UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 8-K

CURRENT REPORT

PURSUANT TO SECTION 13 OR 15(D)

OF THE SECURITIES EXCHANGE ACT OF 1934

Date of report (Date of earliest event reported): February 7, 2022

Crescent Energy Company

(Exact Name of Registrant as Specified in Charter)

Delaware	001-41132	87-1133610
(State or Other Jurisdiction of Incorporation)	(Commission File Number)	(I.R.S. Employer Identification Number)

600 Travis Street, Suite 7200 Houston, Texas	77002
(Address of Principal Executive Offices)	(Zip Code)

(713) 337-4600

(Registrant’s Telephone Number, Including Area Code)

Check the appropriate box below if the Form 8-K filing is intended to simultaneously satisfy the filing obligation of the registrant under any of the following provisions:

☐ Written communication pursuant to Rule 425 under the Securities Act (17 CFR 230.425)

☐ Soliciting material pursuant to Rule 14a-12 under the Exchange Act (17 CFR 240.14a-12)

☐ Pre-commencement communication pursuant to Rule 14d-2(b) under the Exchange Act (17 CFR 240.14d-2(b))

☐ Pre-commencement communication pursuant to Rule 13e-4(c) under the Exchange Act (17 CFR 240.13e-4(c))

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

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

Indicate by check mark whether the registrant is an emerging growth company as defined in Rule 405 of the Securities Act of 1933 (§ 230.405 of this chapter) or Rule 12b-2 of the Securities Exchange Act of 1934 (§ 240.12b-2 of this chapter).

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 13(a) of the Exchange Act.  ☐

Item 2.02. Results of Operations and Financial Condition.

On February 7, 2022, in connection with the Notes Offering (as defined below), Crescent Energy Company (NYSE: CRGY) (“CRGY” or “our,” “us,” or “we”) provided certain updated disclosures to potential investors, the relevant excerpts of which are set forth below.

Preliminary Production Data for the Three Months Ended December 31, 2021

As of the date of this current report, we have not finalized our financial and operational results for the three months or the year ended December 31, 2021. However, based on preliminary information, we estimate that our December production ranged from 112 to 118 MBoe/d including Contango (as defined below) production after the close of the Merger Transactions (as defined below) on December 7, 2021.

This preliminary estimate is derived from our internal records and is based on the most current information available to management as to the outcome and timing of future events, including current planned capital expenditures, drilling activity, commodity prices and well results, as well as current expected unit costs for 2022. This preliminary estimate has not been audited or reviewed by our independent auditors nor have our independent auditors performed any procedures with respect to this information or expressed any opinion or any form of assurance on such information. This preliminary estimate is preliminary, unaudited and inherently uncertain. Our normal reporting processes with respect to the foregoing preliminary estimate have not been fully completed and our auditors have not completed an audit or review of such estimate. During the course of our and our auditors’ review on this preliminary estimate, we could identify items that would require us to make adjustments and which could affect our final results. Any such adjustments could be material. This preliminary estimate should not be viewed as indicative of our financial condition or results as of or for any future period. Actual results could differ from the estimates, trends and expectations discussed herein, and such differences could be material.

In addition, the information contained in Item 8.01 of this Current Report is incorporated into this Item 2.02 by reference.

The information in this Item 2.02 shall not be deemed to be “filed” for purposes of Section 18 of the Securities Exchange Act of 1934, as amended (the “Exchange Act”), or otherwise subject to the liabilities of that section, and is not incorporated by reference into any filing under the Securities Act of 1933, as amended (the “Securities Act”), or the Exchange Act.

Item 7.01. Regulation FD Disclosure.

On February 7, 2022, Crescent Energy Finance LLC (“CE Finance”), a subsidiary of CRGY, issued a news release announcing that, subject to market conditions, CE Finance intends to offer (the “Notes Offering”) for sale in a private placement pursuant to Rule 144A and Regulation S under the Securities Act, to eligible purchasers $150 million aggregate principal amount of 7.250% Senior Notes due 2026. A copy of the news release is attached hereto as Exhibit 99.1 and incorporated herein by reference.

In addition, the information contained in Item 2.02 and Item 8.01 of this Current Report is incorporated into this Item 7.01 by reference.

The information contained in this Item 7.01, including Exhibit 99.1, shall not be deemed to be “filed” for purposes of Section 18 of the Exchange Act, or otherwise subject to the liabilities of that section, and is not incorporated by reference into any filing under the Securities Act, or the Exchange Act.

2

Item 8.01 Other Events.

On February 7, 2022, in connection with the Notes Offering (as defined below), CRGY provided certain updated disclosures to potential investors, the relevant excerpts of which are set forth below.

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Our proved developed producing (“PDP”) reserves as of December 31, 2021 have estimated average five-year and ten-year annual decline rates of approximately 11% and 10%, respectively, and an estimated 2022 PDP decline rate of 17%, based on production type curves used in our reserve reports. As a result of this low decline profile, we require relatively minimal capital expenditures to maintain our production and cash flows. Our properties located in the Eagle Ford, Barnett and the Rockies represent approximately 78% of our PD reserves as of December 31, 2021 and provide us with diversification from both a regional location and commodity price perspective, which provides us certain downside protection as it relates to commodity-specific pressures, isolated infrastructure constraints or severe weather events. The table below illustrates the aggregate leasehold acreage positions, reserve volumes and weighted average decline profiles associated with our proved assets as of December 31, 2021 and our pro forma production for the nine months ended September 30, 2021.

Operating Area	Net Acreage		Net Proved Reserves		% Oil & Liquids			Net PD Reserves		Weighted Average Annual PDP Decline(1)						Net Proved PV ($MM)(2)		Net PD PV ($MM)(2)		9 Months Ended 9/30/21 PF Production
	(in thousands)		(MMBoe)					(MMBoe)		Five Year			Ten Year			PV-10		PV-10		(MBoe/d)
Eagle Ford		143		136		79	%		84		13	%		11	%		1,954		1,306		28
Rockies(3)		243		147		52	%		143		10	%		10	%		1,319		1,250		35
Barnett		133		129		16	%		129		6	%		6	%		605		605		23
Permian		107		54		69	%		37		15	%		12	%		594		458		10
Mid Con		365		40		67	%		40		11	%		10	%		413		411		12
Other(4)		37		25		71	%		25		17	%		12	%		274		274		8
Total		1,029		532		54	%		459		11	%		10	%		5,159		4,305		115

(1) Reflects the estimated average annual decline rates of our PDP reserves as of December 31, 2021 for the five-year period ending January 31, 2027 and the ten-year period ending January 31, 2032 in each case based on the production type curves used in estimating our proved reserves.

(2) Reflects the net proved and net PD present values reflected in our proved reserve estimates as of January 1, 2022. PV-10 is not a financial measure prepared in accordance with U.S. generally accepted accounting principles (“GAAP”). Neither PV-10 or standardized measure represent an estimate of the fair market value of our oil and natural gas properties. We believe that the presentation of PV-10 is relevant and useful to our investors as supplemental disclosure to the standardized measure of future net cash flows, or after tax amount, because it presents the discounted future net cash flows attributable to our reserves prior to taking into account future income taxes and our current tax structure. We and others in the industry use PV-10 as measures to compare the relative size and value of proved reserves held by companies without regard to the specific tax characteristics of such entities. Investors should be cautioned that none of PV-10 and standardized measure represent an estimate of the fair market value of our proved reserves.

The following table presents a reconciliation of our PV-0 and PV-10 to the GAAP financial measure of Standardized Measure.

	SEC Pricing
	As of December 31, 2021
PV-10 of proved reserves	$	5,158,824
Impact removal of 10% discount rate		4,232,083
PV-0		9,390,907
Future income taxes		(352,136	)
Future net cash flows		9,038,771
Impact of 10% discount rate		(4,080,471	)
Standardized Measure	$	4,958,300

(3) We have a contractual right to participate in 28,768 net acres in the DJ basin through an agreement with a large operator and will be entitled to receive our proportionate share of acreage in the future based on our participation in proposed wells.

(4) Includes working interest properties located in California as well as diversified minerals.

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3

We had leasehold interests in an aggregate 1,029 thousand net acres as of December 31, 2021, on 898 thousand of which we were designated as operator.

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As of December 31, 2021, we owned mineral and royalty interests in 174 thousand gross acres and an overriding royalty interest in 117 thousand gross acres, both operated by large, well-capitalized oil and natural gas companies located primarily in the Eagle Ford, Marcellus, Utica and the Rockies. These interests entitle us to receive an average 5.4% royalty and 0.7% overriding royalty interest on all production from such acreage with no additional future capital or operating costs required.

******

The below table describes the net acreage, net PDP wells and proved reserve amounts for each of our geographic areas as of December 31, 2021:

Geographic Area	Net Acreage		Net PDP Wells		Proved Reserves
	(in thousands)				(MBoe)
Eagle Ford Shale		143		666		136,175
Barnett Shale		133		899		129,354
Mid Con		365		1,372		40,146
Rockies(1)		243		1,239		146,584
Permian Basin		107		1,112		54,056
Other Basins(2)		37		609		25,330

(1) We have a contractual right to participate in 28,768 net acres in the DJ basin through an agreement with a large operator and will be entitled to receive our proportionate share of acreage in the future based on our participation in proposed wells.

(2) Includes working interest properties located in California as well as diversified minerals.

Oil, natural gas and NGL data

The following table summarizes our estimated net proved reserves as of December 31, 2021 based on an evaluation prepared in accordance with SEC Pricing, including the provisions of the SEC rule regarding reserve estimation regarding a historical 12 month pricing average applied prospectively.

	As of December 31, 2021(1)
Net Proved Reserves:
Oil (MBbls)		210,160
Natural gas (MMcf)		1,469,953
NGLs (MBbls)		76,493
Total Proved Reserves (MBoe)		531,645
Standardized Measure (thousands)(2)		4,958,300
PV-0 (thousands)(2)	$	9,390,907
PV-10 (thousands)(2)	$	5,158,824
Net Proved Developed Reserves:
Oil (MBbls)		158,091
Natural gas (MMcf)		1,404,570
NGLs (MBbls)		66,402
Total Proved Developed Reserves (MBoe)		458,587
PV-0 (thousands)(2)	$	7,494,842
PV-10 (thousands)(2)	$	4,304,510
Net Proved Undeveloped Reserves:
Oil (MBbls)		52,069
Natural gas (MMcf)		65,383
NGLs (MBbls)		10,091
Total Proved Undeveloped Reserves (MBoe)		73,057
PV-0 (thousands)(2)	$	1,896,065
PV-10 (thousands)(2)	$	854,314

4

(1) Our reserves and present values were determined using average first-day-of-the-month prices for the prior 12 months in accordance with SEC guidance. For oil and NGL volumes, the average WTI posted price of $66.56 per barrel as of December 31, 2021, was adjusted for items such as gravity, quality, local conditions, gathering, transportation fees and distance from market. For natural gas volumes, the average Henry Hub spot price of $3.60 per MMBtu as of December 31, 2021, was similarly adjusted for items such as quality, local conditions, gathering, transportation fees and distance from market. All prices are held constant throughout the lives of the properties. The average adjusted product prices weighted by production over the remaining lives of the properties are $64.84 per barrel of oil, $3.46 per Mcf of natural gas and $27.21 per barrel of NGLs.

(2) PV-0 and PV-10 are not financial measures calculated in accordance with GAAP because they do not include the effects of income taxes on future net revenues. Our standardized measure includes future obligations under the Texas gross margin tax, but it does not include future federal income tax expenses because, due to the status of CE Finance (as defined below) as a flow through entity for U.S. federal income tax purposes, it is not subject to federal income taxes, and accordingly the Standardized Measure of estimated future cash flows attributable to CE Finance does not differ materially from the associated PV-10. None of PV-0, PV-10 or standardized measure represents an estimate of the fair market value of our oil and natural gas properties. We believe that the presentation of PV-0 and PV-10 is relevant and useful to our investors because it presents the discounted future net cash flows attributable to our reserves prior to taking into account future income taxes and our current tax structure. We and others in the industry use PV-0 and PV-10 as measures to compare the relative size and value of proved reserves held by companies without regard to the specific tax characteristics of such entities.

******

As of December 31, 2021, our aggregate PUD reserves were composed of 52,069 MBbls of oil, 65,383 MMcf of natural gas and 10,091 MBbls of NGLs, for a total of 73,057 MBoe. PUDs will be converted from undeveloped to developed as the applicable wells have been drilled or completed and have minimal capital remaining to bring the well onto production.

The following table summarizes our changes in PUDs for the year ended December 31, 2021 (in MBoe):

Balance, December 31, 2020	98,579
Purchases of reserves in place	1,427
Extensions and discoveries	8,588
Revisions of previous estimates	(21,115	)
Sales of reserves in place	(3,190	)
Transfers to proved developed	(11,232	)
Balance, December 31, 2021	73,057

Purchases of reserves in place of 1,427 during the year ended December 31, 2021 primarily relate to PUD locations added as part of the Merger Transactions. Revisions of previous estimates during the year ended December 31, 2021 were due to the removal of certain locations that are no longer part of our five-year consolidated development plan following the Merger Transactions. Additionally, during the year ended December 31, 2021, we spent $86 million to convert 11,232 MBoe to developed reserves.

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5

The following table provides a summary of our gross and net operated and non-operated drilling locations by area as of December 31, 2021:

	Gross Identified Drilling Locations(1)(2)
	Operated				Non-Operated				Total WI				Minerals
	Gross		Net		Gross		Net		Gross		Net		Gross		Net(3)
By Area
Eagle Ford Shale(4)
Total Locations		270.0		258.6		620.0		134.8		890.0		393.4		1,249.0		8.7
Barnett Shale(5)
Total Locations		40.0		24.3		—		—		40.0		24.3		—		—
Mid Con(6)
Total Locations		1.0		0.9		—		—		1.0		0.9		—		—
Rockies(7)
Total Locations		99.0		73.0		167.0		66.0		266.0		139.0		498.0		6.3
Permian Basin(8)
Total Locations		152.0		87.7		174.0		34.8		326.0		122.5		—		—
Other Basins(9)
Total Locations		5.0		4.7		—		—		5.0		4.7		2,550.0		20.6

(1) Locations as of December 31, 2021 have not been updated to reflect events subsequent to December 31, 2021.

(2) We estimate that the significant majority of our identified drilling locations are economic at oil and natural gas prices of $60/Bbl oil and $3.00/MMBtu gas.

(3) Net Mineral Locations Defined as Net Royalty Interest Locations.

(4) Includes 219.0 gross (123.1 net) total PUD locations and assumes average well spacing of 720 feet.

(5) Assumes well spacing of 500 feet.

(6) Includes 1.0 gross (0.9 net) total PUD locations.

(7) Includes 22.0 gross (17.8 net) total PUD locations and assumes average well spacing of 848 feet.

(8) Includes 88.0 gross (17.6 net) total PUD locations and assumes average well spacing of 887 feet.

(9) Includes working interest properties located in California as well as diversified minerals.

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The following table sets forth production, price and cost data with respect to our properties on a historical basis for the nine months ended September 30, 2021.

	Nine Months Ended September 30, 2021
	(in thousands)
Net Production:
Eagle Ford Shale:
Oil (MBbls)		3,907
Natural gas (MMcf)		8,498
NGLs (MBbls)		1,382
Total (MBoe)		6,706
Average daily production (MBoe/d)		25
Barnett Shale:
Oil (MBbls)		8
Natural gas (MMcf)		30,813
NGLs (MBbls)		1,013
Total (MBoe)		6,157
Average daily production (MBoe/d)		23
Total:
Oil (MBbls)		9,866
Natural gas (MMcf)		64,925
NGLs (MBbls)		4,488
Total (MBoe)		25,175
Average daily production (MBoe/d)		92

6

	Nine Months Ended September 30, 2021
	(in thousands)
Average Realized Prices (before effects of derivatives):
Eagle Ford Shale:
Oil (per Bbl)	$	62.79
Natural gas (per Mcf)	$	3.56
NGLs (per Bbl)	$	29.42
Barnett Shale:
Oil (per Bbl)	$	59.73
Natural gas (per Mcf)	$	2.87
NGLs (per Bbl)	$	22.10
Total:
Oil (per Bbl)	$	63.63
Natural gas (per Mcf)	$	3.55
NGLs (per Bbl)	$	27.10
Average Realized Prices (after effects of derivatives):
Eagle Ford Shale:
Oil (per Bbl)	$	52.13
Natural gas (per Mcf)	$	3.27
NGLs (per Bbl)	$	16.56
Barnett Shale:
Oil (per Bbl)	$	59.73
Natural gas (per Mcf)	$	2.90
NGLs (per Bbl)	$	18.77
Total:
Oil (per Bbl)	$	51.97
Natural gas (per Mcf)	$	3.16
NGLs (per Bbl)	$	17.04
Average Costs per Boe:
Eagle Ford Shale	$	18.03
Barnett Shale	$	9.65
Total	$	16.48

(1) As of the date of this Current Report on Form 8-K, we have not finalized our financial and operational results for the three months ended December 31, 2021. However, based on preliminary information, we estimate that our December 2021 production ranged from 112 MBoe/d to 118 MBoe/d.

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The following table sets forth information regarding our PDP wells as of December 31, 2021:

	As of December 31, 2021				Average Working Interest
	Proved Developed Producing Wells
	Working Interest Assets
	Gross		Net
Combined Total:
Natural gas		3,700		1,645		44	%
Oil		8,213		4,252		52	%
Total		11,913		5,897		50	%

7

	As of December 31, 2021				Average Net Revenue Interest
	Proved Developed Producing Wells
	Mineral Assets
	Gross		Net
Combined Total:
Natural gas		1,384		34		2.48	%
Oil		2,207		35		1.58	%
Total		3,591		69		1.93	%

Leasehold acreage

The following table sets forth certain information regarding the total developed and undeveloped acreage in which we owned an interest as of December 31, 2021.

Developed Acres

Undeveloped Acres

Total Acres(1)

Royalty Acres(2)

Gross

Net

Gross

Net

Gross

Net

Gross

NMA

Total

1,969,914

930,154

223,358

98,585

2,193,272

1,028,740

173,593

55,471

(1) We have a contractual right to participate in 28,768 net acres in the DJ basin through an agreement with a large operator and will be entitled to receive our proportionate share of acreage in the future based on our participation in proposed wells.

(2) Royalty acres excludes our overriding royalty interest in 117,000 gross acres.

Undeveloped acreage expirations

The following table sets forth the number of total net undeveloped acres as of December 31, 2021 that will expire in 2022, 2023, 2024 and 2025 unless production is established within the spacing units covering the acreage prior to the expiration dates or unless such leasehold rights are extended or renewed.

	2022		2023		2024		2025
Total		6,960		1		229		320

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The table below sets forth the results of our operated drilling activities for the periods indicated. The information should not be considered indicative of future performance, nor should it be assumed that there is necessarily any correlation among the number of productive wells drilled, quantities of reserves found or economic value. Productive wells are those that produce, or are capable of producing, commercial quantities of hydrocarbons, regardless of whether they produce a reasonable rate of return. Dry wells are those that prove to be incapable of producing hydrocarbons in sufficient quantities to justify completion.

	Year Ended December 31,
	2021
	Gross		Net
Operated Development Wells:
Productive		2.0		1.9
Dry holes		—		—
Total Development		2.0		1.9
Operated Exploratory Wells:
Productive		—		—
Dry holes		—		—
Total Exploratory		—		—
Operated Total Wells:
Productive		2.0		1.9
Dry holes		—		—
Total		2.0		1.9

8

As of December 31, 2021, we were not a party to any long-term drilling rig contracts. The following table provides our wells in progress, as well as the various stages of such progress, at December 31, 2021.

Well Status	Gross		Net
Drilling		6.0		5.7
Waiting on completion		4.0		3.8
Being completed, not producing		9.0		6.7

* * * * *

In September 2021, we entered into a purchase and sale agreement with an unrelated third party to acquire certain operated producing oil and natural gas properties predominantly located in the Central Basin Platform in Texas and New Mexico, with additional properties in the southwestern Permian and Powder River Basins, for a purchase price of $71.3 million. We closed the transaction in December 2021 and funded the purchase with borrowings under our revolving credit facility and cash on hand.

* * * * *

Production volumes sold

The following table presents historical sales volumes for our properties:

	Nine Months Ended September 30,
	2021		2020
Oil (MBbls)		9,866		9,390
Natural gas (MMcf)		64,925		54,506
NGLs (MBbls)		4,488		3,493
Total (MBoe)		25,175		21,967
Daily average (MBoe/d)		92		80

The shift in our production volume mix from oil to natural gas and NGLs since 2020 is due to the acquisition of Titan Energy Holdings, LLC (f/k/a Liberty Energy LLC) (the “Titan Acquisition”), which included assets that are slightly more natural gas-weighted than the existing production of our legacy assets.

Total sales volume increased 3,208 MBoe during the nine months ended September 30, 2021 compared to the nine months ended September 30, 2020. The increase is primarily due to the Titan Acquisition, which contributed an additional 6,079 MBoe, and the acquisition of 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”), which contributed an additional 233 MBoe. Sales volumes from our existing asset base decreased by 3,104 MBoe as a result of shut-ins at certain of our assets in Texas due to the severe winter storms occurring in February 2021 and the natural decline from our existing asset base that resulted from the reduction in development capital expenditures in 2020 as a response to the low commodity price environment.

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Results of operations:

Nine Months Ended September 30, 2021 Compared to Nine Months Ended September 30, 2020

Revenues

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

	Nine Months Ended September 30,				$ Change		% Change
	2021		2020
Revenues (in thousands):
Oil	$	627,817	$	341,808	$	286,009		84	%
Natural gas		230,271		87,113		143,158		164	%
Natural gas liquids		121,613		42,415		79,198		187	%
Midstream and other		34,017		30,631		3,386		11	%
Total revenues	$	1,013,718	$	501,967	$	511,751		102	%

9

	Nine Months Ended September 30,				$ Change		% Change
	2021		2020
Average realized prices, before effects of derivative settlements:
Oil ($/Bbl)	$	63.63	$	36.40	$	27.23		75	%
Natural gas ($/Mcf)	$	3.55	$	1.60	$	1.95		122	%
NGLs ($/Bbl)	$	27.10	$	12.14	$	14.96		123	%
Total ($/Boe)	$	38.92	$	21.46	$	17.46		81	%
Net sales volumes:
Oil (MBbls)		9,866		9,390		476		5	%
Natural gas (MMcf)		64,925		54,506		10,419		19	%
NGLs (MBbls)		4,488		3,493		995		28	%
Total (MBoe)		25,175		21,967		3,208		15	%
Average daily net sales volumes:
Oil (MBbls/d)		36		34		2		6	%
Natural gas (MMcf/d)		238		199		39		20	%
NGLs (MBbls/d)		16		13		3		23	%
Total (MBoe/d)		92		80		12		15	%

Oil revenue. Oil revenue increased $286.0 million, or 84%, in the nine months ended September 30, 2021 compared to the nine months ended September 30, 2020. This was driven primarily by higher realized oil prices that resulted in an increase of $268.7 million (an increase of 75% per Bbl) and a $17.3 million increase in sales volumes (2 MBbls per day, or 6%). The increase in sales volumes was primarily driven by our Titan Acquisition (1,822 MBbls of the increase) and DJ Basin Acquisition (107 MBbls of the increase), partially offset by the natural decline from our existing assets that resulted from the reduction in development capital expenditures in 2020.

Natural gas revenue. Natural gas revenue increased $143.2 million, or 164%, in the nine months ended September 30, 2021 compared to the nine months ended September 30, 2020. This was driven primarily by higher realized natural gas prices that resulted in an increase of $126.5 million (an increase of 122% per Mcf) in the nine months ended September 30, 2021 due in part to the severe winter storms in February 2021, and a $16.7 million increase in sales volumes (39 MMcf per day, or 20%). The increase in sales volumes was primarily driven by our Titan Acquisition (15,898 MMcf of the increase) and our DJ Basin Acquisition (736 MMcf of the increase), partially offset by the natural decline from our existing assets.

NGL revenue. NGL revenue increased $79.2 million, or 187%, in the nine months ended September 30, 2021 compared to the nine months ended September 30, 2020. This was driven primarily by higher realized NGL prices which resulted in an increase of $67.1 million (an increase of 123% per Bbl) as well as a $12.1 million increase in sales volumes (3 MBbls per day, or 23%).The increase in sales volumes was primarily driven by our Titan Acquisition (1,608 MBbls of the increase), partially offset by the natural decline from our existing assets.

Midstream and other revenue. Midstream and other revenue increased $3.4 million, or 11%, in the nine months ended September 30, 2021 compared to the nine months ended September 30, 2020, driven primarily by additional revenue of $5.4 million from the midstream assets acquired in the Titan Acquisition offset by lower midstream revenue from our other legacy midstream assets.

10

Expenses

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

	Nine Months Ended September 30,				$ Change			% Change
	2021		2020
Expenses (in thousands):
Operating expense	$	424,427	$	335,234	$	89,193			27	%
Depreciation, depletion and amortization		233,122		231,270		1,852			1	%
Impairment expense		—		233,957		(233,957	)		(100	)%
General and administrative expense		33,775		10,198		23,577			231	%
Other operating costs		263		8,088		(7,825	)		(97	)%
Total expenses	$	691,587	$	818,747	$	(127,160	)		(16	)%
Expenses per Boe:
Operating expense	$	16.86	$	15.26	$	1.60			10	%
Depreciation, depletion and amortization		9.26		10.53		(1.27	)		(12	)%
Impairment expense		—		10.65		(10.65	)		(100	)%
General and administrative expense		1.34		0.46		0.88			191	%
Other operating costs		0.01		0.37		(0.36	)		(97	)%
Total expenses per Boe	$	27.47	$	37.27	$	(9.80	)		(26	)%

Operating expense. Operating expense increased $89.2 million, or 27%, compared to nine months ended September 30, 2020, driven primarily by the following factors:

(i) Lease and asset operating expenses increased $28.9 million, or 17%, compared to the nine months ended September 30, 2020. This increase was driven primarily by higher production during the nine months ended September 30, 2021, due in part to the Titan Acquisition, which contributed $16.3 million to the increase, as well as certain costs that are indexed to oil commodity prices, such as CO2 purchase costs related to our CO2 flood asset in Wyoming. These commodity indexed operating expenses move in tandem with oil commodity prices and are partially offset by changes in our price realizations.

(ii) Gathering, transportation and marketing expense increased $17.3 million, or 15%, in the nine months ended September 30, 2021, compared to the nine months ended September 30, 2020. The increase was driven primarily by increased production and higher gathering and processing expenses of $38.6 million associated with the Titan Acquisition, which included assets that have a higher mix of natural gas and NGLs. This increase was offset by $12.0 million of nonrecurring expense incurred during the months ended September 30, 2020, due to the termination of a midstream contract at our Eagle Ford business. In addition, during the nine months ended September 30, 2021, we reached a settlement with a third-party operator to recoup $3.5 million of disputed gathering charges that we had paid in historical periods.

(iii) Production and other taxes increased $39.5 million, or 97%, in the nine months ended September 30, 2021, compared to the nine months ended September 30, 2020, driven primarily by higher oil and natural gas revenues, which increased the tax base upon which production and other taxes were calculated.

(iv) Workover expense increased $3.6 million, or 83%, compared to the nine months ended September 30, 2020, driven primarily by higher well workover activities.

Depreciation, depletion and amortization. In the nine months ended September 30, 2021, depreciation, depletion and amortization increased $1.9 million, or 1%, compared to the nine months ended September 30, 2020, driven primarily by an increase in our total production, offset by a reduction in the rate from our impairment in 2020.

Impairment expense. In the nine months ended September 30, 2020, because of significant declines in crude prices as a result of the COVID-19 pandemic, we recorded an impairment charge of $234.0 million to oil and natural gas properties.

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General and administrative expense. General and administrative expense increased $23.6 million, or 231%, compared to the nine months ended September 30, 2020, driven primarily by an increase in our equity-based compensation $13.8 million due to the mark-to-market impact of our liability classified awards, an increase in recurring general and administrative expenses of $2.1 million due to increased employee headcount, and an increase in legal, accounting, and other nonrecurring and transaction-related costs of $7.7 million.

	Nine Months Ended September 30,				$ Change		% Change
	2021		2020
General and Administrative Expense (in thousands):
Recurring general and administrative expense	$	8,445	$	6,367	$	2,078		33	%
Nonrecurring transaction expenses		10,703		3,000		7,703		257	%
Equity-based compensation		14,627		831		13,796		1,660	%
Total expenses	$	33,775	$	10,198	$	23,577		231	%

Other operating costs. Other operating costs included midstream operating expenses, exploration expenses and gain on sale of assets. Other operating costs decreased $7.8 million, or 97%, compared to the nine months ended September 30, 2020, driven primarily by the recognition of a $9.4 million gain on sale of assets during the nine months ended September 30, 2021, partially offset by $2.0 million of additional midstream expenses from our Titan Acquisition.

Interest expense. In the nine months ended September 30, 2021, we incurred interest expense of $37.8 million, as compared to $29.6 million in the nine months ended September 30, 2020, a 28% increase. This increase was primarily driven by the write-off of deferred financing charges associated with our various credit agreements with syndicates of lenders, which were terminated on May 6, 2021, in May 2021 and higher interest rates associated with the issuance of the notes.

Gain (loss) on derivatives

We enter 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. In June 2021, we settled certain of our outstanding derivative oil commodity contracts associated with calendar years 2022 and 2023 for $198.7 million, using borrowings of $160.0 million from our revolving credit facility and cash on hand. As part of this settlement, we entered into new commodity derivatives at prevailing market prices. The following table presents gain (loss) on derivatives for the periods presented:

	Nine Months Ended September 30,						$ Change
	2021			2020
	(in thousands)
Gain (loss) on commodity derivatives	$	(885,006	)	$	308,426		$	(1,193,432	)
Gain (loss) on interest rate derivatives		(26	)		(8,646	)		8,620
Total gain (loss) on derivatives	$	(885,032	)	$	299,780		$	(1,184,812	)

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.

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

	Nine Months Ended September 30,						$ Change			% Change
	2021			2020
	(in thousands)
Net income (loss)	$	(601,172	)	$	(46,442	)	$	(554,730	)		1194	%
Adjustments to reconcile to Adjusted EBITDAX:
Interest expense		37,810			29,555
Realized (gain) loss on interest rate derivatives		7,373			8,670
Income tax expense		407			13
Depreciation, depletion and amortization		233,122			231,270
Exploration expense		833			468
Non-cash (gain) loss on derivatives		493,698			(142,773	)
Impairment of oil and natural gas properties		—			233,957
Equity-based compensation expense		14,054			831
(Gain) loss on sale of assets		(9,418	)		—
Other (income) expense		54			(126	)
Transaction and nonrecurring expenses (1)		12,438			15,000
Early settlement of derivative contracts (2)		198,688			—
Adjusted EBITDAX (non-GAAP)	$	387,887		$	330,423		$	57,464			17	%
Adjustments to reconcile to Levered Free Cash Flow:
Interest expense, excluding non-cash deferred financing cost amortization		(28,460	)		(26,153	)
Realized (gain) loss on interest rate derivatives		(7,373	)		(8,670	)
Current income tax provision		(407	)		(13	)
Development of oil and natural gas properties		(107,998	)		(86,124	)
Levered Free Cash Flow (non-GAAP)	$	243,649		$	209,463		$	34,186			16	%

(1) Transaction and nonrecurring expenses of $12.4 million for the nine months ended September 30, 2021 were primarily related to legal, consulting and other fees incurred for (i) the redemption by certain of our consolidated subsidiaries of the noncontrolling equity interests held in such subsidiaries by a certain third-party investor in exchange for its proportionate share of the underlying oil and natural gas interests held directly or indirectly by such subsidiaries, (ii) the redemption by certain of our consolidated subsidiaries of the noncontrolling equity interests held in such subsidiaries by certain third-party investors in exchange for our membership interests in April 2021 and (iii) the series of transactions (the “Merger Transactions”) consummated pursuant to that certain Transaction Agreement, dated June 7, 2021, providing for the combination of the business of Contango Oil & Gas Company (“Contango”) with the business of Independence Energy LLC under CRGY, as if they had occurred on October 1, 2021. Transaction and nonrecurring expenses of $15.0 million for the nine months ended September 30, 2020 included (i) $3.0 million for the formation of Independence, the Titan Acquisition and the related reorganization transactions and (ii) $12.0 million for the termination of a midstream contract at our Eagle Ford business.

(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 new commodity derivative contracts at prevailing market prices. Adjusted EBITDAX increased by $57.5 million, or 17%, in the nine months ended September 30, 2021, compared to the nine months ended September 30, 2020, driven primarily 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 the Titan Acquisition. This increase was partially offset by a corresponding increase in operating costs due to higher production volume, as well as realized losses on our commodity derivatives in the nine months ended September 30, 2021 as compared to realized gains in the nine months ended September 30, 2020. Levered Free Cash Flow increased by $34.2 million, or 16%, in the nine months ended September 30, 2021 compared to the nine months ended September 30, 2020, driven primarily by (i) increased Adjusted EBITDAX of $57.5 million, offset by $21.9 million of increased capital expenditures related to 2021 development activities following the increase in commodity prices.

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Non-GAAP financial measures

This Current Report on Form 8-K 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.

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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, write-offs of other long-term assets, (gain) loss on sale of assets, other (income) expense, certain noncontrolling interest distributions made by Crescent Energy OpCo LLC (“OpCo”), 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, our revolving credit facility and the 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 (provision), tax-related noncontrolling 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 combined and consolidated financial statements prepared in accordance with GAAP.

******

The following table summarizes our cash flows for the periods indicated:

	Nine Months Ended September 30,
	2021			2020
	(in thousands)
Net cash provided by operating activities	$	148,632		$	297,434
Net cash used in investing activities		(126,776	)		(101,390	)
Net cash (used in) provided by financing activities		4,939			(175,685	)

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Nine Months Ended September 30, 2021 Compared to Nine Months Ended September 30, 2020

Net cash provided by operating activities. Net cash provided by operating activities for the nine months ended September 30, 2021 decreased by $148.8 million, or 50%, compared to the nine months ended September 30, 2020 primarily due to cash payments of $198.7 million associated with the early settlement of certain outstanding oil commodity derivative contracts in June 2021. As part of this settlement, we entered into new commodity derivatives at prevailing market prices.

Net cash used in investing activities. Net cash used in investing activities for the nine months ended September 30, 2021 increased by $25.4 million, or 25%, compared to the nine months ended September 30, 2020, primarily due to $65.4 million of acquisitions of oil and natural gas properties related to our DJ Basin Acquisition partially offset by $26.4 million of lower cash development capital expenditures and $12.8 million higher proceeds from the sale of assets.

Net cash provided by (used in) financing activities. Net cash provided by financing activities for the nine months ended September 30, 2021 was $4.9 million, as compared to a $175.7 million use of cash in the nine months ended September 30, 2020. This increase was primarily due to net cash inflows as a result of our debt refinancing during the nine months ended September 30, 2021 compared to net long-term debt repayments cash outflow of $161.2 million during the nine months ended September 30, 2020.

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

	Nine Months Ended September 30,
	2021			2020
	(in thousands)
Total development of oil and natural gas properties	$	107,998		$	86,124
Change in accruals of oil and natural gas properties		(24,301	)		23,925
Cash used in development of oil and natural gas properties		83,697			110,049
Cash used in acquisition of oil and natural gas properties		65,391			—
Non-cash acquisition of oil and natural gas properties		7,164			452,383
Total expenditure on acquisition and development of oil and natural gas properties	$	156,252		$	562,432

Our development of oil and natural gas properties was higher in the first nine months ended September 30, 2021, compared to the nine months ended September 30, 2020. Due to the low commodity price environment experienced throughout 2020 resulting from the coronavirus disease 2019 (COVID-19) pandemic and the actions from the Organization of Petroleum Exporting Countries, we significantly reduced our development capital expenditures starting in the second quarter of 2020 but have resumed development activities in 2021 as commodity prices have recovered. We used cash of $65.4 million in the nine months ended September 30, 2021 for the acquisition of oil and natural gas properties, primarily related to our DJ Basin Acquisition, and had a non-cash acquisition of $452.4 million in the nine months ended September 30, 2020 related to our Titan Acquisition.

* * * * *

This Item 8.01 incorporates by reference the following audit letter and reserve reports by our independent reserve engineers

• the audit letter of Netherland, Sewell & Associates, Inc., filed as Exhibit 99.2 herewith;

• the report of Netherland, Sewell & Associates, Inc., filed as Exhibit 99.3 herewith;

• the report of Cawley, Gillespie & Associates, Inc., filed as Exhibit 99.4 herewith;

• the report of William M. Cobb & Associates, Inc., filed as Exhibit 99.5 herewith; and

• the report of Haas Petroleum Engineering Services, Inc., filed as Exhibit 99.6 herewith.

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Item 9.01 Financial Statements and Exhibits.

(d)    Exhibits.

Exhibit	Description
23.1	Consent of Netherland, Sewell & Associates, Inc.
23.2	Consent of Cawley, Gillespie & Associates, Inc.
23.3	Consent of William M. Cobb & Associates, Inc.
23.4	Consent of Haas Petroleum Engineering Services, Inc.
99.1	Press Release, dated February 7, 2022.
99.2	Audit Letter of Netherland, Sewell & Associates, Inc.
99.3	Report of Netherland, Sewell & Associates, Inc.
99.4	Report of Cawley, Gillespie & Associates, Inc.
99.5	Report of William M. Cobb & Associates, Inc.
99.6	Report of Haas Petroleum Engineering Services, Inc.
104	Cover Page Interactive Data File (embedded within the Inline XBRL document).

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SIGNATURE

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

Date: February 7, 2022

CRESCENT ENERGY COMPANY
By:	/s/ Bo Shi
Name:	Bo Shi
Title:	General Counsel

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