plant and equipment:
Oil and natural gas properties at cost, successful efforts method
Proved	7,091,516		6,043,602
Unproved	367,643		308,721
Oil and natural gas properties at cost, successful efforts method	7,459,159		6,352,323
Field and other property and equipment, at cost	165,034		144,318
Total property, plant and equipment	7,624,193		6,496,641
Less: accumulated depreciation, depletion, amortization and impairment	(2,161,229)		(1,941,528)
Property, plant and equipment, net	5,462,964		4,555,113
Goodwill	76,826		76,564
Derivative assets – noncurrent	—		579
Investment in equity affiliates	15,624		15,415
Other assets	45,212		30,173
TOTAL ASSETS	$	6,273,672	$	5,157,462

















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


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

	June 30, 2022		December 31, 2021
LIABILITIES, REDEEMABLE NONCONTROLLING INTERESTS AND EQUITY
Current liabilities:
Accounts payable and accrued liabilities	$	597,266	$	337,881
Accounts payable – affiliates	38,486		8,675
Derivative liabilities – current	640,016		253,525
Financing lease obligations – current	2,074		1,606
Other current liabilities	12,737		14,438
Total current liabilities	1,290,579		616,125
Long-term debt	1,515,702		1,030,406
Derivative liabilities – noncurrent	259,033		133,471
Asset retirement obligations	294,099		258,102
Deferred tax liability	96,713		82,537
Financing lease obligations – noncurrent	4,211		3,512
Other liabilities	24,616		13,652
Total liabilities	3,484,953		2,137,805
Commitments and contingencies (Note 9)
Redeemable noncontrolling interests	2,167,413		2,325,013
Equity:
Class A common stock, $0.0001 par value; 1,000,000,000 shares authorized, 43,105,376 shares issued, and 41,954,385 shares outstanding as of June 30, 2022 and December 31, 2021	4		4
Class B common stock, $0.0001 par value; 500,000,000 shares authorized and 127,536,463 shares issued and outstanding as of June 30, 2022 and December 31, 2021	13		13
Preferred stock, $0.0001 par value; 500,000,000 shares authorized and 1,000 Series I preferred shares issued and outstanding as of June 30, 2022 and December 31, 2021	—		—
Treasury stock, at cost; 1,150,991 shares of Class A common stock as of June 30, 2022 and December 31, 2021	(18,448)		(18,448)
Additional paid-in capital	683,541		720,016
Accumulated deficit	(49,853)		(19,376)
Noncontrolling interests	6,049		12,435
Total equity	621,306		694,644
TOTAL LIABILITIES, REDEEMABLE NONCONTROLLING INTERESTS AND EQUITY	$	6,273,672	$	5,157,462

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

CRESCENT ENERGY COMPANY

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS

(Unaudited)

(in thousands, except per share amounts)


	Three Months Ended June 30,				Six Months Ended June 30,
	2022		2021		2022		2021
Revenues:
Oil	$	602,567	$	216,820	$	975,076	$	405,743
Natural gas	207,177		62,449		350,488		143,492
Natural gas liquids	83,864		38,192		155,043		74,291
Midstream and other	14,826		12,668		26,737		24,464
Total revenues	908,434		330,129		1,507,344		647,990
Expenses:
Lease operating expense	106,375		60,970		201,198		117,628
Workover expense	25,017		2,630		34,976		4,891
Asset operating expense	17,243		6,369		33,862		13,496
Gathering, transportation and marketing	38,238		48,250		86,514		91,422
Production and other taxes	65,496		25,873		111,980		52,186
Depreciation, depletion and amortization	131,573		76,228		230,592		160,097
Exploration expense	1,848		23		1,939		79
Midstream operating expense	3,344		2,598		6,422		6,330
General and administrative expense	19,656		16,122		42,178		22,751
Gain on sale of assets	(197)		(9,417)		(4,987)		(9,417)
Total expenses	408,593		229,646		744,674		459,463
Income (loss) from operations	499,841		100,483		762,670		188,527
Other income (expense):
Gain (loss) on derivatives	(177,209)		(355,996)		(850,695)		(602,810)
Interest expense	(24,937)		(17,443)		(41,461)		(24,826)
Other income (expense)	(303)		96		(1,802)		(6)
Income from equity affiliates	2,304		—		3,252		—
Total other income (expense)	(200,145)		(373,343)		(890,706)		(627,642)
Income (loss) before taxes	299,696		(272,860)		(128,036)		(439,115)
Income tax benefit (expense)	(17,798)		(1)		3,927		(14)
Net income (loss)	281,898		(272,861)		(124,109)		(439,129)
Less: net (income) loss attributable to Predecessor	—		269,608		—		425,237
Less: net (income) loss attributable to noncontrolling interests	(713)		3,253		(1,183)		13,892
Less: net (income) loss attributable to redeemable noncontrolling interests	(226,662)		—		94,815		—
Net income (loss) attributable to Crescent Energy	$	54,523	$	—	$	(30,477)	$	—
Net income (loss) per share:
Class A common stock – basic	$	1.30			$	(0.73)
Class A common stock – diluted	$	1.30			$	(0.73)
Class B common stock – basic and diluted	$	—			$	—
Weighted average shares outstanding:
Class A common stock – basic	41,954				41,954
Class A common stock - diluted	41,956				41,954
Class B common stock – basic and diluted	127,536				127,536

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


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

	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		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













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


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

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

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

CRESCENT ENERGY COMPANY

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)

(in thousands)


	Six Months Ended June 30,
		2022		2021
Cash flows from operating activities:
Net income (loss)		$	(124,109)	$	(439,129)
Adjustments to reconcile net income (loss) to net cash provided by operating activities
Depreciation, depletion and amortization		230,592		160,097
Deferred income taxes (benefit)		(11,901)		—
(Gain) loss on derivatives		850,695		602,810
Net cash (paid) received on settlement of derivatives		(442,665)		(296,039)
Non-cash equity-based compensation expense		20,470		9,736
Amortization of debt issuance costs and discount		3,926		5,409
Gain on sale of oil and natural gas properties		(4,987)		(9,417)
Restructuring of acquired derivative contracts		(51,994)		—
Settlement of acquired derivative contracts		(23,101)		—
Other		(7,636)		2,541
Changes in operating assets and liabilities:
Accounts receivable		(265,459)		(54,375)
Accounts receivable – affiliates		18,627		—
Prepaid and other current assets		(13,471)		24,113
Accounts payable and accrued liabilities		191,134		39,587
Accounts payable – affiliates		29,811		(9,169)
Other		(1,478)		(486)
Net cash provided by operating activities		398,454		35,678
Cash flows from investing activities:
Development of oil and natural gas properties		(240,356)		(48,797)
Acquisitions of oil and natural gas properties		(627,390)		(60,828)
Proceeds from the sale of oil and natural gas properties		800		22,053
Purchases of restricted investment securities – HTM		(5,390)		(4,956)
Maturities of restricted investment securities – HTM		3,600		6,330
Other		4,700		(472)
Net cash used in investing activities		(864,036)		(86,670)
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		918,000		349,062
Revolving Credit Facility repayments		(632,000)		—
Payment of debt issuance costs		(14,873)		(10,194)
Prior Credit Agreement borrowings		—		53,900
Prior Credit Agreement repayments		—		(804,975)
Redeemable noncontrolling interest contributions		5,985		—
Member distributions and other		(745)		(23,392)
Dividend to Class A common stock		(12,168)		—
Distributions to redeemable noncontrolling interests related to Class A common stock dividend		(37,004)		—
Distributions to redeemable noncontrolling interests related to Manager Compensation		(12,734)		—
Distributions to redeemable noncontrolling interests related to income taxes		(11,685)		—
Repurchase of noncontrolling interest		(4,060)		—
Noncontrolling interest distributions		(3,408)		(278)
Noncontrolling interest contributions		55		35,461
Net cash provided by financing activities		394,613		90,209
Net change in cash, cash equivalents and restricted cash		(70,969)		39,217
Cash, cash equivalents and restricted cash, beginning of period		135,117		41,420
Cash, cash equivalents and restricted cash, end of period		$	64,148	$	80,637

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

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 owns and continues to own 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.

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 is owned approximately 25% by Crescent and approximately 75% 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 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 June 30,
	2022		2021
	(in thousands)
Cash and cash equivalents	$	54,580	$	74,511
Restricted cash – noncurrent	9,568		6,126
Total cash, cash equivalents and restricted cash	$	64,148	$	80,637

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.

From December 31, 2021 through June 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

(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 interest is offset by a $195.0 million decrease in Additional paid-in capital ("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 six months ended June 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 six months ended June 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 six months ended June 30, 2022 we recognized income tax expense of $17.8 million and an income tax benefit of $3.9 million for an effective tax rate of 5.9% and 3.1%. 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 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 a small annual limitation. These annual limitations may result in the expiration of NOLs and credits prior to utilization. As of June 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 June 30, 2022, we decreased APIC by $46.6 million primarily as the result of a tax effect related to the reversal of the $195.0 million redemption adjustment to redeemable noncontrolling interest. During the six months ended June 30, 2022 we decreased APIC by $26.4 million primarily related to a change in the deferred tax liability related to our estimated basis in Crescent's ownership of OpCo. As of June 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 six months ended June 30, 2022 and 2021:


	Six Months Ended June 30,
		2022		2021
	(in thousands)
Supplemental cash flow disclosures:
Interest paid, net of amounts capitalized		$	32,470	$	10,494
Income tax (refunds) payments		7,744		14
Non-cash investing and financing activities:
Capital expenditures included in accounts payable and accrued liabilities		$	98,961	$	28,569

Equity consideration for acquisitions, net of cash acquired		—		7,164
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. ("EP") located in the State of Utah (the “Utah Assets”). 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 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 six months ended June 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 second half 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 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 three and six months ended June 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. Such interest is valued at approximately $3.8 million. 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. During the first quarter of 2022, we derecognized the assets and liabilities that were contributed to Chama from our condensed consolidated balance sheets. We recorded a $4.5 million gain related to the deconsolidation of these assets and liabilities and recorded an equity method investment for our interest in Chama. The carrying value of our equity method investment in Chama at June 30, 2022 is $3.9 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 a $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 June 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.

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 June 30, 2022:


Production Period	Volumes	Weighted Average Fixed Price			Fair Value
Crude oil swaps (Bbls):	(in thousands)				(in thousands)
WTI
2022	6,881	$64.35			$	(234,085)
2023	9,710	$60.00			(248,904)
2024	5,721	$63.82			(80,403)
Brent
2022	252	$56.36			(11,398)
2023	527	$52.52			(19,454)
2024	276	$68.65			(4,029)
Crude oil collars – WTI (Bbls):
2023	1,155	$48.68	-	$57.87	(32,709)
Natural gas swaps (MMBtu):
2022	40,814	$2.77			(116,709)
2023	62,248	$2.73			(119,329)
2024	9,604	$4.14			(2,288)
NGL swaps (Bbls):
2022	1,505	$32.64			(15,023)
2023	1,379	$40.80			3,351
Crude oil basis swaps (Bbls):
2022	2,857	$(0.13)			(5,154)
Natural gas basis swaps (MMBtu):
2022	12,654	$(0.17)			(2,610)
Calendar Month Average ("CMA") roll swaps (Bbls):
2022	740	$1.08			(1,557)
Natural gas collars (MMBtu):
2023	550	$2.63	-	$3.01	(1,145)
2024	18,300	$3.38	-	$4.56	(7,603)
Total					$	(899,049)

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 June 30, 2022 and December 31, 2021:


	Gross Fair Value		Effect of Counterparty Netting		Net Carrying Value
	(in thousands)
June 30, 2022
Assets:
Derivative assets – current	$	7,823	$	(7,823)	$	—
Derivative assets – noncurrent	8,736		(8,736)		—
Total assets	$	16,559	$	(16,559)	$	—
Liabilities:
Derivative liabilities – current	$	(647,839)	$	7,823	$	(640,016)
Derivative liabilities – noncurrent	(267,769)		8,736		(259,033)
Total liabilities	$	(915,608)	$	16,559	$	(899,049)

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 six months ended June 30, 2022 and 2021:


	Three Months Ended June 30,				Six Months Ended June 30,
	2022		2021		2022		2021
	(in thousands)
Derivatives not designated as hedging instruments:
Realized gain (loss) on oil positions	$	(146,765)	$	(43,901)	$	(246,856)	$	(65,986)
Realized gain (loss) on early settlement of certain oil positions	—		(198,688)		—		(198,688)
Realized gain (loss) on natural gas positions	(93,630)		(2,102)		(143,475)		(2,367)
Realized gain (loss) on NGL positions	(26,469)		(12,452)		(52,334)		(24,168)
Realized gain (loss) on interest hedges	—		(3,394)		—		(7,022)
Total realized gain (loss) on derivatives	(266,864)		(260,537)		(442,665)		(298,231)
Unrealized gain (loss) on commodity hedges	89,655		(99,165)		(408,030)		(311,926)
Unrealized gain (loss) on interest hedges	—		3,706		—		7,347
Total unrealized gain (loss) on derivatives	89,655		(95,459)		(408,030)		(304,579)
Gain (loss) on derivatives	$	(177,209)	$	(355,996)	$	(850,695)	$	(602,810)

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 June 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)
June 30, 2022
Financial assets:
Derivative assets	$	—	$	16,559	$	—	$	16,559
Financial liabilities:
Derivative liabilities	$	—	$	(915,608)	$	—	$	(915,608)

December 31, 2021
Financial assets:
Derivative assets	$	—	$	7,817	$	—	$	7,817
Financial liabilities:
Derivative liabilities	$	—	$	(394,234)	$	—	$	(394,234)

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 June 30, 2022 and December 31, 2021 was approximately $641.5 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 June 30, 2022 and December 31, 2021:


	June 30, 2022		December 31, 2021
	(in thousands)
Accounts payable and accrued liabilities:
Accounts payable	$	147,969	$	87,336
Accrued lease and asset operating expense	43,973		55,228

Accrued capital expenditures	93,759		60,647
Accrued general and administrative expense	13,487		12,193
Accrued transportation expense	30,913		20,639
Accrued revenue and royalties payable	181,405		75,827
Accrued interest expense	11,661		6,325
Accrued severance taxes	58,269		5,062
Other	15,830		14,624
Total accounts payable and accrued liabilities	$	597,266	$	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 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. In conjunction with the Uinta Transaction closing, we entered into an amendment to the credit agreement that (i) increased our elected commitment amount from $700.0 million to $1.3 billion, (ii) increased our borrowing base from $1.3 billion to $1.8 billion, and (iii) increased our maximum credit amount from $1.5 billion to $3.0 billion. The Revolving Credit Facility matures on May 6, 2025. At June 30, 2022, we had $829.0 million of borrowings and $17.8 million in letters of credit outstanding under the Revolving Credit Facility.

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

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

Interest

Borrowings under the Revolving Credit Facility bear interest at either (i) a U.S. dollar alternative base rate (based on the prime rate, the federal funds effective rate or an adjusted secured overnight financing rate (“SOFR”)), plus an applicable margin or (ii) SOFR, plus an applicable margin, at the election of the borrowers. The applicable margin varies based upon our borrowing base utilization then in effect. The fee payable for the unused revolving commitments 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 June 30, 2022 was 4.42%.

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 June 30, 2022, we had letters of credit outstanding of $17.8 million, which reduce the amount available to borrow under our Revolving Credit Facility.

Total Debt Outstanding

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


	Debt Outstanding		Letters of Credit Issued		Borrowing Base		Maturity
	(in thousands)
June 30, 2022
Revolving Credit Facility	$	829,000	$	17,771	$	1,800,000	5/6/2025
7.250% Senior Notes due 2026	700,000		—		—		5/1/2026
Less: Unamortized discount and issuance costs	(13,298)
Total long-term debt	$	1,515,702

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

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 six months ended June 30, 2022:


	Six Months Ended June 30, 2022
	(in thousands)
Balance at beginning of period	$	266,007
Acquisitions	37,203
Additions	99
Retirements	(6,320)
Sale	(8,390)
Change in estimate	1,968
Accretion expense	9,985
Balance at end of period	300,552
Less: current portion	(6,453)
Balance at end of period, noncurrent portion	$	294,099

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 June 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.

On March 30, 2022, the U.S. Environmental Protection Agency (“EPA”) announced a civil penalty of $0.7 million to EP related to regulatory infractions incurred by EP prior to the Uinta Transaction. Following the acquisition, we paid the penalty to the EPA on July 11, 2022.

NOTE 10 – Incentive Compensation Arrangements

Overview

We and certain of our subsidiaries have entered into incentive compensation award agreements to grant profits interests, restricted stock units ("RSUs"), performance stock units ("PSUs") and other incentive awards to our employees, our Manager, and non-employee directors. The following table summarizes compensation expense we recognized in connection with our incentive compensation awards for the periods indicated:


	Three Months Ended June 30,				Six Months Ended June 30,
	2022		2021		2022		2021
	(in thousands)
ASC 710 profits interest awards	$	500	$	—	$	500	$	—
ASC 718 liability-classified profits interest awards	4,993		4,835		12,213		8,172
ASC 718 equity-classified profits interest awards	—		1,564		—		1,564
ASC 718 equity-classified RSU awards	394		—		394		—
ASC 718 equity-classified PSU awards	3,968		—		7,863		—
Total expense (income)	$	9,855	$	6,399	$	20,970	$	9,736

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 six months ended June 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

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 generally 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.

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 $13.5 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 six months ended June 30, 2022, we recorded general and administrative expense of $3.3 million and $6.6 million, respectively, and made cash distributions of $10.0 million and $12.7 million, respectively, to our redeemable noncontrolling interests related to the Management Agreement. In addition, at June 30, 2022 we accrued $10.1 million for distributions to our redeemable noncontrolling interests in OpCo related to the Management Agreement which will be paid during the third 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 six months ended June 30, 2022, we recorded general and administrative expense of $4.0 million and $7.9 million, respectively, related to Incentive Compensation. See NOTE 10 – Incentive Compensation Arrangements for more information.

KKR Funds

From time to time, we may invest in upstream oil and gas assets alongside EIGF II and/or other KKR funds ("KKR Funds") pursuant to the terms of the Management Agreement. In these instances, certain of our consolidated subsidiaries enter into Master Service Agreements ("MSA") with entities owned by KKR Funds, pursuant to which our subsidiaries provide certain services to such KKR Funds, including the allocation of the production and sale of oil, natural gas and NGLs, collection and disbursement of revenues, operating expenses and general and administrative expenses in the respective oil and natural gas properties, and the payment of all capital costs associated with the ongoing operations of the oil and natural gas assets. Our subsidiaries settle balances due to or due from KKR Funds on a monthly basis. The administrative costs associated with these MSAs are allocated by us to KKR Funds based on (i) an actual basis for direct expenses we may incur on their behalf or (ii) an allocation of such charges between the various KKR Funds based on the estimated use of such services by each party. As of June 30, 2022 and December 31, 2021, we had a related party receivable of $1.7 million and $3.3 million, respectively, included within Accounts receivable – affiliates and a related party payable of $32.3 million and $7.0 million, respectively, included within Accounts payable – affiliates on our condensed consolidated balance sheets associated with KKR Funds transactions.

Other Transactions

During the six months ended June 30, 2022, we incurred $0.7 million in fees to KKR Capital Markets LLC, an affiliate of KKR Group, in connection with the New Notes. We recorded these fees as debt issuance costs within Long-term debt on the condensed consolidated balance sheets. During the three and six months ended June 30, 2022, we paid an additional $1.5 million in fees to KKR Capital Markets LLC 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 six months ended June 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 $3.3 million deposited in an escrow account to fund these wind down costs at June 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 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 June 30,				Six Months Ended June 30,
	2022		2021		2022		2021
	(in thousands, except share and per share amounts)
Numerator:
Net income (loss)	$	281,898	$	(272,861)	$	(124,109)	$	(439,129)
Less: net loss attributable to Predecessor	—		269,608		—		425,237
Less: net (income) loss attributable to noncontrolling interests	(713)		3,253		(1,183)		13,892
Less: net (income) loss attributable to redeemable noncontrolling interests	(226,662)		—		94,815		—
Net income (loss) attributable to Crescent Energy - basic	54,523		—		(30,477)		—
Add: Reallocation of net income attributable to redeemable noncontrolling interest for the dilutive effect of RSUs	2		—		—		—
Net income (loss) attributable to Crescent Energy - diluted	$	54,525	$	—	$	(30,477)	$	—
Denominator:
Weighted-average Class A common stock outstanding – basic	41,954,385				41,954,385
Add: dilutive effect of RSUs	2,081				—
Weighted-average Class A common stock outstanding – diluted	41,956,466				41,954,385
Weighted-average Class B common stock outstanding – basic and diluted	127,536,463				127,536,463
Net income (loss) per share:
Class A common stock – basic	$	1.30			$	(0.73)
Class A common stock – diluted	$	1.30			$	(0.73)
Class B common stock – basic and diluted	$	—			$	—

NOTE 13 – Subsequent Events

Dividend

On August 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 second quarter of 2022. The quarterly dividend is payable on September 6, 2022 to shareholders of record as of the close of business on August 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.

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 Report on Form 10-Q for the period ended March 31, 2022, as well as our unaudited condensed consolidated financial statements for the three and six months ended June 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 six months ended June 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.

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 the first six months of 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.

Finally, 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. In addition, 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, which could have the effects of raising the cost of capital and depressing economic growth, either of which—or the combination thereof—could hurt our business.

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. ("EP") located in the State of Utah (the “Utah Assets”). 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.

under our Revolving Credit Facility (as defined below). We accounted for the Central Basin Platform Acquisition as an asset acquisition.

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.

Divestitures

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 three and six months ended June 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. Such interest is valued at approximately $3.8 million. 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. During the first quarter of 2022, we derecognized the assets and liabilities that were contributed to Chama from our condensed consolidated balance sheets. We recorded a $4.5 million gain related to on the deconsolidation of these assets and liabilities and recorded an equity method investment for our interest in Chama. The carrying value of our equity method investment in Chama at June 30, 2022 is $3.9 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.

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 December 2021, we released our inaugural ESG report, which included key performance metrics according to Value Reporting Foundation’s SASB Standard for Oil & Gas – Exploration & Production and also established our key ESG priorities. We also established an ESG Advisory Council to advise management and our Board of Directors on ESG-related issues. We are working to reduce greenhouse gas (“GHG”) emissions by implementing aggressive 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.

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. Our program is approximately 95% allocated to D&C (80 to 85% to our operated assets primarily in the Eagle Ford and Uinta basins and 10 to 15% to non-operated activity) and approximately 5% to other capital expenditures. 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 revenue

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 June 30,				Six Months Ended June 30,
	2022		2021		2022		2021
Oil	68	%	68	%	66	%	65	%
Natural gas	23	%	20	%	24	%	23	%
NGLs	9	%	12	%	10	%	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 4% or less of our total revenues for the three and six months ended June 30, 2022 and 2021.

Production volumes sold

The following table presents historical sales volumes for our properties:


	Three Months Ended June 30,		Six Months Ended June 30,
	2022	2021	2022	2021
Oil (MBbls)	5,781	3,351	9,766	6,669
Natural gas (MMcf)	32,353	22,482	62,367	43,305
NGLs (MBbls)	1,785	1,492	3,612	2,937
Total (MBoe)	12,958	8,590	23,773	16,824
Daily average (MBoe/d)	142	94	131	93

Total sales volume increased 4,368 MBoe and 6,949 MBoe during the three and six months ended June 30, 2022, respectively, compared to the three and six months ended June 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 2,701 MBoe and 2,356 MBoe for the three months ended June 30, 2022, respectively, and 5,836 MBoe and 2,356 MBoe for the six months ended June 30, 2022, respectively. Sales volumes from our other assets decreased by 689 and 1,243 MBoe during the three and six months ended June 30, 2022, respectively, compared to the three and six months ended June 30, 2021, primarily as a result of the natural decline from our existing asset base.

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. Despite the impact of the COVID-19 virus on the global economy, commodity prices trended higher in the three and six months ended June 30, 2022, compared with the three and six months ended June 30, 2021, reflecting the ongoing recovery in the oil and gas industry in early 2022 due to increasing demand as more states and countries re-open and national and global economies continue to 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 and the continued effect from the COVID-19 pandemic, as well 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 June 30,				Six Months Ended June 30,
	2022		2021		2022		2021
Oil	66	%	81	%	70	%	82	%
Natural gas	67	%	80	%	71	%	84	%
NGLs	49	%	70	%	49	%	71	%

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


	Three Months Ended June 30,				Six Months Ended June 30,
	2022		2021		2022		2021
Oil (Bbl):
Average NYMEX	$	108.41	$	66.07	$	101.35	$	61.96
Realized price (excluding derivative settlements)	104.23		64.70		99.84		60.84
Realized price (including derivative settlements) (1)	78.84		51.60		74.57		50.95
Natural Gas (Mcf):
Average NYMEX	$	7.17	$	2.83	$	6.06	$	2.76
Realized price (excluding derivative settlements)	6.40		2.78		5.62		3.31
Realized price (including derivative settlements)	3.51		2.68		3.32		3.26
NGLs (Bbl):
Realized price (excluding derivative settlements)	$	46.98	$	25.60	$	42.92	$	25.30
Realized price (including derivative settlements)	32.15		17.25		28.44		17.07

(1) For the three and six months ended June 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.

Results of operations:

Three Months Ended June 30, 2022 Compared to Three Months Ended June 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 June 30,
	2022		2021		$ Change		% Change
Revenues (in thousands):
Oil	$	602,567	$	216,820	$	385,747	178	%
Natural gas	207,177		62,449		144,728		232	%
Natural gas liquids	83,864		38,192		45,672		120	%
Midstream and other	14,826		12,668		2,158		17	%
Total revenues	$	908,434	$	330,129	$	578,305	175	%
Average realized prices, before effects of derivative settlements:
Oil ($/Bbl)	$	104.23	$	64.70	$	39.53	61	%
Natural gas ($/Mcf)	6.40		2.78		3.62		130	%
NGLs ($/Bbl)	46.98		25.60		21.38		84	%
Total ($/Boe)	68.96		36.96		32.00		87	%
Net sales volumes:
Oil (MBbls)	5,781		3,351		2,430		73	%
Natural gas (MMcf)	32,353		22,482		9,871		44	%
NGLs (MBbls)	1,785		1,492		293		20	%
Total (MBoe)	12,958		8,590		4,368		51	%
Average daily net sales volumes:
Oil (MBbls/d)	64		37		27		73	%
Natural gas (MMcf/d)	356		247		109		44	%
NGLs (MBbls/d)	20		16		4		25	%
Total (MBoe/d)	142		94		48		51	%

Oil revenue. Oil revenue increased $385.7 million, or 178%, in the three months ended June 30, 2022, compared to the three months ended June 30, 2021. This was driven primarily by higher realized oil prices that resulted in an increase of $228.5 million (an increase of 61% per Bbl) and a $157.2 million increase in sales volume (27 MBbls/d or 73%). The increase in sales volumes is primarily related to our 2021 Acquisitions and our Uinta Transaction, which contributed an additional 923 MBbls and 1,593 MBbls, respectively, partially offset by the natural decline from our existing asset base of 86 MBbls.

Natural gas revenue. Natural gas revenue increased $144.7 million, or 232% in the three months ended June 30, 2022, compared to the three months ended June 30, 2021. This was driven primarily by higher natural gas prices that resulted in an increase of $117.1 million (an increase of 130% per Mcf) and a $27.4 million increase in sales volume (109 MMcf/d, or 44%). The increase in sales volumes were primarily related to our 2021 Acquisitions and our Uinta Transaction, which contributed an additional 8,283 MMcf and 4,570 MMcf, respectively, partially offset by the natural decline from our existing asset base of 2,982 MMcf.

NGL revenue. NGL revenue increased $45.7 million, or 120%, in the three months ended June 30, 2022, compared to the three months ended June 30, 2021. This was driven primarily by higher realized NGL prices that resulted in an increase of $38.2 million (an increase of 84% per Bbl) and a $7.5 million increase in sales volume (4 MBbls/d, or 25%).

Midstream and other revenue. Midstream and other revenue increased $2.2 million, or 17%, in the three months ended June 30, 2022, compared to the three months ended June 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 June 30,
	2022		2021		$ Change		% Change
Expenses (in thousands):
Operating expense	$	255,713	$	146,690	$	109,023	74	%
Depreciation, depletion and amortization	131,573		76,228		55,345		73	%
General and administrative expense	19,656		16,122		3,534		22	%
Other operating costs	1,651		(9,394)		11,045		NM*
Total expenses	$	408,593	$	229,646	$	178,947	78	%
Selected expenses per Boe:
Operating expense, excluding production and other taxes	$	14.68	$	14.06	$	0.62	4	%
Production and other taxes	5.05		3.01		2.04		68	%
Depreciation, depletion and amortization	10.15		8.87		1.28		14	%

* NM = Not meaningful.

Operating expense. Operating expense increased $109.0 million, or 74%, in the three months ended June 30, 2022, compared to the three months ended June 30, 2021, driven primarily by the following factors:

(i)Lease and asset operating expense increased $56.3 million, or 84%, in the three months ended June 30, 2022, compared to the three months ended June 30, 2021. Additionally, lease and asset operating expense per Boe increased $1.70 per Boe from $7.84 per Boe to $9.54 per Boe. This $56.3 million increase was driven primarily by higher production during the three months ended June 30, 2022, due in part to the 2021 Acquisitions and Uinta Transaction, which contributed $36.4 million and $8.5 million to the increase, respectively, 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 $10.0 million, or 21%, in the three months ended June 30, 2022, compared to the three months ended June 30, 2021. Additionally, gathering, transportation and marketing expense per Boe decreased $2.67 per Boe from $5.62 per Boe to $2.95 per Boe. This decrease was driven primarily by lower sulfur processing and transportation expenses.

(iii)Production and other taxes increased $39.6 million, or 153%, in the three months ended June 30, 2022, compared to the three months ended June 30, 2021 and increased $2.04 per Boe, an increase of 68%, to $5.05 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 $22.4 million, or 851%, in the three months ended June 30, 2022, compared to the three months ended June 30, 2021. Additionally, workover expense per Boe increased $1.62 per Boe from $0.31 per Boe to $1.93 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 and (ii) additional costs from our 2021 Acquisitions and Uinta Transaction, which contributed $14.8 million and $2.9 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.

(v)Midstream operating expense increased $0.7 million, or 29%, in the three months ended June 30, 2022, compared to the three months ended June 30, 2021.

Depreciation, depletion and amortization. In the three months ended June 30, 2022, depreciation, depletion and amortization increased $55.3 million, or 73%, compared to the three months ended June 30, 2021, driven primarily by $24.3 million and

$33.4 million of additional depreciation, depletion and amortization due to our 2021 Acquisitions and our 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 $3.5 million, or 22%, for the three months ended June 30, 2022, compared to the three months ended June 30, 2021, primarily driven by (i) an increase in equity-based compensation expense of $3.0 million due to awards that were granted as part of the Merger Transactions and the increase in fair value of the Company's liability-classified profits interest awards and (ii) $3.3 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 $1.5 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 June 30,
	2022		2021		$ Change		% Change
General and administrative expense (in thousands):
Recurring general and administrative expense	$	8,052	$	6,019	$	2,033	34	%
Transaction and nonrecurring expenses	2,249		3,704		(1,455)		(39)	%
Equity-based compensation	9,355		6,399		2,956		46	%
Total general and administrative expense	$	19,656	$	16,122	$	3,534	22	%
General and administrative expense per Boe:
Recurring general and administrative expense	$	0.62	$	0.70	$	(0.08)	(11)	%
Transaction and nonrecurring expenses	0.17		0.43		(0.26)		(60)	%
Equity-based compensation	0.72		0.74		(0.02)		(3)	%

Other operating costs. Other operating costs include exploration expense and gain on sale of assets. Other operating costs changed by $11.0 million, compared to the three months ended June 30, 2021, primarily driven by $9.2 million lower gain on sale of assets recognized during the three months ended June 30, 2022.

Interest expense

In the three months ended June 30, 2022, we incurred interest expense of $24.9 million, as compared to $17.4 million in the three months ended June 30, 2021, a 43% 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 June 30,
	2022		2021		$ Change		% Change
Gain (loss) on derivatives (in thousands):
Gain (loss) on commodity derivatives	$	(177,209)	$	(356,308)	$	179,099	(50)	%
Gain (loss) on interest rate derivatives	—		312		(312)		(100)	%
Gain (loss) on derivatives	$	(177,209)	$	(355,996)	$	178,787	(50)	%

Our loss on commodity derivatives during the three months ended June 30, 2022 decreased $178.8 million, or 50%, compared to the three months ended June 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 three months ended June 30, 2022.

Income from equity affiliates

Our income from equity method investments was $2.3 million for the three months ended June 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 three months ended June 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 June 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 June 30, 2022 we recognized income tax expense of $17.8 million for an effective tax rate of 5.9%. 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 June 30,
	2022		2021		$ Change		% Change
(in thousands)
Net income (loss)	$	281,898	$	(272,861)	$	554,759	(203)	%
Adjustments to reconcile to Adjusted EBITDAX:
Interest expense	24,937		17,443
Realized (gain) loss on interest rate derivatives	—		3,394
Income tax expense (benefit)	17,798		1
Depreciation, depletion and amortization	131,573		76,228
Exploration expense	1,848		23
Non-cash (gain) loss on derivatives	(89,655)		95,459
Non-cash equity-based compensation expense	9,355		6,399
(Gain) loss on sale of assets	(197)		(9,417)
Other (income) expense	303		(96)
Certain redeemable noncontrolling interest distributions made by OpCo related to Manager Compensation	(10,064)		—
Transaction and nonrecurring expenses (1)	5,548		4,175
Early settlement of derivative contracts (2)	—		198,688
Adjusted EBITDAX (non-GAAP)	$	373,344	$	119,436	$	253,908	213	%
Adjustments to reconcile to Levered Free Cash Flow:
Interest expense, excluding non-cash deferred financing cost amortization	(22,608)		(12,884)
Realized (gain) loss on interest rate derivatives	—		(3,394)
Current income tax benefit (expense)	(3,026)		(1)
Tax-related redeemable noncontrolling interest distributions made by OpCo	(17,167)		—
Development of oil and natural gas properties	(193,388)		(40,272)
Levered Free Cash Flow (non-GAAP)	$	137,155	$	62,885	$	74,270	118	%

(1)Transaction and nonrecurring expenses of $5.5 million for the three months ended June 30, 2022 were primarily related to (i) transition service agreement costs incurred for the Uinta Transaction and (ii) acquisition and debt transaction related costs. Transaction and nonrecurring expenses of $4.2 million for the three months ended June 30, 2021 were primarily related to legal, consulting and other fees related to the formation of Independence, the acquisition of Titan Energy Holdings, LLC (f/k/a Liberty Energy LLC) (the "Titan Acquisition") and the related reorganization 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 $253.9 million, or 213%, in the three months ended June 30, 2022, compared to the three months ended June 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 and our Uinta Transaction. 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 $74.3 million, or 118%, in the three months ended June 30, 2022 compared to the three months ended June 30, 2021, primarily driven by our increased Adjusted EBITDAX offset by $153.1 million of increased capital expenditures related to our additional reinvestment activities following the increase in commodity prices.

Six Months Ended June 30, 2022 Compared to Six Months Ended June 30, 2021

Revenues

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


	Six Months Ended June 30,
		2022		2021		$ Change		% Change
Revenues (in thousands):
Oil		$	975,076	$	405,743	$	569,333	140	%
Natural gas		350,488		143,492		206,996		144	%
Natural gas liquids		155,043		74,291		80,752		109	%
Midstream and other		26,737		24,464		2,273		9	%
Total revenues		$	1,507,344	$	647,990	$	859,354	133	%
Average realized prices, before effects of derivative settlements:
Oil ($/Bbl)		$	99.84	$	60.84	$	39.00	64	%
Natural gas ($/Mcf)		5.62		3.31		2.31		70	%
NGLs ($/Bbl)		42.92		25.29		17.63		70	%
Total ($/Boe)		62.28		37.06		25.22		68	%
Net sales volumes:
Oil (MBbls)		9,766		6,669		3,097		46	%
Natural gas (MMcf)		62,367		43,305		19,062		44	%
NGLs (MBbls)		3,612		2,937		675		23	%
Total (MBoe)		23,773		16,824		6,949		41	%
Average daily net sales volumes:
Oil (MBbls/d)		54		37		17		46	%
Natural gas (MMcf/d)		345		239		106		44	%
NGLs (MBbls/d)		20		16		4		25	%
Total (MBoe/d)		131		93		38		41	%

Oil revenue. Oil revenue increased $569.3 million, or 140%, in the six months ended June 30, 2022, compared to the six months ended June 30, 2021. This was driven primarily by higher realized oil prices that resulted in an increase of $380.9 million (an increase of 64% per Bbl) and a $188.4 million increase in sales volume (17 MBbls/d or 46%). The increase in sales volumes primarily related to our 2021 Acquisitions and Uinta Transaction, which contributed an additional 1,918 MBbls and 1,593 MBbls, respectively, partially offset by the natural decline from our existing asset base of 414 MBbls.

Natural gas revenue. Natural gas revenue increased $207.0 million, or 144% in the six months ended June 30, 2022, compared to the six months ended June 30, 2021. This was driven primarily by higher natural gas prices that resulted in an increase of $143.9 million (an increase of 70% per Mcf) and a $63.1 million increase in sales volume (106 MMcf/d, or 44%). The increase in sales volumes was primarily related to our 2021 Acquisitions and Uinta Transaction, which contributed an additional 18,674 MMcf and 4,570 MMcf, respectively, partially offset by the natural decline from our existing asset base of 4,182 MMcf.

NGL revenue. NGL revenue increased $80.8 million, or 109%, in the six months ended June 30, 2022, compared to the six months ended June 30, 2021. This was driven primarily by higher realized NGL prices that resulted in an increase of $63.7 million (an increase of 70% per Bbl) and a $17.1 million increase in sales volume (4 MBbls/d, or 25%).

Midstream and other revenue. Midstream and other revenue increased $2.3 million, or 9%, in the six months ended June 30, 2022, compared to the six months ended June 30, 2021, driven primarily by higher midstream revenue related to the 2021 Acquisitions.

Expenses


	Six Months Ended June 30,
		2022		2021		$ Change		% Change
Expenses (in thousands):
Operating expense		$	474,952	$	285,953	$	188,999	66	%
Depreciation, depletion and amortization		230,592		160,097		70,495		44	%
General and administrative expense		42,178		22,751		19,427		85	%
Other operating costs		(3,048)		(9,338)		6,290		NM*
Total expenses		$	744,674	$	459,463	$	285,211	62	%
Selected expenses per Boe:
Operating expense, excluding production and other taxes		$	15.27	$	13.89	$	1.38	10	%
Production and other taxes		4.71		3.10		1.61		52	%
Depreciation, depletion and amortization		9.70		9.52		0.18		2	%

* NM = Not meaningful.

Operating expense. Operating expense increased $189.0 million, or 66%, in the six months ended June 30, 2022, compared to the six months ended June 30, 2021, driven primarily by the following factors:

(i)Lease and asset operating expense increased $103.9 million, or 79%, in the six months ended June 30, 2022, compared to the six months ended June 30, 2021. Additionally, lease and asset operating expense per Boe increased $2.10 per Boe from $7.79 per Boe to $9.89 per Boe. This $103.9 million increase was driven primarily by higher production during the six months ended June 30, 2022, due in part to the 2021 Acquisitions and Uinta Transaction, which contributed $72.7 million and $8.5 million to the increase, respectively, 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 $4.9 million, or 5%, in the six months ended June 30, 2022, compared to the six months ended June 30, 2021. Additionally, gathering, transportation and marketing expense per Boe decreased $1.79 per Boe from $5.43 per Boe to $3.64 per Boe. This decrease was driven primarily by lower sulfur processing and transportation expenses.

(iii)Production and other taxes and increased $59.8 million, or 115%, in the six months ended June 30, 2022, compared to the six months ended June 30, 2021 and increased $1.61 per Boe, an increase of 52%, to $4.71 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 $30.1 million, or 615%, in the six months ended June 30, 2022, compared to the six months ended June 30, 2021. Additionally, workover expense per Boe increased $1.18 per Boe from $0.29 per Boe to $1.47 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 and (ii) additional costs from our 2021 Acquisitions and Uinta Transaction, which contributed $20.3 million and $2.9 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.

(v)Midstream operating expense increased $0.1 million, or 1%, in the six months ended June 30, 2022, compared to the six months ended June 30, 2021.

Depreciation, depletion and amortization. In the six months ended June 30, 2022, depreciation, depletion and amortization increased $70.5 million, or 44%, compared to the six months ended June 30, 2021, driven primarily by $55.1 million and $33.4 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 $19.4 million, or 85%, for the six months ended June 30, 2022, compared to the six months ended June 30, 2021, primarily driven by (i) an increase in equity-based compensation expense of $10.7 million due to awards that were granted as part of the Merger Transactions and the increase in fair value of the Company's liability-classified profits interest awards and (ii) $6.6 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. 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”).


	Six Months Ended June 30,
		2022		2021		$ Change		% Change
General and administrative expense (in thousands):
Recurring general and administrative expense		$	16,315	$	8,667	$	7,648	88	%
Transaction and nonrecurring expenses		5,393		4,348		1,045		24	%
Equity-based compensation		20,470		9,736		10,734		110	%
Total general and administrative expense		$	42,178	$	22,751	$	19,427	85	%
General and administrative expense per Boe:
Recurring general and administrative expense		$	0.69	$	0.52	$	0.17	33	%
Transaction and nonrecurring expenses		0.23		0.26		(0.03)		(12)	%
Equity-based compensation		0.86		0.58		0.28		48	%

Other operating costs. Other operating costs include exploration expense and gain on sale of assets. Other operating costs changed by $6.3 million, compared to the six months ended June 30, 2021, primarily driven by a $4.4 million lower gain on sale of assets recognized during the six months ended June 30, 2022.

Interest expense

In the six months ended June 30, 2022, we incurred interest expense of $41.5 million, as compared to $24.8 million in the six months ended June 30, 2021, a 67% 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.

Gain (loss) on derivatives


	Six Months Ended June 30,
		2022		2021		$ Change		% Change
Gain (loss) on derivatives (in thousands):
Gain (loss) on commodity derivatives		$	(850,695)	$	(603,135)	$	(247,560)	41	%
Gain (loss) on interest rate derivatives		—		325		(325)		(100)	%
Gain (loss) on derivatives		$	(850,695)	$	(602,810)	$	(247,885)	41	%

Our loss on commodity derivatives during the six months ended June 30, 2022 increased $247.9 million, or 41%, compared to the six months ended June 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 six months ended June 30, 2022.

Income from equity affiliates

Our income from equity method investments was $3.3 million for the six months ended June 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 six months ended June 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 six months ended June 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 six months ended June 30, 2022 we recognized income tax expense of $3.9 million for an effective tax rate of 3.1%. 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)


	Six Months Ended June 30,
		2022		2021		$ Change		% Change
(in thousands)
Net income (loss)		$	(124,109)	$	(439,129)	$	315,020	(72)	%
Adjustments to reconcile to Adjusted EBITDAX:
Interest expense		41,461		24,826
Realized (gain) loss on interest rate derivatives		—		7,022
Income tax expense (benefit)		(3,927)		14
Depreciation, depletion and amortization		230,592		160,097
Exploration expense		1,939		79
Non-cash (gain) loss on derivatives		408,030		304,579
Non-cash equity-based compensation expense		20,470		9,736
(Gain) loss on sale of assets		(4,987)		(9,417)
Other (income) expense		1,802		6
Certain redeemable noncontrolling interest distributions made by OpCo related to Manager Compensation		(20,128)		—
Transaction and nonrecurring expenses (1)		17,107		4,819
Early settlement of derivative contracts (2)		—		198,688
Adjusted EBITDAX (non-GAAP)		$	568,250	$	261,320	$	306,930	117	%
Adjustments to reconcile to Levered Free Cash Flow:
Interest expense, excluding non-cash deferred financing cost amortization		(37,535)		(19,417)
Realized (gain) loss on interest rate derivatives		—		(7,022)
Current income tax benefit (expense)		(7,976)		(14)
Tax-related redeemable noncontrolling interest distributions made by OpCo		(17,167)		—
Development of oil and natural gas properties		(278,868)		(65,099)
Levered Free Cash Flow (non-GAAP)		$	226,704	$	169,768	$	56,936	34	%

(1)Transaction and nonrecurring expenses of $17.1 million for the six months ended June 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 and (iii) acquisition and debt transaction related costs. Transaction and nonrecurring expenses of $4.8 million for the six months ended June 30, 2021 were primarily related to legal, consulting and other fees related to the formation of Independence, the Titan Acquisition and the related reorganization transactions.

Adjusted EBITDAX increased by $306.9 million, or 117%, in the six months ended June 30, 2022, compared to the six months ended June 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 and our Uinta Transaction. 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 $56.9 million, or 34%, in the six months ended June 30, 2022 compared to the six months ended June 30, 2021, primarily driven by our increased Adjusted EBITDAX offset by $213.8 million of increased capital expenditures related to our additional reinvestment activities following the increase in commodity prices.

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:


	June 30, 2022		December 31, 2021
	(in thousands)
Cash and cash equivalents	$	54,580	$	128,578
Long-term debt	1,515,702		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:


	Six Months Ended June 30,
		2022		2021
		(in thousands)
Net cash provided by operating activities		$	398,454	$	35,678
Net cash used in investing activities		(864,036)		(86,670)
Net cash provided by financing activities		394,613		90,209

Net cash provided by operating activities. Net cash provided by operating activities for the six months ended June 30, 2022 increased by $362.8 million, or 1017%, compared to the six months ended June 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 six months ended June 30, 2022 increased by $777.4 million, or 897%, compared to the six months ended June 30, 2021, primarily due to $566.6 million of additional acquisitions of oil and natural gas properties in 2022, driven by the Uinta Transaction, and an additional $191.6 million of cash development capital expenditures as we have resumed reinvestment activity in relation to higher commodity prices.

Net cash provided by financing activities. Net cash provided by financing activities for the six months ended June 30, 2022 was $394.6 million, as compared to a $90.2 million use of cash in the six months ended June 30, 2021. This increase was primarily due to net cash inflows from our debt transactions, primarily the result of 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 $61.4 million in distributions to redeemable noncontrolling interests and $12.2 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 May 6, 2025. At June 30, 2022, we had $829.0 million of outstanding borrowings under the Revolving Credit Facility and $17.8 million in outstanding letters of credit.

In connection with the closing of the Uinta Transaction, we entered into an amendment to our Revolving Credit Facility to increase the borrowing base to $1.8 billion with an elected commitment amount of $1.3 billion.

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 June 30, 2022 was 4.42%.

The borrowing base is subject to semi-annual scheduled redeterminations on or about April 1 and October 1 of each year, as well as (i) elective borrowing base interim redeterminations at our request not more than twice during any consecutive 12-month period or the required lenders not more than once during any consecutive 12-month period and (ii) elective borrowing base interim redeterminations at our request following any acquisition of oil and natural gas properties with a purchase price in the aggregate of at least 5.0% of the then effective borrowing base. The borrowing base will be automatically reduced upon (a) the issuance of certain permitted junior lien debt and other permitted additional debt, (b) the sale or other disposition of borrowing base properties if the aggregate net present value, discounted at 9% per annum (“PV-9”) of such properties sold or

disposed of is in excess of 5.0% of the borrowing base then in effect and (c) early termination or set-off of swap agreements (x) the administrative agent relied on in determining the borrowing base or (y) if the value of such swap agreements so terminated is in excess of 5.0% of the borrowing base then in effect.

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

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


	Six Months Ended June 30,
		2022		2021
		(in thousands)
Total development of oil and natural gas properties		$	278,868	$	65,099
Change in accruals or other non-cash adjustments		(38,512)		(16,302)
Cash used in development of oil and natural gas properties		240,356		48,797
Cash used in acquisition of oil and natural gas properties		627,390		60,828
Non-cash acquisition of oil and natural gas properties		—		10,537
Total expenditures on acquisition and development of oil and natural gas properties		$	867,746	$	120,162

Our development of oil and natural gas properties was higher during the six months ended June 30, 2022, compared to the six months ended June 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 six ended June 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 $627.4 million in 2022 for the acquisition of oil and natural gas properties, primarily related to our Uinta Transaction, as compared to $60.8 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 June 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 $0.29 per share of our Class A Common Stock to shareholders during the six months ended June 30, 2022.

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 June 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:

•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.

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 June 30, 2022, our derivative portfolio had an aggregate notional value of approximately $2.0 billion, and the fair market value of our commodity derivative contracts was a net liability of $0.9 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 June 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 $279.6 million. If prices decreased by 10%, our derivative position would change by approximately $279.2 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 June 30, 2022, we had $829.0 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 $4.1 million increase or decrease in interest expense for the six months ended June 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

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 June 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 June 30, 2022 that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.

Part II – Other Information

Item 1. Legal Proceedings

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

Item 1A. Risk Factors

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

Continuing or worsening inflationary issue 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, 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.

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

None.

Item 3. Defaults Upon Senior Securities

None.

Item 4. Mine Safety Disclosures

Not applicable.

Item 5. Other Information

Not applicable.

Item 6. Exhibits


Exhibit No.			Description
2.1			Transaction Agreement, dated as of June 7, 2021, by and among Contango Oil & Gas Company, Independence Energy LLC, IE PubCo Inc., IE OpCo LLC, IE L Merger Sub LLC and IE C Merger Sub Inc. (incorporated by reference to Exhibit 2.1 to the Company's proxy statement/prospectus, filed with the Securities and Exchange Commission on October 8, 2021).
2.2			Membership Interest Purchase Agreement, dated as of February 15, 2022, by and between Verdun Oil Company II LLC and Javelin VentureCo, LLC, and Crescent Energy OpCo LLC, as guarantor (incorporated by reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K filed with the Securities and Exchange Commission on February 16, 2022).
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 Quarterl y 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).
10.1*			Form of Equity Incentive Plan RSU Agreement (Director)
31.1*			Certification of Chief Executive Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002
31.2*			Certification of Chief Financial Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002
32.1**			Certification of Chief Executive Officer and Chief Financial Officer pursuant to 18 U.S.C. § 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002
101.INS**			XBRL Instance Document
101.SCH**			XBRL Schema Document
101.CAL**			XBRL Calculation Linkbase Document
101.LAB**			XBRL Label Linkbase Document
101.PRE**			XBRL Presentation Linkbase Document
101.DEF**			XBRL Definition Linkbase Document

* 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.

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)

August 9, 2022						/s/ David Rockecharlie
						David Rockecharlie
						Chief Executive Officer
						(Principal Executive Officer)

August 9, 2022						/s/ Brandi Kendall
						Brandi Kendall
						Chief Financial Officer
						(Principal Financial Officer)