UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

☒ QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES

EXCHANGE ACT OF 1934

For the quarterly period ended March 31, ~~2021~~2022

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

Commission File Number: 001-35371

~~Bonanza Creek Energy, Inc.~~

Civitas Resources, Inc.

(Exact name of registrant as specified in its charter)


Delaware						61-1630631
(State or other jurisdiction of incorporation or organization)						(I.R.S. Employer Identification No.)

~~410~~555 17th Street,

Suite ~~1400~~3700

Denver,

Colorado

80202

(Address of principal executive offices)

(Zip Code)

~~(720) 440-6100~~(303) 293-9100

(Registrant’s telephone number, including area code)


Securities registered pursuant to Section 12(b) of the Act:
Title of each class	Trading Symbol	Name of exchange on which registered
Common Stock, par value $0.01 per share	~~BCEI~~CIVI	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, 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

☐

~~Emerging growth~~Smaller reporting company

☐

~~Smaller reporting~~

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. ☐

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

Indicate by check mark whether the registrant has filed all documents and reports required to be filed by Sections 12, 13 or 15(d) of the Securities Exchange Act of 1934 subsequent to the distribution of securities under a plan confirmed by a court. ☒ ~~Yes~~ ☐ No

As of ~~April 30, 2021,~~May 2, 2022, the registrant had ~~30,732,645~~84,967,471 shares of common stock outstanding.

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~~BONANZA CREEK ENERGY,~~CIVITAS RESOURCES, INC.

~~INDEX~~FORM 10-Q

FOR THE QUARTER ENDED MARCH 31, 2022

TABLE OF CONTENTS

PAGE

Part I.

~~FINANCIAL INFORMATION~~Financial Information

Item 1.

Financial Statements (Unaudited)

Condensed Consolidated Balance Sheets as of March 31, ~~2021~~2022 and December 31, ~~2020~~2021

Condensed Consolidated Statements of Operations and Comprehensive Income ~~(Loss)~~(Loss) for the Three Months Ended March 31, ~~2021~~2022 and ~~2020~~2021

Condensed Consolidated Statements of Stockholders' Equity for the Three Months Ended March 31, ~~2021~~2022 and ~~2020~~2021

Condensed Consolidated Statements of Cash Flows for the Three Months Ended March 31, ~~2021~~2022 and ~~2020~~2021

Notes to the Condensed Consolidated Financial Statements

510

Item 2.

Management’s Discussion and Analysis of Financial Condition and Results of Operations

2233

Item 3.

Quantitative and Qualitative Disclosures About Market Risk

3140

Item 4.

Controls and Procedures

3341

Part II.

~~OTHER INFORMATION~~Other Information

Unregistered Sales of Equity Securities and Use of Proceeds

3641

Item 3.

Defaults Upon Senior Securities

3642

Item 4.

Mine Safety Disclosures

~~PART~~

Information Regarding Forward-Looking Statements

This Quarterly Report on Form 10-Q contains various statements, including those that express belief, expectation or intention, as well as those that are not statements of historic fact, that are forward-looking statements within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities and Exchange Act of 1934, as amended (the “Exchange Act”). When used in this Quarterly Report on Form 10-Q, the words “could,” “believe,” “anticipate,” “intend,” “estimate,” “expect,” “may,” “continue,” “predict,” “potential,” “project,” “plan,” “will,” and similar expressions are intended to identify forward-looking statements, although not all forward-looking statements contain such identifying words. These forward-looking statements are based on management's current belief, based on currently available information, as to the outcome and timing of future events.

Forward-looking statements include statements related to, among other things:

•the Company’s business strategies;

•reserves estimates;

•estimated sales volumes;

•the amount and allocation of forecasted capital expenditures and plans for funding capital expenditures and operating expenses;

•our ability to modify future capital expenditures;

•anticipated costs;

•compliance with debt covenants;

•our ability to fund and satisfy obligations related to ongoing operations;

•compliance with government regulations, including environmental, health, and safety regulations and liabilities thereunder;

•the adequacy of gathering systems and continuous improvement of such gathering systems;

•the impact from the lack of available gathering systems and processing facilities in certain areas;

•the impact of any pandemic or other public health epidemic, including the ongoing COVID-19 pandemic;

•oil, natural gas, and natural gas liquid prices and factors affecting the volatility of such prices;

•the impact of lower commodity prices;

•sufficiency of impairments;

•the ability to use derivative instruments to manage commodity price risk and ability to use such instruments in the future;

•our drilling inventory and drilling intentions;

•the impact of potentially disruptive technologies;

•our estimated revenue gains and losses;

•the timing and success of specific projects;

•our implementation of standard and long reach laterals;

•our intention to continue to optimize enhanced completion techniques and well design changes;

•stated working interest percentages;

•our management and technical team;

•outcomes and effects of litigation, claims, and disputes;

•primary sources of future production growth;

•our ability to replace oil and natural gas reserves;

•our ability to convert proved undeveloped reserves to producing properties within five years of their initial proved booking;

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•our ability to pay future cash dividends on our common stock;

•the impact of the loss a single customer or any purchaser of our products;

•the timing and ability to meet certain volume commitments related to purchase and transportation agreements;

•the impact of customary royalty interests, overriding royalty interests, obligations incident to operating agreements, liens for current taxes, and other industry-related constraints;

•our anticipated financial position, including our cash flow and liquidity;

•the adequacy of our insurance;

•the results, effects, benefits, and synergies of the Extraction Merger and the Crestone Peak Merger, future opportunities for the combined companies, other plans and expectations with respect to the mergers, and the anticipated impact of the mergers on the combined company’s results of operations, financial position, growth opportunities, and competitive position; and

•other statements concerning our anticipated operations, economic performance, and financial condition.

We have based these forward-looking statements on certain assumptions and analyses we have made in light of our experience and our perception of historical trends, current conditions, and expected future developments as well as other factors we believe are appropriate under the circumstances. They can be affected by inaccurate assumptions or by known or unknown risks and uncertainties. Many such factors will be important in determining actual future results. The actual results or developments anticipated by these forward-looking statements are subject to a number of risks and uncertainties, many of which are beyond our control, and may not be realized or, even if substantially realized, may not have the expected consequences. Actual results could differ materially from those expressed or implied in the forward-looking statements.

Factors that could cause actual results to differ materially include, but are not limited to, the following:

•the risk factors discussed in Part I, ~~- FINANCIAL INFORMATION~~Item 1A of our Annual Report on Form 10-K for the year ended December 31, 2021 and in Part II, Item 1A of this report;

•declines or volatility in the prices we receive for our oil, natural gas, and natural gas liquids;

•general economic conditions, whether internationally, nationally or in the regional and local market areas in which we do business;

•the effects of disruption of our operations or excess supply of oil and natural gas due to world health events, including the COVID-19 pandemic, and the actions by certain oil and natural gas producing countries;

•the continuing effects of the COVID-19 pandemic, including any recurrence or the worsening thereof;

•ability of our customers to meet their obligations to us;

•our access to capital;

•our ability to generate sufficient cash flow from operations, borrowings, or other sources to enable us to fully develop our undeveloped acreage positions;

•the presence or recoverability of estimated oil and natural gas reserves and the actual future sales volume rates and associated costs;

•uncertainties associated with estimates of proved oil and gas reserves;

•the possibility that the industry may be subject to future local, state, and federal regulatory or legislative actions (including additional taxes and changes in environmental regulation);

•environmental risks;

•seasonal weather conditions;

•lease stipulations;

•drilling and operating risks, including the risks associated with the employment of horizontal drilling and completion techniques;

•our ability to acquire adequate supplies of water for drilling and completion operations;

•availability of oilfield equipment, services, and personnel;

•exploration and development risks;

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•operational interruption of centralized oil and natural gas processing facilities;

•competition in the oil and natural gas industry;

•management’s ability to execute our plans to meet our goals;

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

•our ability to maintain effective internal controls;

•access to adequate gathering systems and pipeline take-away capacity;

•our ability to secure adequate processing capacity for natural gas we produce, to secure adequate transportation for oil, natural gas, and natural gas liquids we produce, and to sell the oil, natural gas, and natural gas liquids at market prices;

•costs and other risks associated with perfecting title for mineral rights in some of our properties;

•political conditions in or affecting other producing countries, including conflicts in or relating to the Middle East, South America, and Russia (including the current events involving Russia and Ukraine), and other sustained military campaigns or acts of terrorism or sabotage; and

•other economic, competitive, governmental, legislative, regulatory, geopolitical, and technological factors that may negatively impact our businesses, operations, or pricing.

All forward-looking statements speak only as of the filing date of this report. We disclaim any obligation to update or revise these statements unless required by law, and you should not place undue reliance on these forward-looking statements. Although we believe that our plans, intentions, and expectations reflected in or suggested by the forward-looking statements we make in this report are reasonable, we can give no assurance that these plans, intentions, or expectations will be achieved. We disclose important factors that could cause our actual results to differ materially from our expectations under Part II, Item 1A. Risk Factors and Part I, Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations and elsewhere in this report. These cautionary statements qualify all forward-looking statements attributable to us or persons acting on our behalf.

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PART I. FINANCIAL INFORMATION

~~Item~~ITEM 1. Financial ~~Statements.~~Statements

~~BONANZA CREEK ENERGY,~~CIVITAS RESOURCES, INC. AND SUBSIDIARIES

CONDENSEDCONSOLIDATED BALANCE SHEETS (UNAUDITED)

(in thousands, except per share amounts)

March 31, 2021 December 31, 2020
ASSETS
Current assets:
Cash and cash equivalents $ 38,695 $ 24,743
Accounts receivable, net:
Oil and gas sales 37,644 32,673
Joint interest and other 15,495 14,748
Prepaid expenses and other 3,468 3,574
Inventory of oilfield equipment 9,601 9,185
Derivative assets (note 10) 0 7,482
Total current assets 104,903 92,405
Property and equipment (successful efforts method):

Proved properties 1,096,588 1,056,773
Less: accumulated depreciation, depletion, and amortization (229,877) (211,432)
Total proved properties, net 866,711 845,341
Unproved properties 98,194 98,122
Wells in progress 43,664 50,609
Other property and equipment, net of accumulated depreciation of $3,871 in 2021 and $3,737 in 2020 3,143 3,239
Total property and equipment, net 1,011,712 997,311
Long-term derivative assets (note 10) 92 0
Right-of-use assets (note 3) 28,127 29,705
Deferred income tax assets (Note 12) 60,564 60,520
Other noncurrent assets 2,888 2,871
Total assets $ 1,208,286 $ 1,182,812
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities:
Accounts payable and accrued expenses (note 4) $ 39,607 $ 37,425
Oil and gas revenue distribution payable 23,720 18,613
Lease liability (note 3) 12,400 12,044
Derivative liability (note 10) 18,549 6,402
Total current liabilities 94,276 74,484
Long-term liabilities:
Credit facility (note 5) 0 0
Lease liability (note 3) 15,939 17,978
Ad valorem taxes 21,226 15,069
Derivative liability (note 10) 1,421 1,330
Asset retirement obligations for oil and gas properties (note 9) 28,664 28,699
Total liabilities 161,526 137,560
Commitments and contingencies (note 6) 0 0
Stockholders’ equity:
Preferred stock, $0.01 par value, 25,000,000 shares authorized, NaN outstanding 0 0
Common stock, $0.01 par value, 225,000,000 shares authorized, 20,839,727 and 20,839,227 issued and outstanding as of March 31, 2021 and December 31, 2020, respectively 4,282 4,282
Additional paid-in capital 708,836 707,209
Retained earnings 333,642 333,761
Total stockholders’ equity 1,046,760 1,045,252
Total liabilities and stockholders’ equity $ 1,208,286 $ 1,182,812


	March 31, 2022		December 31, 2021
ASSETS
Current assets:
Cash and cash equivalents	$	154,349	$	254,454
Accounts receivable, net:
Oil, natural gas, and NGL sales	410,418		362,262
Joint interest and other	72,888		66,390
Prepaid expenses and other	21,891		21,052
Inventory of oilfield equipment	14,557		12,386
Derivative assets	—		3,393
Total current assets	674,103		719,937
Property and equipment (successful efforts method):
Proved properties	5,983,892		5,457,213
Less: accumulated depreciation, depletion, and amortization	(608,898)		(430,201)
Total proved properties, net	5,374,994		5,027,012
Unproved properties	671,538		688,895
Wells in progress	213,153		177,296
Other property and equipment, net of accumulated depreciation of $5,403 in 2022 and $4,742 in 2021	51,046		51,639
Total property and equipment, net	6,310,731		5,944,842

Right-of-use assets	36,054		39,885
Deferred income tax assets	—		22,284

Other noncurrent assets	12,859		14,085
Total assets	$	7,033,747	$	6,741,033
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities:
Accounts payable and accrued expenses	$	296,433	$	246,188
Production taxes payable	188,962		144,408
Oil and natural gas revenue distribution payable	422,854		466,233
Lease liability	18,588		18,873
Derivative liability	384,694		219,804
Asset retirement obligations	24,000		24,000
Total current liabilities	1,335,531		1,119,506
Long-term liabilities:
Senior notes	492,123		491,710

Lease liability	17,920		21,398
Ad valorem taxes	296,773		232,147
Derivative liability	46,111		19,959
Deferred income tax liabilities	5,805		—
Asset retirement obligations	201,951		201,315
Total liabilities	2,396,214		2,086,035
Commitments and contingencies (Note 6)	0		0
Stockholders’ equity:
Preferred stock, $.01 par value, 25,000,000 shares authorized, none outstanding	—		—
Common stock, $.01 par value, 225,000,000 shares authorized, 84,941,558 and 84,572,846 issued and outstanding as of March 31, 2022 and December 31, 2021, respectively	4,916		4,912
Additional paid-in capital	4,194,444		4,199,108
Retained earnings	438,173		450,978
Total stockholders’ equity	4,637,533		4,654,998
Total liabilities and stockholders’ equity	$	7,033,747	$	6,741,033

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

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~~BONANZA CREEK ENERGY,~~CIVITAS RESOURCES, INC. AND SUBSIDIARIES

CONDENSEDCONSOLIDATED STATEMENTS OF OPERATIONS AND COMPREHENSIVE INCOME (LOSS) (UNAUDITED)

(in thousands, except per share amounts)

Three Months Ended March 31,
2021 2020
Operating net revenues:
Oil and gas sales $ 74,159 $ 60,405
Operating expenses:
Lease operating expense 5,731 5,699
Midstream operating expense 3,905 4,014
Gathering, transportation, and processing 4,967 3,481
Severance and ad valorem taxes 4,604 5,173
Exploration 96 373
Depreciation, depletion, and amortization 18,823 21,584
Abandonment and impairment of unproved properties 0 30,057
Bad debt expense 0 576
Merger transaction costs 3,295 0
General and administrative expense (including $1,612 and $1,239, respectively, of stock-based compensation) 9,251 9,429
Total operating expenses 50,672 80,386
Other income (expense):
Derivative gain (loss) (23,419) 100,419
Interest expense, net (419) (217)
Other income (expense) 188 (1,670)
Total other income (expense) (23,650) 98,532
Income (loss) from operations before taxes (163) 78,551
Income tax benefit 44 0
Net income (loss) $ (119) $ 78,551
Comprehensive income (loss) $ (119) $ 78,551
Net income (loss) per common share:
Basic $ (0.01) $ 3.80
Diluted $ (0.01) $ 3.80
Weighted-average common shares outstanding:
Basic 20,839 20,649
Diluted 20,839 20,684


	Three Months Ended March 31,
	2022		2021
Operating net revenues:
Oil, natural gas, and NGL sales	$	817,810	$	74,159
Operating expenses:
Lease operating expense	36,019		5,731
Midstream operating expense	5,712		3,905
Gathering, transportation, and processing	50,403		4,967
Severance and ad valorem taxes	63,304		4,604
Exploration	528		96
Depreciation, depletion, and amortization	184,860		18,823
Abandonment and impairment of unproved properties	17,975		—
Unused commitments	776		—

Merger transaction costs	20,534		3,295
General and administrative expense (including $8,090 and $1,612, respectively, of stock-based compensation)	35,720		9,251
Total operating expenses	415,831		50,672
Other income (expense):
Derivative loss	(295,493)		(23,419)
Interest expense	(9,066)		(419)
Gain on property transactions, net	16,797		—
Other income	783		188
Total other expense	(286,979)		(23,650)
Income (loss) from operations before income taxes	115,000		(163)
Income tax benefit (expense)	(23,361)		44
Net income (loss)	$	91,639	$	(119)

Comprehensive income (loss)	$	91,639	$	(119)

Net income (loss) per common share:
Basic	$	1.08	$	(0.01)
Diluted	$	1.07	$	(0.01)
Weighted-average common shares outstanding
Basic	84,840		20,839
Diluted	85,326		20,839

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

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~~BONANZA CREEK ENERGY,~~CIVITAS RESOURCES, INC. AND SUBSIDIARIES

CONDENSEDCONSOLIDATED STATEMENTS OF ~~STOCKHOLDERS'~~STOCKHOLDERS’ EQUITY (UNAUDITED)

(in thousands, except per share amounts)


					Additional										Additional
		Common Stock			Paid-In		Retained					Common Stock			Paid-In		Retained
		Shares	Amount		Capital		Earnings		Total			Shares	Amount		Capital		Earnings		Total
Balances, December 31, 2020		20,839,227	$	4,282	$	707,209	$	333,761	$	1,045,252
Balances, December 31, 2021											Balances, December 31, 2021	84,572,846	$	4,912	$	4,199,108	$	450,978	$	4,654,998

Restricted common stock issued	Restricted common stock issued	109	—		—		—		—		Restricted common stock issued	579,229	6		—		—		6

Stock used for tax withholdings	Stock used for tax withholdings	(38)	—		—		—		—		Stock used for tax withholdings	(215,811)	(2)		(12,932)		—		(12,934)
Exercise of stock options	Exercise of stock options	429	—		15		—		15		Exercise of stock options	5,294	—		178		—		178
Stock-based compensation	Stock-based compensation	—	—		1,612		—		1,612		Stock-based compensation	—	—		8,090		—		8,090
Net loss		—	—		—		(119)		(119)
Balances, March 31, 2021		20,839,727	$	4,282	$	708,836	$	333,642	$	1,046,760
Cash dividends, $1.2125 per share											Cash dividends, $1.2125 per share	—	—		—		(104,444)		(104,444)
Net income											Net income	—	—		—		91,639		91,639
Balances, March 31, 2022											Balances, March 31, 2022	84,941,558	$	4,916	$	4,194,444	$	438,173	$	4,637,533


Balances, December 31, 2019		20,643,738	$	4,284	$	702,173	$	230,233	$	936,690
Balances, December 31, 2020											Balances, December 31, 2020	20,839,227	$	4,282	$	707,209	$	333,761	$	1,045,252

Restricted common stock issued	Restricted common stock issued	13,674	—		—		—		—		Restricted common stock issued	109	—		—		—		—
Stock used for tax withholdings											Stock used for tax withholdings	(38)	—		—		—		—
Exercise of stock options											Exercise of stock options	429	—		15		—		15
Stock-based compensation											Stock-based compensation	—	—		1,612		—		1,612

Stock used for tax withholdings		(2,330)	—		(61)		—		(61)

Stock-based compensation		—	—		1,239		—		1,239
Net income		—	—		—		78,551		78,551
Balances, March 31, 2020		20,655,082	$	4,284	$	703,351	$	308,784	$	1,016,419

Net loss											Net loss	—	—		—		(119)		(119)
Balances, March 31, 2021											Balances, March 31, 2021	20,839,727	$	4,282	$	708,836	$	333,642	$	1,046,760

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

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~~BONANZA CREEK ENERGY,~~CIVITAS RESOURCES, INC. AND SUBSIDIARIES

CONDENSEDCONSOLIDATED STATEMENTS OF CASH FLOWS

(UNAUDITED)

(in thousands)

Three Months Ended March 31,
2021 2020
Cash flows from operating activities:
Net income (loss) $ (119) $ 78,551
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation, depletion, and amortization 18,823 21,584
Deferred income tax benefit (44) 0
Abandonment and impairment of unproved properties 0 30,057
Well abandonment costs and dry hole expense 0 (8)
Stock-based compensation 1,612 1,239
Non-cash lease component (84) (51)
Amortization of deferred financing costs 93 123
Derivative (gain) loss 23,419 (100,419)
Derivative cash settlement gain (loss) (3,791) 11,254
Other 0 (4,240)
Changes in current assets and liabilities:
Accounts receivable, net (5,718) 19,182
Prepaid expenses and other assets 106 1,100
Accounts payable and accrued liabilities 9,073 (9,768)
Settlement of asset retirement obligations (406) (610)
Net cash provided by operating activities 42,964 47,994
Cash flows from investing activities:
Acquisition of oil and gas properties (180) (284)
Exploration and development of oil and gas properties (28,730) (26,225)
Additions to property and equipment - non oil and gas (38) (362)
Net cash used in investing activities (28,948) (26,871)
Cash flows from financing activities:
Proceeds from credit facility 0 15,000
Payments to credit facility 0 (36,000)
Proceeds from exercise of stock options 15 0
Payment of employee tax withholdings in exchange for the return of common stock 0 (61)
Deferred financing costs (58) 0
Principal payments on finance lease obligations (21) (10)
Net cash used in financing activities (64) (21,071)
Net change in cash, cash equivalents, and restricted cash 13,952 52
Cash, cash equivalents, and restricted cash:
Beginning of period 24,845 11,095
End of period $ 38,797 $ 11,147
Supplemental cash flow disclosure(1):
Cash paid for interest, net of capitalization $ 318 $ 246
Changes in working capital related to drilling expenditures $ (4,371) $ (13,532)
(1) Refer to Note 3 - Leases in the notes to the condensed consolidated financial statements for discussion of right-of-use assets obtained in exchange for lease liabilities.


	Three Months Ended March 31,
	2022		2021
Cash flows from operating activities:
Net income (loss)	$	91,639	$	(119)
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation, depletion, and amortization	184,860		18,823
Deferred income tax expense (benefit)	23,361		(44)

Abandonment and impairment of unproved properties	17,975		—
Stock-based compensation	8,090		1,612
Amortization of deferred financing costs	1,078		93
Derivative loss	295,493		23,419
Derivative cash settlements loss	(166,578)		(3,791)
Gain on property transactions, net	(16,797)		—
Other	68		(84)
Changes in current assets and liabilities:
Accounts receivable, net	11,906		(5,718)
Prepaid expenses and other assets	(2,398)		106
Accounts payable and accrued liabilities	88,975		9,073
Settlement of asset retirement obligations	(5,131)		(406)
Net cash provided by operating activities	532,541		42,964
Cash flows from investing activities:
Acquisition of oil and natural gas properties	(300,087)		(180)
Cash acquired	44,310		—
Exploration and development of oil and natural gas properties	(260,667)		(28,730)

Additions to other property and equipment	(68)		(38)
Other	212		—
Net cash used in investing activities	(516,300)		(28,948)
Cash flows from financing activities:



Proceeds from exercise of stock options	178		15
Dividends paid	(103,596)		—
Payment of employee tax withholdings in exchange for the return of common stock	(12,928)		—
Deferred financing costs	—		(58)
Other	—		(21)
Net cash used in financing activities	(116,346)		(64)
Net change in cash, cash equivalents, and restricted cash	(100,105)		13,952
Cash, cash equivalents, and restricted cash:
Beginning of period	254,556		24,845
End of period(1)	$	154,451	$	38,797
Supplemental cash flow disclosure:


Cash paid for interest	$	(774)	$	(318)
Cash paid for income taxes	$	(6,300)	$	—


Changes in working capital related to drilling expenditures	$	(28,015)	$	4,371
(1) Includes $0.1 million of restricted cash and consists of funds for road maintenance and repairs that is presented in other noncurrent assets within the accompanying unaudited condensed consolidated balance sheets (“balance sheets”) as of both March 31, 2022 and March 31, 2021.

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

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~~BONANZA CREEK ENERGY,~~CIVITAS RESOURCES, INC. AND SUBSIDIARIES

NOTES TO THE CONDENSEDCONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED)

NOTE 1 - ~~ORGANIZATION AND BUSINESS~~SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Description of Operations

When we use the terms “Civitas,” the “Company,” “we,” “us,” or “our,” we are referring to Civitas Resources, Inc. and its consolidated subsidiaries unless the context otherwise requires. Effective November 1, 2021, Bonanza Creek Energy, Inc. ~~(“BCEI” or, together with our consolidated subsidiaries,~~changed its name to Civitas Resources, Inc. Civitas is an independent Denver-based exploration and production company focused on the ~~“Company”) is engaged primarily in acquiring, developing, extracting,~~acquisition, development, and ~~producing~~production of oil and associated liquids-rich natural gas ~~properties. The Company’s assets and operations are concentrated~~ in the ~~rural portions of~~Rocky Mountain region, primarily in the Wattenberg Field ~~in Colorado.~~of the DJ Basin.

Basis of Presentation

~~NOTE 2 - BASIS OF PRESENTATION~~

~~These~~The accompanying unaudited condensed consolidated financial statements include the accounts of the Company and have been prepared in accordance with ~~U.S.~~accounting principles generally accepted ~~accounting principles~~in the United States (“GAAP”) for interim financial ~~statements~~information, the instructions to Quarterly Report on Form 10-Q, and Regulation S-X. Accordingly, pursuant to ~~the~~such rules and regulations, ~~of the Securities~~certain notes and ~~Exchange Commission.~~other financial information included in audited financial statements have been condensed or omitted. In the opinion of management, ~~the accompanying unaudited condensed consolidated financial statements reflect~~ all adjustments, consisting of normal recurring adjustments asconsidered necessary for a fair presentation of ~~our financial position and results of operations.~~

~~The~~interim financial information, ~~as of~~have been included. All significant intercompany balances and transactions have been eliminated in consolidation.

The December 31, ~~2020,~~2021 unaudited condensed consolidated balance sheet data has been derived from the audited consolidated financial statements contained in our Annual Report on Form 10-K for the year ended December 31, ~~2020~~2021 (“~~2020~~ 2021 Form ~~10-K”~~10-K”), but does not include all disclosures, including notes required by GAAP. As such, this quarterly report should be read in conjunction with the audited consolidated financial statements and related notes included in our ~~2020~~2021 Form ~~10-K. The Company follows the same accounting principles for preparing quarterly and annual reports.~~10-K. In connection with the preparation of the unaudited condensed consolidated financial statements, the Company evaluated subsequent events after the balance sheet date of March 31, ~~2021,~~2022, through the filing date of this report.

~~Principles of Consolidation~~

The condensed consolidated balance sheets (“balance sheets”) include the accounts of the Company and its wholly owned subsidiaries, Bonanza Creek Energy Operating Company, LLC, Holmes Eastern Company, LLC, and Rocky Mountain Infrastructure, LLC. All intercompany accounts and transactions have been eliminated.

~~Use of Estimates~~

The preparation of the Company’s condensed consolidated financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of oil and gas reserves, assets and liabilities, and disclosure of contingent assets and liabilities at the date of the balance sheet and the reported amounts of revenue and expenses during the reporting period. Actual results could differ from those estimates. The results of operations for the three months ended March 31, ~~2021,~~2022 are not necessarily indicative of the results that may be expected for the full year ~~ending December 31, 2021. Further these estimates and~~or any other ~~factors, including those outside~~future period.

Significant Accounting Policies

The significant accounting policies followed by the Company are set forth in Note 1 - Summary of ~~the Company's control, such as the impact of lower commodity prices, may impact the Company's business, financial condition, results of operations and cash flows.~~

~~Industry Segment and Geographic Information~~

~~The Company operates in 1 industry segment, which is the development and production of oil, natural gas, and natural gas liquids (“NGLs”), and all of the Company's operations are conducted~~Significant Accounting Policies in the ~~continental United States.~~

~~Revenue Recognition~~

~~Sales of oil, natural gas,~~2021 Form 10-K and ~~NGLs~~ are ~~recognized when performance obligations are satisfied at~~supplemented by the ~~point control of the product is transferred~~notes to the customer. The Company's contracts' pricing provisions are tied to a market index, with certain adjustments based on, among other factors, whether a well delivers to a gathering or transmission line, quality of the oil or natural gas, and prevailing supply and demand conditions. As a result, the price of the oil, natural gas, and NGLs fluctuates to remain competitive with other available oil, natural gas, and NGLs supplies.

~~As further described in~~ ~~Note 6 - Commitments and Contingencies~~, one contract with NGL Crude Logistics, LLP (“NGL Crude”, known as the “NGL Crude agreement”) has an additional aspect of variable consideration related to the minimum volume commitments (“MVCs”) as specified in the agreement. On an on-going basis, the Company performs an analysis of expected risk adjusted production applicable to the NGL Crude agreement based on approved production plans to determine if liquidated damages to NGL Crude are probable. As of March 31, 2021, the Company believes that the volumes delivered to NGL Crude will be in excess of the MVCs required then and for the upcoming approved production plan. As a

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~~result of this analysis, to date, no variable consideration related to potential liquidated damages has been considered in the transaction price for the NGL Crude agreement.~~

Under the oil sales contracts, the Company sells oil production at the wellhead, or other contractually agreed-upon delivery points, and collects an agreed-upon index price, net of pricing differentials. In this scenario, the Company recognizes revenue when control transfers to the purchaser at the wellhead, or other contractually agreed-upon delivery point, at the net contracted price received.

Under the natural gas processing contracts, the Company delivers natural gas to an agreed-upon delivery point. The delivery points are specified within each contract, and the transfer of control varies between the inlet and outlet of the midstream processing facility. The midstream processing entity gathers and processes the natural gas and remits proceeds to the Company for the resulting sales of NGLs and residue gas. For the contracts where the Company maintains control through the outlet of the midstream processing facility, the Company recognizes revenue on a gross basis, with gathering, transportation, and processing fees presented as an expense in the Company's accompanyingunaudited condensed consolidated financial statements ~~of operations~~included in this report.

Recently Issued and comprehensive income (loss) (“statements of operations”). Alternatively, for those contracts where the Company relinquishes control at the inlet of the midstream processing facility, the Company recognizes natural gas and NGLs revenues based on the contracted amount of the proceeds received from the midstream processing entity and, as a result, the Company recognizes revenue on a net basis.

Under the product sales contracts, the Company invoices customers once the performance obligations have been satisfied, at which point payment is unconditional. Accordingly, the Company's product sales contracts do not give rise to contract assets or liabilities under this guidance. At March 31, 2021 and December 31, 2020, the Company's receivables from contracts with customers were $37.6 million and $32.7 million, respectively. Payment is generally received within 30 to 60 days after the date of production.

The Company records revenue in the month production is delivered to the purchaser. However, as stated above, settlement statements for certain natural gas and NGLs sales may not be received for 30 to 60 days after the date production is delivered, and as a result, the Company is required to estimate the amount of production delivered to the purchaser and the price that will be received for the sale of the product. The Company records the differences between its estimates and the actual amounts received for product sales in the month in which payment is received from the purchaser. For the period from January 1, 2021 through March 31, 2021, revenue recognized in the reporting period related to performance obligations satisfied in prior reporting periods was insignificant.

~~Revenue attributable to each identified revenue stream is disaggregated below (in thousands):~~

Three Months Ended March 31,
2021 2020
Operating Revenues:
   Crude oil sales $ 50,064 $ 51,146
   Natural gas sales 13,132 6,018
   Natural gas liquids sales 10,963 3,241
Oil and gas sales $ 74,159 $ 60,405

~~Restricted Cash~~

The following table provides a reconciliation of cash, cash equivalents, and restricted cash reported within the balance sheets, which sums to the total of such amounts shown in the accompanying condensed consolidated statements of cash flows (“statements of cash flows”) (in thousands):

As of March 31,
2021 2020
Cash and cash equivalents $ 38,695 $ 11,052
Restricted cash(1)
102 95
Total cash, cash equivalents, and restricted cash $ 38,797 $ 11,147

~~__________________________~~

~~(1) Included in other noncurrent assets and consists of funds for road maintenance and repairs.~~

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~~Unproved Property~~

Unproved oil and gas property costs are evaluated for impairment when there is an indication that the carrying costs may not be fully recoverable. During the three months ended March 31, 2021, the Company did 0t incur any abandonment and impairment of unproved properties compared to $30.1 million during the three months ended March 31, 2020 due to the reassessment of estimated probable and possible reserve locations based primarily upon economic viability.

Adopted Accounting ~~Pronouncements Recently Adopted and Issued~~Standards

In March 2020, the FASB issued Update No. 2020-04, Reference Rate Reform (Topic 848), which provides temporary optional guidance to companies impacted by the transition away from the LIBOR. The amendment provides certain expedients and exceptions to applying GAAP in order to lessen the potential accounting burden when contracts, hedging relationships, and other transactions that reference LIBOR as a benchmark rate are modified. Further, in January 2021, the FASB issued Update No. 2021-01, Reference Rate Reform (Topic 848), which clarifies the scope of Topic 848 so that derivatives affected by the discounting transition are explicitly eligible for certain optional expedients and exceptions in Topic 848. These amendments are effective upon issuance and expire on December 31, 2022. The Company is currently assessing the impact of the LIBOR transition on the Company's condensed consolidated financial statements.

There are no other accounting standards applicable to the Company that would have a material effect on the ~~Company's condensed consolidated~~Company’s financial statements and disclosures that have been issued but not yet adopted by the Company as of March 31, ~~2021,~~2022, and through the filing date of this report.

~~NOTE 3 - LEASES~~

The Company's right-of-use assets and lease liabilities are recognized at their discounted present value on the balance sheet, which include leases related to the asset classes reflected as of the dates indicated in the table below (in thousands):

March 31, 2021 December 31, 2020
Operating leases
Field equipment(1)
$ 26,350 $ 27,537
Corporate leases 1,201 1,481
Vehicles 357 468
Total right-of-use asset $ 27,908 $ 29,486
Field equipment(1)
$ 26,350 $ 27,537
Corporate leases 1,536 1,900
Vehicles 357 468
Total lease liability $ 28,243 $ 29,905
Finance leases
Right-of-use asset - field equipment(1)
$ 219 $ 219
Lease liability - field equipment(1)
$ 96 $ 117

~~__________________________~~

~~(1) Includes compressors, certain gas processing equipment, and other field equipment.~~

The lease amounts disclosed are presented on a gross basis. A portion of these costs may have been or will be billed to other working interest owners, and the Company's net share of these costs, once paid, are included in various line items on the statements of operations or capitalized to oil and gas properties or other property and equipment, as applicable.

The Company recognizes operating lease expense on a straight-line basis. Finance lease expense is recognized based on the effective interest method for the lease liability and straight-line amortization for the right-of-use asset, resulting in more cost being recognized in earlier lease periods. Short-term and variable lease payments are recognized as incurred. Short-term lease cost represents payments for leases with a lease term of one year or less, excluding leases with a term of one month or less. Short-term leases include drilling rigs and other equipment. Drilling rig contracts are structured based on an allotted number of wells to be drilled consecutively at a daily operating rate. Short-term drilling rig costs include a non-lease labor component, which is treated as a single lease component.

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NOTE 2 - ACQUISITIONS AND DIVESTITURES

All mergers and acquisitions disclosed were accounted for under the acquisition method of accounting for business combinations. Accordingly, we conducted assessments of the net assets acquired and recognized amounts for identifiable assets acquired and liabilities assumed at their estimated acquisition date fair values, while transaction and integration costs associated with the acquisition were expensed as incurred. The fair value measurements of assets acquired and liabilities assumed were based on inputs that are not observable in the market, and therefore represent Level 3 inputs. The fair values of crude oil and natural gas properties and asset retirement obligations were measured using valuation techniques that convert future cash flows to a single discounted amount. Significant inputs to the valuation of proved oil and natural gas properties include estimates of reserves, future operating and development costs, future commodity prices, estimated future cash flows, and a market-based weighted-average cost of capital. These inputs required significant judgments and estimates by management at the time of the valuation.

HighPoint Merger

On April 1, 2021, Civitas completed its previously announced acquisition of HighPoint Resources Corporation, a Delaware corporation (“HighPoint”), pursuant to the terms of HighPoint’s prepackaged plan of reorganization under Chapter 11 of the United States Bankruptcy Code (the “Prepackaged Plan”), which was confirmed by the U.S. Bankruptcy Court for the District of Delaware on March 18, 2021 pursuant to a confirmation order, and went effective on April 1, 2021 (the “HighPoint Merger”).

The ~~following table summarizes~~Prepackaged Plan implemented the ~~components~~merger and restructuring transactions in accordance with the Agreement and Plan of Merger, dated as of November 9, 2020 (the “HighPoint Merger Agreement”), by and among Civitas, HighPoint and Boron Merger Sub, Inc., a wholly-owned subsidiary of Civitas (“Merger Sub”). Pursuant to the Prepackaged Plan and the HighPoint Merger Agreement, at the effective time of the ~~Company's gross lease costs incurred during~~HighPoint Merger (the “HighPoint Effective Time”) and the ~~three months ended March 31, 2021~~effective date under the Prepackaged Plan, Merger Sub merged with and ~~2020 (in thousands):~~

Three Months Ended March 31,
2021 2020
Operating lease cost(1)
$ 3,337 $ 3,491
Finance lease cost:
Amortization of right-of-use assets 3 2
Interest on lease liabilities 1 1
Short-term lease cost 47 1,590
Variable lease cost(2)
(30) 91
Sublease income(3)
(92) (89)
Total lease cost $ 3,266 $ 5,086

~~____________________________~~

~~(1) Includes office rent expense~~into HighPoint, with HighPoint continuing as the surviving corporation and wholly-owned subsidiary of ~~$0.3 million for~~Civitas. At the HighPoint Effective Time, each eligible share of common stock, par value $0.001 per share, of HighPoint (“HighPoint Common Stock”) issued and outstanding immediately prior to the HighPoint Effective Time was automatically converted into the right to receive 0.11464 shares of common stock, par value $0.01 per share, of Civitas (“Civitas Common Stock”), with cash paid in lieu of the ~~three months ended March 31, 2021 and 2020.~~

(2) Variable lease cost represents differences between lease obligations and actual costs incurred for certain leases that do not have fixed payments related to both lease and non-lease components. Such incremental costs include lease payment increases or decreases driven by market price fluctuations and leased asset maintenance costs.

~~(3) The Company has subleased a portion~~issuance of ~~its office space for the remainder of the office lease term.~~

~~The Company does not have~~ any ~~leases with an implicit interest rate that can be readily determined.~~fractional shares. As a result, Civitas issued 487,952 shares of Civitas Common Stock to former HighPoint stockholders.

Concurrently with the ~~Company used~~HighPoint Merger and pursuant to the ~~incremental borrowing rate, based on~~Prepackaged Plan, and in exchange for the ~~Credit Facility benchmark rate, adjusted for facility utilization~~$625.0 million in aggregate principal amount outstanding of 7.0% Senior Notes due 2022 of HighPoint Operating Corporation (“HighPoint OpCo”) and ~~lease term,~~8.75% Senior Notes due 2025 of HighPoint OpCo (collectively, the “HighPoint Senior Notes”), Civitas issued to ~~calculate the respective discount rates.~~all holders of HighPoint Senior Notes an aggregate of (i) 9,314,214 shares of Civitas Common Stock and (ii) $100.0 million aggregate principal amount of 7.5% Senior Notes due 2026 (“7.5% Senior Notes”). Please refer to Note 5 - Long-term Debt for ~~additional information.~~further discussion of the 7.5% Senior Notes.

Immediately after the HighPoint Effective Time, in connection with the HighPoint Merger, Civitas entered into the Second Amendment, dated April 1, 2021, to the Credit Facility. Please refer to Note 5 - Long-Term Debt for further discussion.

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The ~~Company has certain lease agreements that provide for~~following tables present the ~~option to extend,~~HighPoint Merger consideration and purchase ~~or terminate early, which was evaluated on each lease to arrive at~~price allocation of the ~~proper lease term. There were some leases for which~~assets acquired and the ~~option to extend or purchase was factored into~~liabilities assumed in the resulting lease term. There were no leases where early termination was factored into the resulting lease term. The Company's weighted-average remaining lease terms and discount rates for operating leases as of March 31, 2021 are as follows:HighPoint Merger:


Merger Consideration (in thousands, except per share amount)
Shares of Civitas Common Stock issued to existing holders of HighPoint Common Stock(1)	~~Operating Leases~~488
~~Weighted-average lease term (years)~~Shares of Civitas Common Stock issued to existing holders of HighPoint Senior Notes	~~2.6~~9,314
~~Weighted-average discount rate~~Total additional shares of Civitas Common Stock issued as merger consideration	~~3.81%~~9,802

Closing price per share of Civitas Common Stock(2)	$	38.25

Merger consideration paid in shares of Civitas Common Stock	$	374,933
Aggregate principal amount of the 7.5% Senior Notes	100,000
Total merger consideration	$	474,933

~~Supplemental cash flow information~~_________________________

(1) Based on the number of shares of HighPoint Common Stock issued and outstanding as of April 1, 2021 and the conversion ratio of 0.11464 per share of Civitas Common Stock.

(2) Based on the closing stock price of Civitas Common Stock on April 1, 2021.


Purchase Price Allocation (in thousands)
Assets Acquired
Cash and cash equivalents	$	49,827
Accounts receivable - oil and natural gas sales	26,343
Accounts receivable - joint interest and other	9,161
Prepaid expenses and other	3,608
Inventory of oilfield equipment	4,688
Proved properties	539,820
Other property and equipment, net of accumulated depreciation	2,769
Right-of-use assets	4,010
Deferred income tax assets	110,513
Other noncurrent assets	797
Total assets acquired	$	751,536

Liabilities Assumed
Accounts payable and accrued expenses	$	51,088
Oil and natural gas revenue distribution payable	20,786
Lease liability	4,010
Derivative liability	18,500
Current portion of long-term debt	154,000
Ad valorem taxes	3,746
Asset retirement obligations	24,473
Total liabilities assumed	276,603
Net assets acquired	$	474,933

The valuation of proved oil and natural gas properties for the HighPoint Merger applied a market-based weighted-average cost of capital rate of approximately 13%.

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Extraction Merger

On November 1, 2021, Civitas completed its merger with Extraction Oil & Gas, Inc., a Delaware corporation (“Extraction”), pursuant to the terms of the related Agreement and Plan of Merger (the “Extraction Merger Agreement”) (the “Extraction Merger”).Pursuant to the Extraction Merger Agreement, at the effective time of the Extraction Merger of November 1, 2021 (the “Extraction Merger Effective Time”), (i) Raptor Eagle Merger Sub merged with and into Extraction, with Extraction continuing its existence as the surviving corporation as a wholly owned subsidiary of Civitas following the Extraction Merger (the “Extraction Surviving Corporation”), (ii) each share of common stock, par value $0.01 per share, of Extraction (the “Extraction Common Stock”) issued and outstanding as of immediately prior to the Extraction Merger Effective Time was converted into the right to receive 1.1711 shares of Civitas Common Stock for each share of Extraction Common Stock (the “Extraction Exchange Ratio”).

Additionally, pursuant to the Extraction Merger Agreement, at the Extraction Merger Effective Time, each award of restricted stock units (including those subject to performance-based vesting conditions) issued pursuant to Extraction’s 2021 Long Term Incentive Plan (the “Extraction Equity Plan”) that was outstanding immediately prior to the Extraction Merger Effective Time and that by its terms did not settle by reason of the occurrence of the closing of the Extraction Merger (each, an “Extraction RSU Award”) was assumed by Civitas and converted into a number of restricted stock units with respect to shares of Civitas Common Stock (such restricted stock unit, a “Converted RSU”) equal to the product of the number of Extraction Common Stock subject to the Extraction RSU Award immediately prior to the Extraction Merger Effective Time multiplied by the Extraction Exchange Ratio, effective as of the Extraction Merger Effective Time.

As of the Extraction Merger Effective Time, each Converted RSU continued to be governed by the same terms and conditions that were applicable to the corresponding Extraction RSU Award immediately prior to the Extraction Merger Effective Time. In addition, Converted RSUs subject to performance-based vesting conditions held by certain Extraction executives provide that, in the event such individual’s employment is terminated for death, disability, by Civitas for any reason other individual for good reason, in each case, on or within twelve months following the Extraction Merger Effective Time, the portion of such individual’s Converted RSUs subject to performance-based vesting conditions shall, effective as of such individual’s termination date, immediately vest in full based on deemed achievement of any applicable performance goals at the maximum level of performance. Further, effective as of immediately prior to the Extraction Merger Effective Time, each award of deferred stock units granted under the Extraction Equity Plan and held by a member of the Extraction board who was not a designee of Extraction for appointment to Civitas’ board of directors ("Board") as of the Extraction Merger Effective Time immediately vested in full.

Additionally, at the Extraction Merger Effective Time, in accordance with the terms of (i) the Extraction Tranche A warrants to purchase Extraction Common Stock, issued pursuant to that certain Warrant Agreement by and between Extraction and American Stock Transfer & Trust Company, LLC, as warrant agent (“AST”), dated as of January 20, 2021 (the “Tranche A Warrants”), and (ii) the Extraction Tranche B warrants to purchase Extraction Common Stock, issued pursuant to that certain Warrant Agreement by and between Extraction and AST, as warrant agent, dated as of January 20, 2021 (the “Tranche B Warrants,” and, together with the Tranche A Warrants, the “Extraction Warrants”), that were issued and outstanding immediately prior to the Extraction Merger Effective Time, were cancelled and Civitas executed a replacement warrant agreement for the Tranche A Warrants and a replacement warrant agreement for the Tranche B Warrants (each, a "Replacement Warrant Agreement") and issued to each holder of the Extraction Warrants a replacement warrant (each, a “Replacement Warrant”) that is exercisable for a number of shares of Civitas Common Stock equal to the number of shares of Civitas Common Stock that would have been issued or paid to a holder of the number of shares of Extraction Common Stock into which such Extraction Warrant was exercisable immediately prior to the Extraction Merger Effective Time. Each Replacement Warrant has an exercise price as set forth in the applicable Replacement Warrant Agreement, subject to adjustment as set forth therein.

The Replacement Warrants may be exercised, in whole or in part, at any time or from time to time on or before 5:00 p.m., New York time, on (i) January 20, 2025, in the case of the Replacement Warrants for the Tranche A Warrants, or (ii) January 20, 2026, in the case of the Replacement Warrants for the Tranche B Warrants. The number of shares of Civitas Common Stock for which a Replacement Warrant is exercisable, and the exercise price of such Replacement Warrant, are subject to customary adjustments from time to time upon the occurrence of certain events, including the payment of in-kind dividends or distributions, splits, subdivisions or combinations of shares of Civitas Common Stock. A holder of a Replacement Warrant, in its capacity as such, is not entitled to any rights whatsoever as a stockholder of Civitas, except to the extent expressly provided in the applicable Replacement Warrant Agreement. 3.4 million Tranche A Replacement Warrants and 1.7 million Tranche B Replacement Warrants were issued.

The following tables present the merger consideration and preliminary purchase price allocation of the assets acquired and the liabilities assumed in the Extraction Merger:

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Merger Consideration (in thousands, except per share amount)
Shares of Civitas Common Stock issued as merger consideration(1)	31,095
Closing price per share of Civitas Common Stock(2)	$	56.10
Merger consideration paid in shares of Civitas Common Stock	$	1,744,431

Unvested restricted stock compensation expense as merger consideration	$	19,338
Unvested performance restricted stock compensation expense allocated as merger consideration	2,897
Total merger consideration	$	22,235

Tranche A Warrants issued as merger consideration	$	52,164
Tranche B Warrants issued as merger consideration	25,299
Total warrant merger consideration	$	77,463

Total merger consideration	$	1,844,129

_________________________

(1) Based on the number of shares of Extraction Common Stock issued and outstanding as of November 1, 2021 and the conversion ratio of 1.1711 per share of Civitas Common Stock.

(2) Based on the closing stock price of Civitas Common Stock on November 1, 2021.


Preliminary Purchase Price Allocation (in thousands)
Assets Acquired
Cash and cash equivalents	$	106,360
Accounts receivable - oil and natural gas sales	119,585
Accounts receivable - joint interest and other	33,054
Prepaid expenses and other	3,044
Inventory of oilfield equipment	9,291
Derivative assets	5,834
Proved properties	1,876,014
Unproved properties	193,400
Other property and equipment, net of accumulated depreciation	40,068
Right-of-use assets	6,883
Deferred income tax assets	49,194
Other noncurrent assets	4,248
Total assets acquired	$	2,446,975

Liabilities Assumed
Accounts payable and accrued expenses	$	90,353
Production taxes payable	63,572
Oil and natural gas revenue distribution payable	170,002
Income tax payable	14,000
Lease liability	6,883
Derivative liability	100,474
Ad valorem taxes	87,071
Asset retirement obligations	68,741
Other noncurrent liabilities	1,750
Total liabilities assumed	602,846
Net assets acquired	$	1,844,129

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The valuation of proved oil and natural gas properties for the Extraction Merger applied a market-based weighted-average cost of capital rate of approximately 10%.

The purchase price allocation is preliminary, and Civitas is continuing to assess the fair values of certain of the Extraction assets acquired and liabilities assumed. In particular, assets and liabilities subject to potential adjustment, in amounts that could be material to the pro forma financial statements, include, but are not limited to, proved properties, unproved properties, and accounts payable and accrued expenses related to ~~leases~~our continued assessment over the application of lease contracts and related deductions. We cannot reasonably estimate the impact of such conclusions as there is still a high level of uncertainty regarding the underlying terms and application.

Crestone Peak Merger

On November 1, 2021, Civitas completed its acquisition of CPPIB Crestone Peak Resources America Inc., a Delaware corporation (“Crestone Peak”), pursuant to the terms of the related Agreement and Plan of Merger (the “Crestone Merger Agreement”) (the “Crestone Peak Merger”). Pursuant to the Crestone Merger Agreement, at the effective time of the Crestone Peak Merger of November 1, 2021, (i) Merger Sub 1 merged with and into Crestone Peak (the “Merger Sub 1 Merger”), with Crestone Peak continuing its existence as the surviving corporation as a wholly owned subsidiary of Civitas following the Merger Sub 1 Merger (the “Crestone Surviving Corporation”), and (ii) subsequently, the Crestone Surviving Corporation merged with and into Merger Sub 2 (the “Merger Sub 2 Merger” and together with the Merger Sub 1 Merger, the “Crestone Peak Merger”), with Merger Sub 2 continuing its existence as the surviving entity as a wholly owned subsidiary of Civitas (the “Crestone Surviving Entity”).

Pursuant to the Crestone Merger Agreement, at the effective time of the Merger Sub 1 Merger (the “Merger Sub 1 Merger Effective Time”), the shares of Crestone Peak common stock, par value $0.01 per share (“Crestone Peak Common Stock”) (excluding shares of Crestone Peak Common Stock held by Crestone Peak as treasury shares or by Civitas or Merger Sub 1 immediately prior to the Merger Sub 1 Merger Effective Time), issued and outstanding as of immediately prior to the Merger Sub 1 Merger Effective Time were converted into the right to collectively receive 22.5 million shares of Civitas Common Stock (the “Crestone Peak Merger Consideration”). In addition, at the effective time of the Merger Sub 2 Merger (the “Merger Sub 2 Merger Effective Time”), each share of common stock of the Crestone Surviving Corporation issued and outstanding as of immediately prior to the Merger Sub 2 Merger Effective Time was automatically cancelled and each unit of Merger Sub 2 issued and outstanding immediately prior to the Merger Sub 2 Merger Effective Time remained issued and outstanding and represents the only outstanding units of the Crestone Surviving Entity immediately following the Merger Sub 2 Merger.

The following tables present the Crestone Peak Merger Consideration and preliminary purchase price allocation of the assets acquired and the liabilities assumed in the Crestone Peak Merger:


Merger Consideration (in thousands, except per share amount)
Shares of Civitas Common Stock issued as merger consideration	22,500
Closing price per share of Civitas Common Stock(1)	$	56.10
Merger consideration paid in shares of Civitas Common Stock	$	1,262,250

_________________________

(1) Based on the closing stock price of Civitas Common Stock on November 1, 2021.

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Preliminary Purchase Price Allocation (in thousands)
Assets Acquired
Cash and cash equivalents	$	67,505
Accounts receivable - oil and natural gas sales	81,340
Accounts receivable - joint interest and other	9,917
Prepaid expenses and other	2,929
Inventory of oilfield equipment	11,951
Proved properties	1,797,814
Unproved properties	453,321
Other property and equipment, net of accumulated depreciation	7,980
Right-of-use assets	7,934
Total assets acquired	$	2,440,691

Liabilities Assumed
Accounts payable and accrued expenses	$	134,791
Production taxes payable	52,435
Oil and natural gas revenue distribution payable	83,950
Lease liability	7,934
Derivative liability	338,383
Credit facility	280,000
Ad valorem taxes	66,913
Deferred income tax liabilities	125,086
Asset retirement obligations	88,949
Total liabilities assumed	1,178,441
Net assets acquired	$	1,262,250

The valuation of proved oil and natural gas properties for the Crestone Peak Merger applied a market-based weighted-average cost of capital rate of approximately 10%.

The purchase price allocation is preliminary, and Civitas is continuing to assess the fair values of certain of the Crestone Peak assets acquired and liabilities assumed. In particular, assets and liabilities subject to potential adjustment, in amounts that could be material to the pro forma financial statements, include, but are not limited to, proved properties, unproved properties, and accounts payable and accrued expenses related to our continued assessment over the application of lease contracts and related deductions. We cannot reasonably estimate the impact of such conclusions as there is still a high level of uncertainty regarding the underlying terms and application.

Revenue and earnings of the acquiree

There were no revenue and earnings included in our statement of operations during the three months ended March 31, 2021 related to the HighPoint, Extraction, and Crestone Peak Mergers as all mergers were completed after the three months ended March 31, 2021.

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Supplemental pro forma financial information

The following unaudited pro forma financial information (in thousands, except per share amounts) represents a summary of the condensed consolidated results of operations for the three months ended March 31, 2021, assuming the HighPoint, Extraction, and ~~2020 consisted~~Crestone Peak mergers had been completed as of January 1, 2020. The pro forma financial information includes certain non-recurring pro forma adjustments that were directly attributable to the business combinations. The pro forma financial information is not necessarily indicative of the ~~following~~results of operations that would have been achieved if the mergers had been effective as of this date, or of future results.


	Three Months Ended March 31, 2021
	As reported		HighPoint(1)		Extraction(2)		Crestone Peak(2)		Civitas Pro Forma Combined
Total revenue	$	74,159	$	72,019	$	292,484	$	126,654	$	565,316
Net income (loss)	(119)		(46,434)		983,201		(78,552)		858,096
Net income (loss) per common share - basic	$	(0.01)							$	10.19
Net income (loss) per common share - diluted	$	(0.01)							$	10.14
_________________________
(1) Based on a closing date of April 1, 2021.
(2) Based on a closing date of November 1, 2021.

Bison Acquisition

On March 1, 2022, the Company completed the acquisition of privately held DJ Basin operator Bison Oil & Gas II, LLC (“Bison”) for merger consideration of approximately $279.7 million (the “Bison Acquisition”). Net assets acquired under the preliminary purchase price allocation were $294.2 million and consequently resulted in a bargain purchase gain of $14.5 million. Because of the immateriality of the Bison Acquisition, the related revenue and earnings, supplemental pro forma financial information, and detailed purchase price allocation are not disclosed.

Merger transaction costs

Merger transaction costs of $20.5 million and $3.3 million related to the aforementioned mergers and acquisitions were accounted for separately from the assets acquired and liabilities assumed and are included in merger transaction costs in the accompanying unaudited condensed consolidated statements of operations and comprehensive income (“statements of operations”) for the three months ended March 31, 2022 and 2021, respectively. Merger transaction costs include $7.6 million and zero of severance payments for the three months ended March 31, 2022 and 2021, respectively.

NOTE 3 - REVENUE RECOGNITION

Oil, natural gas, and natural gas liquid (“NGL”) sales revenue presented within the accompanying statements of operations is reflective of the revenue generated from contracts with customers. Revenue attributable to each identified revenue stream is disaggregated below (in thousands):

Three Months Ended March 31,
2021 2020
Cash paid for amounts included in the measurement of lease liabilities:
Operating cash flows from operating leases $ 3,150 $ 3,133
Operating cash flows from finance leases 1 1
Financing cash flows from finance leases 21 10
Right-of-use assets obtained in exchange for new operating lease obligations $ 1,489 $ 5,444
Right-of-use assets obtained in exchange for new finance lease obligations 0 219


	Three Months Ended March 31,
	2022		2021
Operating net revenues:
Oil sales	$	549,502	$	50,064
Natural gas sales	113,161		13,132
NGL sales	155,147		10,963
Oil, natural gas, and NGL sales	$	817,810	$	74,159

817

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AsThe Company recognizes revenue from the sale of produced oil, natural gas, and NGL at the point in time when control of produced oil, natural gas, or NGL volumes transfer to the purchaser, which may differ depending on the applicable contractual terms. The Company considers the transfer of control to have occurred when the purchaser has the ability to direct the use of, and obtain substantially all of the remaining benefits from, the oil, natural gas, or NGL production. Transfer of control dictates the presentation of gathering, transportation, and processing expenses within the accompanying statements of operations. Gathering, transportation, and processing expenses incurred by the Company prior to the transfer of control are recorded gross within the gathering, transportation, and processing line item on the accompanying statements of operations. Conversely, gathering, transportation, and processing expenses incurred by the Company subsequent to the transfer of control are recorded net within the oil, natural gas, and NGL sales line item on the accompanying statements of operations. Please refer to Note 1 - Summary of Significant Accounting Policies in the 2021 Form 10-K for more information regarding the types of contracts under which oil, gas, and NGL sales revenue is generated.

The Company records revenue in the month production is delivered and control is transferred to the purchaser. However, settlement statements and payment may not be received for 30 to 60 days after the date production is delivered and control is transferred. Until such time settlement statements and payment are received, the Company records a revenue accrual based on, amongst other factors, an estimate of the volumes delivered at estimated prices as determined by the applicable contractual terms. The Company records the differences between its estimates and the actual amounts received for product sales in the month in which payment is received from the purchaser. For the three months ended March 31, 2022, revenue recognized in the reporting period related to performance obligations satisfied in prior reporting periods was insignificant. At March 31, 2022 and December 31, 2021, ~~future commitments by year for~~ the Company's ~~operating~~receivables from contracts with customers were $410.4 million and finance leases with a lease term of one year or more are presented in the table below. Such commitments are reflected at undiscounted values and are reconciled to the discounted present value recognized on the balance sheet as follows (in thousands):

Operating Leases
Finance Leases(1)
Remainder of 2021 $ 10,151 $ 96
2022 10,448 0
2023 6,430 0
2024 2,471 0
2025 139 0
Thereafter 5 0
Total lease payments 29,644 96
Less: imputed interest (1,401) 0
Total lease liability $ 28,243 $ 96

~~____________________________~~

~~(1) Represents the Company's exercise of the 1-year equipment purchase option in the second quarter of 2021.~~

$362.3 million, respectively.

NOTE 4- ACCOUNTS PAYABLE AND ACCRUED EXPENSES

Accounts payable and accrued expenses contain the following as of the dates indicated (in thousands):


	March 31, 2022		December 31, 2021
Accounts payable trade	$	29,425	$	19,623
Accrued drilling and completion costs	101,415		129,430
Accrued lease operating expense and gathering, transportation, and processing	53,597		19,077
Accrued general and administrative expense	12,873		21,163
Accrued merger transaction costs	3,206		1,475
Accrued oil and NGL hedging	65,418		26,601
Accrued interest expense	13,516		6,303
Accrued settlement	15,541		20,791
Other accrued expenses	1,442		1,725
Total accounts payable and accrued expenses	$	296,433	$	246,188

NOTE 5 - LONG-TERM DEBT

5.0% Senior Notes

On October 13, 2021, the Company issued $400.0 million aggregate principal amount of 5.0% Senior Notes due 2026 (the “5.0% Senior Notes”) pursuant to an indenture (the “5.0% Indenture”), among Civitas Resources, Wells Fargo Bank, National Association, as trustee, and the guarantors party thereto. The Company used the net proceeds and cash on hand to repay all borrowings under the Credit Facility (as defined below), all borrowings outstanding under the Crestone Peak credit facility, and for general corporate purposes. Interest accrues at the rate of 5.0% per annum and is payable semiannually in arrears on April 15 and October 15 of each year, which payments commenced on April 15, 2022.

The 5.0% Indenture contains covenants that limit, among other things, the Company’s ability to: (i) incur or guarantee additional indebtedness; (ii) create liens securing indebtedness; (iii) pay dividends on or redeem or repurchase stock or subordinated debt; (iv) make specified types of investments and acquisitions; (v) enter into or permit to exist contractual limits on the ability of the Company’s subsidiaries to pay dividends to Civitas Resources; (vi) enter into transactions with affiliates; and (vii) sell assets or merge with other companies. These covenants are subject to a number of important limitations and exceptions. The Company was in compliance with all covenants under the 5.0% Indenture as of March 31, 2022, and through the filing of this report. In addition, certain of these covenants will be terminated before the 5.0% Senior Notes mature if at any time no default or event of default exists under the 5.0% Indenture and the 5.0% Senior Notes receive an investment-grade rating from at least 2 ratings agencies. The 5.0% Indenture also contains customary events of default.

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At any time prior to October 15, 2023, the Company may redeem the 5.0% Senior Notes, in whole or in part, at a redemption price equal to the sum of (i) the principal amount thereof, plus (ii) the “make-whole” premium at the redemption date, plus (iii) accrued and unpaid interest, if any. On or after October 15, 2023, the Company may redeem all or part of the 5.0% Senior Notes at redemption prices (expressed as percentages of the principal amount redeemed) equal to (i) 102.5% for the twelve-month period beginning on October 15, 2023; (ii) 101.25% for the twelve-month period beginning on October 15, 2024; and (iii) 100.0% for the twelve-month period beginning October 15, 2025 and at any time thereafter, plus accrued and unpaid interest, if any.

The Company may redeem up to 35% of the aggregate principal amount of the 5.0% Senior Notes at any time prior to October 15, 2023 with an amount not to exceed the net cash proceeds from certain equity offerings at a redemption price equal to 105.0% of the principal amount of the 5.0% Senior Notes redeemed, plus accrued and unpaid interest, if any, provided, however, that (i) at least 65.0% of the aggregate principal amount of the 5.0% Senior Notes originally issued on the issue date (but excluding 5.0% Senior Notes held by the Company) remains outstanding immediately after the occurrence of such redemption (unless all such 5.0% Senior Notes are redeemed substantially concurrently) and (ii) the redemption occurs within 180 days after the date of the closing of such equity offering.

The 5.0% Senior Notes are fully and unconditionally guaranteed on a senior unsecured basis by all of Civitas' existing subsidiaries.

7.5% Senior Notes

In conjunction with the HighPoint Merger, the Company issued $100.0 million aggregate principal amount of 7.5% Senior Notes due 2026 (the “7.5% Senior Notes”) pursuant to an indenture, dated April 1, 2021 (the “7.5% Indenture”), by and among Civitas Resources, U.S. Bank National Association , as trustee, and the guarantors party thereto. Interest accrues at the rate of 7.5% per annum is payable semiannually in arrears on April 30 and October 31 of each year.

The 7.5% Indenture contains covenants that limit, among other things, the Company’s ability to: (i) incur additional indebtedness and issue preferred stock; (ii) pay dividends or make other distributions in respect of the Company's common stock; (iii) make other restricted payments and investments; (iv) create liens; (v) restrict distributions or other payments from Civitas' restricted subsidiaries; (vi) sell assets, including capital stock of restricted subsidiaries; (vii) merge or consolidate with other entities; and (viii) enter into transactions with affiliates. These covenants are subject to a number of important limitations and exceptions. The Company was in compliance with all covenants under the 7.5% Indenture as of March 31, 2022, and through the filing of this report. In addition, certain of these covenants will be suspended before the 7.5% Senior Notes mature if at any time no default or event of default exists under the 7.5% Indenture and the 7.5% Senior Notes receive an investment grade rating from at least 2 ratings agencies. The 7.5% Indenture also contains customary events of default.

The 7.5% Senior Notes are redeemable at the Company’s option (an “Optional Redemption”), in whole or in part, prior to April 30, 2022 at a redemption price equal to 107.5% of the aggregate principal to be redeemed, plus unpaid accrued interest, if any, through the Optional Redemption date. On or after April 30, 2022, the Optional Redemption price will be equal to 100.0% of the aggregate principal amount of the 7.5% Senior Notes to be redeemed, plus accrued and unpaid interest, if any, through the Optional Redemption date.

The 7.5% Senior Notes are fully and unconditionally guaranteed on a senior unsecured basis by all of Civitas' existing subsidiaries.

On May 1, 2022 (the “Redemption Date”), the Company exercised its Optional Redemption of all of the issued and outstanding 7.5% Senior Notes. The 7.5% Senior Notes were redeemed at 100.0% of their aggregate principal amount, plus accrued and unpaid interest thereon to the Redemption Date.

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The 7.5% Senior Notes and 5.0% Senior Notes are recorded net of unamortized deferred financing costs within the Senior notes line item on the accompanying balance sheets. There were no discounts or premiums associated with the either issuance. The tables below present the related carrying values as of March 31, 2022 and December 31, 2021 (in thousands):

As of March 31, 2021 As of December 31, 2020
Accrued drilling and completion costs $ 4,824 $ 453
Accounts payable trade 14,006 1,931
Accrued general and administrative expense 3,306 7,529
Accrued lease operating expense 1,936 1,793
Accrued interest expense 329 322
Accrued oil and gas hedging 2,036 0
Accrued production and ad valorem taxes and other 13,170 25,397
Total accounts payable and accrued expenses $ 39,607 $ 37,425


	As of March 31, 2022
	Principal Amount		Unamortized Deferred Financing Costs		Net Amount
7.5% Senior Notes	$	100,000	$	—	$	100,000
5.0% Senior Notes	$	400,000	$	7,877	$	392,123

~~NOTE 5- LONG-TERM DEBT~~


	As of December 31, 2021
	Principal Amount		Unamortized Deferred Financing Costs		Net Amount
7.5% Senior Notes	$	100,000	$	—	$	100,000
5.0% Senior Notes	$	400,000	$	8,290	$	391,710

Credit Facility

In December 2018, the Company entered into a reserve-based revolving facility, as the borrower, with JPMorgan Chase Bank, N.A. (“JPMorgan”), as the administrative agent, and a syndicate of financial institutions (the “Lender Syndicate”), as lenders, ~~(the~~that mature on December 7, 2023 (with all subsequent amendments as defined below, the “Credit Facility”). The $750.0 million Credit Facility has a maturity date of December 7, 2023. The redeterminations in June 2020 and December 2020, resulted in a borrowing base of $260.0 million. The next redetermination is set to occur in May 2021.

The Credit Facility contains customary representations and affirmative covenants. The Credit Facility also contains customary negative covenants, which, among other things, and subject to certain exceptions, include restrictions on (i) liens, (ii) indebtedness, guarantees and other obligations, (iii) restrictions in agreements on liens and distributions, (iv) mergers or consolidations, (v) asset sales, (vi) restricted payments, (vii) investments, (viii) affiliate transactions, (ix) change of business, (x) foreign operations or subsidiaries, (xi) name changes, (xii) use of proceeds, letters of credit, (xiii) gas imbalances, (xiv) hedging transactions, (xv) additional subsidiaries, (xvi) changes in fiscal year or fiscal quarter, (xvii) operating leases, (xviii) prepayments of certain debt and other obligations, (xix) sales or discounts of receivables, (xx) dividend payment thresholds, and (xi) cash balances. In addition, the Company is ~~guaranteed by all wholly owned subsidiaries~~subject to certain financial covenants under the Credit Facility, as tested on the last day of each fiscal quarter, including, without limitation, (a) a maximum ratio of the Company's consolidated indebtedness (subject to certain exclusions) to earnings before interest, income taxes, depreciation, depletion, and amortization, exploration expense, and other non-cash charges and (b) a current ratio, as defined in the agreement, inclusive of the unused commitments then available to be borrowed, to not be less than 1.00 to 1. The Company ~~(each, a “Guarantor”~~was in compliance with all covenants under the Credit Facility as of March 31, 2022, and ~~together with~~through the ~~Company, the “Credit Parties”), and is secured by first priority security interests on substantially all assets~~filing of ~~each Credit Party, subject to customary exceptions.~~this report.

Under the terms of the Credit Facility, as amended in June 2020 (the “First Amendment”), borrowings ~~bear~~bore interest at a per annum rate equal to, at the option of the Company, either (i) a LIBOR, subject to a 0% LIBOR floor plus a margin of 2.00% to 3.00%, based on the utilization of the Credit Facility (the “Eurodollar Rate”) or (ii) a fluctuating interest rate per annum equal to the greatest of (a) the rate of interest publicly announced by JPMorgan ~~Chase Bank, N.A.~~ as its prime rate, (b) the rate of interest published by the Federal Reserve Bank of New York as the federal funds effective rate, (c) the rate of interest published by the Federal Reserve Bank of New York as the overnight bank funding rate, or (d) a LIBOR offered rate for a one-month interest period, subject to a 0% LIBOR floor plus a margin of 1.00% to 2.00%, based on the utilization of the Credit Facility (the “Reference Rate”). Interest on borrowings that bear interest at the Eurodollar Rate shall be payable on the last day of the applicable interest period selected by the Company, which shall be one, two, three, or six months, and interest on borrowings that bear interest at the Reference Rate shall be payable quarterly in arrears.

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The First Amendment Credit Facility contains customary representations and affirmative covenants. The Credit Facility also contains customary negative covenants, which, among other things, and subject to certain exceptions, include restrictions on (i) liens, (ii) indebtedness, guarantees and other obligations, (iii) restrictions in agreements on liens and distributions, (iv) mergers or consolidations, (v) asset sales, (vi) restricted payments, (vii) investments, (viii) affiliate transactions, (ix) change of business, (x) foreign operations or subsidiaries, (xi) name changes, (xii) use of proceeds, letters of credit, (xiii) gas imbalances, (xiv) hedging transactions, (xv) additional subsidiaries, (xvi) changes in fiscal year or fiscal quarter, (xvii) operating leases, (xviii) prepayments of certain debt and other obligations, (xix) sales or discounts of receivables, (xx) dividend payments, and (xi) cash balances. The Credit Parties are subject to certain financial covenants under the Credit Facility, as tested on the last day of each fiscal quarter, including, without limitation, (i) a maximum ratio of the Company's consolidated indebtedness (subject to certain exclusions) to earnings before interest, income taxes, depreciation, depletion, and amortization, exploration expense, and other non-cash charges (“EBITDAX”) of 3.50 to 1.00 and (ii) a current ratio, as defined in the agreement, inclusive of the unused Commitments then available to be borrowed, to not be less than 1.00 to 1.00. The Company was in compliance with all covenants as of March 31, 2021, and through the filing date of this report.

On April 1, 2021, in conjunction with the HighPoint ~~Acquisition,~~Merger, the Company ~~together with certain of its subsidiaries,~~ entered into the Second Amendment to the Credit Facility (the “Second Amendment”) to, among other things: (i) increase the aggregate maximum commitment amount from $750.0 million to $1.0 billion; (ii) increase the available borrowing base from $260.0 million to $500.0 million; (iii) increase the Eurodollar Rate margin to 3.00% to 4.00%; (iv) increase the Reference Rate margin to 2.00% to 3.00%; (v) increase (A) the LIBOR floor from 0% to .50% and (B) the alternate base rate floor from 0% to 1.50%; (vi) decrease for any fiscal quarter ending on or after April 1, 2021, the maximum permitted net leverage ratio from 3.50 to 3.0; and (viii) amend certain other covenants and provisions.

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On November 1, 2021, the Company, JPMorgan, and the Lender Syndicate entered into an Amended and Restated Credit Agreement (the “Amended and Restated Credit Agreement”), having an aggregate maximum commitment amount of $2.0 billion. The Amended and Restated Credit Agreement, among other things: (i) increased the aggregate elected commitments to from $400.0 million to $800.0 million, (ii) increased the available borrowing base from $500.0 million to $1.0 billion, (iii) extended the maturity date of the Amended and Restated Credit Agreement to November 1, 2025 and (iv) amended the borrowing base adjustment provisions such that, between borrowing base determinations, downward adjustments related to the incurrence of certain permitted indebtedness will only occur if either (A) such indebtedness exceeds $500.0 million and the Company’s pro-forma leverage ratio is less than or equal to 1.50 to 1, or (B) the Company's pro-forma leverage ratio is greater than 1.50 to 1.

Under the Amended and Restated Credit Agreement, the Credit Facility ~~(as amended, restated, supplemented or otherwise modified). Please refer~~is guaranteed by all restricted domestic subsidiaries of the Company, and is secured by first priority security interests on substantially all assets, including a mortgage on at least 90% of the total value of the proved oil and natural gas properties evaluated in the most recently delivered reserve reports prior to ~~Note 13 - Subsequent Events~~ ~~for additional information~~the amendment effective date, including any engineering reports relating to the oil and natural gas properties of the Extraction Surviving Corporation, the Crestone Surviving Entity, their respective subsidiaries, of each of the Company, all restricted domestic subsidiaries of the Company, the Extraction Surviving Corporation and the Crestone Surviving Entity, in each case, subject to customary exceptions.

AsOn December 21, 2021, the Company, JPMorgan, and the Lender Syndicate, entered into a First Amendment to Amended and Restated Credit Agreement. Pursuant to the First Amendment to Amended and Restated Credit Agreement, the parties agreed that the minimum hedging covenant with respect to projected oil and gas production will not apply if the Company’s leverage ratio is less than 1.00 to 1 as of ~~both March 31, 2021~~the applicable quarterly test date, until the next such test date.

On April 20, 2022, the Company, JPMorgan, and the Lender Syndicate, entered into a Second Amendment to the Amended and Restated Credit Agreement. Pursuant to the Second Amendment to the Amended and Restated Credit Agreement, and as part of the regularly scheduled, semi-annual borrowing base redetermination, the Company's borrowing base was increased from $1.0 billion to $1.7 billion, and the aggregate elected commitment amount was increased from $800.0 million to 1.0 billion. The borrowing base increase was primarily driven by the increased value of the Company’s estimated proved reserves at December 31, ~~2020, the Company had 0 outstanding on the Credit Facility. As of the~~2021. The next scheduled borrowing base redetermination date ~~of this filing,~~is set to occur in October 2022.

The following table presents the outstanding balance, ~~was $129.0 million. The Company's~~total amount of letters of credit outstanding, and available borrowing capacity under the Credit Facility ~~approximates fair value~~ as of the ~~applicable interest rates are floating.~~dates indicated (in thousands):


	May 4, 2022		March 31, 2022		December 31, 2021
Revolving credit facility	$	—	$	—	$	—
Letters of credit	12,393		12,393		21,656
Available borrowing capacity	987,607		787,607		778,344
Total aggregate elected commitments	$	1,000,000	$	800,000	$	800,000

In connection with the Second Amendment and the Amended and Restated Credit Agreement, the Company capitalized a total of ~~both March 31, 2021~~approximately $3.9 million and ~~December 31, 2020,~~$6.8 million, respectively, in deferred financing costs. Of the ~~balances of~~ total post-amortization net capitalized ~~deferred financing costs of~~amounts, (i) ~~$0.7~~$6.9 million and $7.5 million are presented within the other noncurrent assets line item on the accompanying balance sheets as of March 31, 2022 and December 31, 2021, respectively, and (ii) ~~$0.4~~$2.7 million ~~are~~is presented within the prepaid expenses and other line ~~items in~~item on the accompanying balance ~~sheets. These balances did not change between the disclosed periods due to capitalized deferred financing cost additions offset by amortization.~~sheets at both March 31, 2022 and December 31, 2021.

Interest Expense

For the three months ended March 31, ~~2021~~2022 and ~~2020,~~2021, the Company incurred interest expense of $9.1 million and $0.4 million, ~~and $1.2 million,~~ respectively. ~~NaN~~No interest was capitalized during the three months ended March 31, 2022 and 2021. ~~The Company capitalized $1.0 million~~

Table of ~~interest expense during the three months ended March 31, 2020.~~Contents

NOTE6- COMMITMENTS AND CONTINGENCIES

Legal Proceedings

From time to time, the Company is involved in various commercial and regulatory claims, litigation, and other legal proceedings that arise in the ordinary course of its business. The Company assesses these claims in an effort to determine the degree of probability and range of possible loss for potential accrual in its ~~condensed~~ consolidated financial statements. In accordance with authoritative accounting guidance, an accrual is recorded for a loss contingency when its occurrence is probable and damages can be reasonably estimated based on the most likely anticipated outcome or the minimum amount within a range of possible outcomes. Because legal proceedings are inherently unpredictable and unfavorable resolutions could occur, assessing contingencies is highly subjective and requires judgments about uncertain future events. When evaluating contingencies, the Company may be unable to provide a meaningful estimate due to a number of factors, including the procedural status of the matter in question, the presence of complex or novel legal theories, and/or the ongoing discovery and development of information important to the matters. The Company regularly reviews contingencies to determine the adequacy of its accruals and related disclosures. ~~NaN~~No claims have been made, nor is the Company aware of any material uninsured liability which the Company may have, as it relates to any environmental cleanup, restoration, or the violation of any rules or regulations.

Upon closing of the HighPoint, Extraction, and Crestone Peak Mergers, the Company assumed all obligations, whether asserted or unasserted, of HighPoint, Extraction, and Crestone Peak. As of the filing date of this report, there were no probable, material pending, or overtly threatened legal actions against the Company of which it was ~~aware.~~aware, other than the following:

Boulder County. As of the date of this filing, there is ongoing litigation between Boulder County and Extraction which has been previously disclosed as having the potential to prevent oil and gas operations for the development minerals contained within Boulder County, Colorado. As noted below, this matter remains pending, but the substantive issues have been fully addressed by the appellate court in the Company’s favor and the Company is awaiting a dismissal from the trial court.

Boulder County initiated suit in District Court for Boulder County, Colorado in case no. 2018CV030925. The action was primarily a contract case, where the relevant contracts are the conservation easement (“CE”) over the Blue Paintbrush location, Extraction’s Surface Use Agreement (“SUA”) for the Blue Paintbrush location, and the leases that Boulder owns within the Blue Paintbrush drilling and spacing unit. Boulder sought invalidation of these leases in the litigation.

Boulder argued that the lease underlying the CE only authorize the extraction of minerals underneath the CE property. Boulder took issue with the planned 32 wells for the location and argued that only the number of wells necessary to extract the minerals underlying the CE property should be allowed. Boulder also argued that Extraction induced a breach of the CE by contracting with the CE property owner for the SUA. Boulder argued that the terms of the SUA violate the CE because the SUA allows for development in excess of that allowed under the underlying lease. Boulder’s argument was based on its assertion that the lease underlying the CE property only allows for the extraction of minerals underneath the CE property.

Boulder’s remaining claims asserted that Extraction breached the terms of leases Boulder owns in the drilling and spacing unit by establishing the Blue Paintbrush drilling and spacing unit. Specifically, Boulder’s leases within the Blue Paintbrush drilling and spacing unit have a clause that states that a unit must be the “minimum size tract on which a well may be drilled under the laws, rules, or regulations in force at the time of such pooling or unitization.” Boulder argued that no drilling and spacing unit including acreage covered by these leases can be greater than 80 acres because Colorado Oil and Gas Conservation Commission ("COGCC") Order 407 established 80-acre drilling and spacing units for the Codell and COGCC Order 407-87 established 80-acre drilling and spacing unit for the Niobrara.

On September 25, 2018, Extraction prevailed before the district court on all issues. The district court’s order was appealed, was fully briefed on appeal, and was argued before the Colorado Court of Appeals on December 14, 2021 - Board of County Commissioners of Boulder County v. 8 North and Extraction Oil & Gas, Case No. 2019CA001896 (Colorado Court of Appeals). On March 3, 2022, the Colorado Court of Appeals issued a unanimous opinion rejecting Boulder County's claims. Under the Colorado Rules of Appellate Procedure, Boulder County had forty-two days to petition the Colorado Supreme Court for certiorari. This date passed, and on April 25, 2022, the Court of Appeals issued a mandate affirming the judgment of the District Court of Boulder County. There are no outstanding issues for consideration by the trial court, and the Company is authorized to rely upon the Colorado Court of Appeals mandate.

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Enforcement. Disclosure of certain environmental matters is required when a governmental authority is a party to the proceedings and the proceedings involve potential monetary sanctions that the Company believes could exceed $0.3 million. The Company has received Notices of Alleged Violations (“NOAV”) from the COGCC alleging violations of various Colorado statutes and COGCC regulations governing oil and gas operations. The Company has further received notices from the Colorado Air Pollution Control Division. The Company continues to engage in discussions regarding resolution of the alleged violations. As of March 31, 2022 and December 31, 2021, the Company has accrued approximately $1.0 million associated with the NOAVs and Colorado Air Pollution Control Division notices, as they are probable and reasonably estimable.

Commitments

Firm Transportation Agreements. The Company is party to 1 firm pipeline transportation contract to provide a guaranteed outlet for production on an oil pipeline system. The contract requires the Company to pay minimum volume transportation charges on 8,500 gross barrels per day through April 2022 and 12,500 barrels per day thereafter through April 2025, regardless of the amount of pipeline capacity utilized by the Company. The aggregate financial commitment fee over the remaining term was $44.7 million as of March 31, 2022. The Company expects to utilize most, if not all, of the firm capacity on the oil pipeline system.

Minimum Volume Agreement - Oil. The Company is party to a purchase agreement to deliver fixed and determinable quantities of crude ~~oil to NGL Crude. The NGL Crude~~oil. This agreement includes defined volume commitments over a term ending in 2023. Under the terms of the ~~NGL Crude~~ agreement, the Company is required to make periodic deficiency payments for any shortfalls in delivering minimum gross volume commitments, which are set in six-month periods. The minimum gross volume commitment will increase approximately 3% each year for the remainder of the contract, to a maximum of approximately 16,000 gross barrels per day. The aggregate financial commitment fee over the remaining term ~~was $44.9~~is $31.7 million as of March 31, ~~2021.~~2022. Upon notifying ~~NGL Crude~~the purchaser at least twelve months prior to the expiration date of the ~~NGL Crude~~ agreement, the Company may elect to extend the term of the ~~NGL Crude~~ agreement for up to three additional years. Since the commencement of the agreement and through the remainder of its term, the Company has not and does not expect to incur any deficiency payments.

Minimum Volume Agreement - Gas and Other. The Company is party to a long-term gas gathering and processing agreement (the “Gathering Agreement”) with a third-party midstream provider over a term ending in 2029 with an annual minimum volume commitment of 13.0 billion cubic feet of natural gas (“Bcf”). The Gathering Agreement also includes a commitment to sell take-in-kind NGLs from other processing agreements of 7,500 barrels a day through year seven of the Gathering Agreement with the ability to roll forward up to a 10% shortfall in a given month to the subsequent month. The aggregate financial commitment fee over the remaining term is $145.5 million as of March 31, 2022. The Company has not and does not expect to incur any deficiency payments.

Additionally, the Company is also party to a gas gathering and processing agreement with several third-party producers and a third-party midstream provider to deliver to 2 different plants over terms that end in August 2025 and July 2026. The Company’s share of these commitments requires an incremental 51.5 and 20.6 MMcf per day, respectively, over a baseline volume of 65 MMcf per day for a period of seven years following the in-service dates of the plants. The Company may be required to pay a shortfall fee for any incremental volume deficiencies under these commitments. These contractual obligations can be reduced by the Company’s proportionate share of the collective volumes delivered to the plants by other incremental third-party volumes available to the midstream provider that are in excess of the total commitments. Because of the third-party producer reduction provision, we believe that the aggregate financial commitment fee over the remaining term is zero as of March 31, 2022. The Company has not and does not expect to incur any deficiency payments.

The Company is also party to 2 additional agreements that require the Company to pay a fee associated with the minimum volumes regardless of the amount delivered. The aggregate financial commitment fee over the remaining term for these contracts was $12.5 million as of March 31, 2022.

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The ~~annual~~ minimum ~~commitment~~annual payments under the ~~NGL Crude agreement~~these agreements for the next five years as of March 31, ~~2021~~2022 are presented below (in thousands):


	Firm Transportation		Minimum Volume(1)
Remainder of 2022	$	10,616	$	42,589
2023	14,600		32,241
2024	14,640		22,298
2025	4,800		20,400
2026	—		19,553
2027 and thereafter	—		52,716
Total	$	44,656	$	189,797

NGL Crude Commitments(1)
Remainder of 2021 $ 17,571
2022 23,097
2023 4,202
2024 0
2025 0
2026 and thereafter 0
Total $ 44,870
___________________________

~~____________________________~~

(1)The above calculation is based on the minimum volume commitment schedule (as defined in the ~~NGL Crude~~relevant agreement) and applicable differential fees.

Other commitments.

~~Since~~ The Company is party to a drilling commitment agreement with a third-party midstream provider such that the ~~commencement~~Company is required to drill a total of 106 horizontal wells, whereby a minimum number of wells out of the ~~NGL Crude~~total must be drilled by a deadline occurring every two years over a period ending December 31, 2026. The drilling commitment agreement provides for, among other things, a number of specifications such as minimum consecutive days of production, well performance, and ~~through~~lateral length. Wells operated by others can satisfy this commitment, subject to limitations. If the ~~remainder of~~Company were to fail to complete the ~~term~~wells by the applicable deadline, it would be in breach of the agreement and the third-party midstream provider could attempt to assert damages against Civitas and its affiliates. As of the date of filing, the Company ~~has not and does not expect to incur~~cannot reasonably estimate how much, if any, ~~deficiency payments.~~damages will be paid.

~~There have been no other material changes from the commitments disclosed in the notes to the Company's consolidated financial statements included in our 2020 Form 10-K.~~ Refer to Note 313 - Leases, for lease commitments.

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NOTE 7 - STOCK-BASED COMPENSATION

Long Term Incentive Plans

In April 2017, the Company adopted the 2017 Long Term Incentive Plan

In (“2017 ~~the Company adopted a Long Term Incentive Plan (the “LTIP”~~LTIP”), ~~as established by the Board,~~ which ~~allows~~provides for the issuance of restricted stock units, ~~(“RSUs”),~~ performance stock units, ~~(“PSUs”),~~ and stock options, and reserved 2,467,430 shares of common stock. ~~See below for further discussion~~In June 2021, the Company adopted the 2021 Long Term Incentive Plan (“2021 LTIP”), which reserved an incremental 700,000 shares of common stock to those previously reserved under the 2017 LTIP. Finally, pursuant to the Extraction Merger Agreement, Civitas assumed the Extraction Equity Plan, which reserved 3,305,080 shares of common stock now issuable by Civitas. The 2017 LTIP, 2021 LTIP, and Extraction Equity Plan are collectively referred to herein as the “LTIP”.

In November 2021, the Company adopted a non-employee director compensation program (the “Director Compensation Program”), which provides that non-employee directors will receive grants of deferred stock units (“DSUs”). In connection with the adoption of the Director Compensation Program, the Company adopted a First Amendment to the 2021 LTIP that, among other things, allows the Company to determine whether dividend rights granted pursuant to the LTIP should be reinvested, paid currently or paid in accordance with the terms of an associated award.

The Company records compensation expense associated with the issuance of awards ~~granted~~ under the ~~LTIP.~~LTIP based on the fair value of the awards as of the date of grant within general and administrative expense. The following table outlines the compensation expense recorded by type of award (in thousands):


	Three Months Ended March 31,
	2022		2021
Restricted and deferred stock units	$	5,265	$	1,321
Performance stock units	2,825		291

Total stock-based compensation	$	8,090	$	1,612

~~The Company recorded~~As of March 31, 2022, unrecognized compensation expense related to the awards granted under the LTIP ~~as follows (in thousands):~~

Three Months Ended March 31,
2021 2020
Restricted stock units $ 1,321 $ 1,301
Performance stock units 291 (193)
Stock options 0 131
Total stock-based compensation $ 1,612 $ 1,239

~~As of March 31, 2021, unrecognized compensation expense~~ will be amortized through the relevant periods as follows (in thousands):

Unrecognized Compensation Expense Final Year of Recognition
Restricted stock units $ 6,469 2023
Performance stock units 1,489 2022
$ 7,958

~~Table of~~ ~~Contents~~


	Unrecognized Compensation Expense		Final Year of Recognition
Restricted and deferred stock units	$	21,532	2025
Performance stock units	15,685		2024
Total unrecognized stock-based compensation	$	37,217

Restricted Stock Units (“RSUs”) and Deferred Stock Units

The ~~LTIP allows for the issuance of~~Company typically grants RSUs to ~~members of the Board of Directors (the “Board”)~~officers, directors, and employees and DSUs to directors as part of ~~the Company at the discretion of the Board.~~ its LTIP.Each RSU and DSU represents a right to receive 1 share of the Company's common stock ~~to be released from restriction~~ upon ~~completion~~settlement of the award at the end of the specified vesting period. ~~The awards typically~~

RSUs generally vest and settle either over a (i) one-year vesting period, with the entire grant vesting and settling on the anniversary date or (ii) three-year vesting period, with one-third of the total grant vesting and settling on each anniversary date. DSUs generally vest in ~~one-third increments~~quarterly installments over ~~three years. The RSUs are valued at~~a one-year period following the grant ~~date share price~~date.DSUs are settled in shares of the Company's common stock upon the director’s separation of service from the Board. The Company records compensation expense associated with the issuance of RSUs and ~~are recognized as general and administrative expense~~DSUs on a straight-line basis over the vesting period based on the fair value of the ~~award.~~awards as of the date of grant within general and administrative expense. The fair value of RSUs and DSUs is equal to the closing price of the Company’s common stock on the date of the grant.

~~During the three months ended March 31, 2021, the Company granted 146 RSUs with a nominal fair value.~~

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A summary of the status and activity of non-vested ~~restricted stock units~~RSUs and DSUs for the three months ended March 31, ~~2021~~2022 is presented below:


	RSUs and DSUs	Weighted-Average Grant-Date Fair Value
Non-vested, beginning of year	815,062	$	42.18
Granted	388,937	45.92
Vested	(444,556)	48.25
Forfeited	(9,745)	40.71
Non-vested, end of year	749,698	$	40.54

Restricted Stock Units Weighted-Average Grant-Date Fair Value
Non-vested, beginning of year 550,056 $ 20.30
Granted 146 35.73
Vested (109) 35.73
Forfeited (109) 27.42
Non-vested, end of quarter 549,984 $ 20.30

Cash flows resulting from excess tax benefits are to be classified as part of cash flows from operating activities. Excess tax benefits are realized tax benefits from tax deductions for vested restricted stock in excessThe fair value of the ~~deferred tax asset attributable to stock compensation costs for such restricted stock. The Company recorded no excess tax benefits for~~RSUs and DSUs granted under the ~~periods presented.~~LTIP during the three months ended March 31, 2022 was $17.9 million.

Performance Stock Units (“PSUs”)

The ~~LTIP allows for the issuance of~~Company grants PSUs to ~~employees at the sole discretion~~officers as part of ~~the Board.~~its LTIP. The number of shares of the ~~Company's~~Company’s common stock ~~that may be~~ issued to settle PSUs ranges from 0zero to 2 times the number of PSUs ~~awarded. The PSUs vest in their entirety at the end of the~~granted and is determined based on performance achievement against certain criteria over a three-year performance period. ~~The total number~~PSUs generally vest and settle on the third anniversary of ~~PSUs granted~~the date of the grant.

Performance achievement is ~~split between two performance~~determined based on 1 to 2 criteria. The first criterion is based on either, or a ~~comparison~~combination of, the ~~Company's~~Company’s absolute and relative total shareholder return (“TSR”) ~~for~~over the performance period. Absolute TSR is determined based upon the performance of the Company's common stock over the performance period relative to the price of the Company's common stock at the grant date. For awards with a relative TSR component, the Company's absolute TSR is compared with the absolute TSRs of a group of peer companies ~~for~~over the ~~same~~ performance period. The absolute TSR for the Company and each of the peer companies is determined by dividing (A) (i) the volume-weighted average share price for the last 30 trading days of the performance period, minus (ii) the volume-weighted average share price for the 30 trading days preceding the beginning of the performance period, plus (iii) dividends paid by (B) the volume-weighted average share price for the 30 trading days preceding the beginning of the performance period. The second criterion, if applicable, is based on the Company's annual return on average capital employed (“ROCE”) for each year during the three-year performance period.

The total number of PSUs granted under the LTIP was split ~~between the two performance criteria was even~~as follows for the ~~PSUs granted in 2019, whereas~~relevant grant years:


	2022		2021		2020
TSR	100	%	100	%	67	%
ROCE	—	%	—	%	33	%

As the ~~split was two-thirds weighted to the TSR criterion and one-third weighted to the ROCE criterion for the~~2020 PSUs ~~granted in 2020. Compensation expense associated with PSUs is recognized as general and administrative expense over the performance period. Because these awards~~ depend on a ~~combination of~~ performance-based ~~and market-based~~ settlement ~~criteria,~~criterion, compensation expense may be adjusted in future periods as the number of units expected to vest increases or decreases based on the ~~Company's~~Company’s expected ROCE performance. ~~As of March 31, 2021,~~

Of the ~~Company does not expect any of the ROCE portion of the PSUs granted in 2019 to vest and has accordingly adjusted the related compensation expense.~~

~~The~~grant-date fair value, of the ~~PSUs was measured at the grant date. The~~ portion of the PSUs tied to ~~the~~ TSR performance required a stochastic process method using a Brownian Motion simulation. A stochastic process is a mathematically defined equation that can create a series of outcomes over time. These outcomes are not deterministic in nature, which means that by iterating the equations multiple times, different results will be obtained for those iterations. In the case of the ~~Company's TSRs,~~PSUs tied to TSR performance, the Company could not predict with certainty the path its stock price or the stock prices of its peers would take over the performance period. By using a stochastic simulation, the Company created multiple prospective stock pathways, statistically analyzed these simulations, and ultimately made inferences regarding the most likely path the stock price would take. As such, because future stock prices are stochastic, or probabilistic with some direction in nature, the stochastic method, specifically the Brownian Motion Model, was deemed an appropriate method by which to determine the fair value of the portion of the PSUs tied to ~~the TSR.~~TSR performance. Significant assumptions used in this simulation include the ~~Company's~~Company’s expected volatility, risk-free interest rate based on U.S. Treasury yield curve rates with maturities consistent with the performance period, as well as the volatilities for each of the ~~Company's~~Company’s peers.

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NaN PSUs were granted during the three months ended March 31, 2021. The PSUs granted in 2018 expired as of December 31, 2020, with zero distribution of shares to the recipients, as neither the TSR nor the ROCE performance criteria were met. A summary of the status and activity of ~~performance stock units~~non-vested PSUs for the three months ended March 31, ~~2021~~2022 is presented below:

Performance Stock Units(1)
Weighted-Average Grant-Date Fair Value
Non-vested, beginning of year 185,588 $ 22.63
Granted 0 0
Vested 0 0
Forfeited 0 0
Non-vested, end of quarter 185,588 $ 22.63


	PSUs (1)	Weighted-Average Grant-Date Fair Value
Non-vested, beginning of year	319,367	$	57.58
Granted	129,676	56.43
Vested	(91,523)	32.49

Expired	(41,955)	22.77
Non-vested, end of year	315,565	$	69.01

___________________________

(1)The number of awards assumes that the associated performance condition is met at the target ~~amount.~~amount (multiplier of 1). The final number of shares of the ~~Company's~~Company’s common stock issued may vary depending on the performance multiplier, which ranges from 0zero to 2, depending on the level of satisfaction of the performance condition.

The fair value of the PSUs granted under the LTIP during the three months ended March 31, 2022 was $7.3 million.

The PSUs tied to TSR performance granted in 2019 vested as of December 31, 2021 and were released during the three months ended March 31, 2022 with a 200% distribution of shares to the recipients. The PSUs tied to ROCE performance granted in 2019 expired, with zero distribution of shares to the recipients.

Stock Options

The LTIP allows for the issuance of stock options to the Company's employees at the sole discretion of the Board. Options expire ten years from the grant date unless otherwise determined by the Board. Compensation expense on the stock options is recognized as general and administrative expense over the vesting period of the award.

~~There were 0~~Stock options are valued using a Black-Scholes Model where expected volatility is based on an average historical volatility of a peer group selected by management over a period consistent with the expected life assumption on the grant date, the risk-free rate of return is based on the U.S. Treasury constant maturity yield on the grant date with a remaining term equal to the expected term of the awards, and the Company’s expected life of stock ~~options granted during~~option awards is derived from the ~~three months ended March 31, 2021.~~ midpoint of the average vesting time and contractual term of the awards.

A summary of the status and activity of non-vested stock options for the three months ended March 31, ~~2021~~2022 is presented below:


	Stock Options	Weighted- Average Exercise Price		Weighted-Average Remaining Contractual Term (in years)	Aggregate Intrinsic Value (in thousands)
Outstanding, beginning of year	25,549	$	34.36

Exercised	(5,294)	34.36
Forfeited	(111)	34.36
Outstanding, end of year	20,144	$	34.36	5.1	$	511
Options outstanding and exercisable	20,144	$	34.36	5.1	$	511

Stock Options Weighted-Average Exercise Price Weighted-Average Remaining Contractual Term (in years) Aggregate Intrinsic Value (in thousands)
Outstanding, beginning of year 72,368 $ 34.36 0 0
Granted 0 0
Exercised (429) 34.36
Forfeited (222) 34.36
Outstanding, end of quarter 71,717 $ 34.36 6.1 $ 98
Number of options outstanding and exercisable 71,717 $ 34.36 6.1 $ 98

The aggregate intrinsic value of options exercised during the three months ended March 31, 2022 was $0.1 million.

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NOTE8 - FAIR VALUE MEASUREMENTS

The Company follows authoritative accounting guidance for measuring the fair value ~~measurement authoritative guidance, which defines fair value, establishes a framework for using fair value to measure~~of assets and liabilities ~~and expands disclosures about fair value measurements. The authoritative accounting~~in its financial statements. This guidance 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. ~~The statement~~Further, this guidance establishes a hierarchy for inputs used in measuring fair value that maximizes the use of observable inputs and minimizes the use of unobservable inputs by requiring that the most observable inputs be used when available.

The fair value hierarchy is broken down into three levels based on the reliability of the inputs as follows:

Level 1: Quoted prices ~~are available~~ in active markets for identical assets or liabilities

Level 2: Quoted prices in active markets for similar assets and liabilities, quoted prices for identical or similar instruments in markets that are not active, and model-derived valuations whose inputs are observable or whose significant value drivers are observable

Level 3: Significant inputs to the valuation model are unobservable

Financial and non-financial assets and liabilities are ~~to be~~ classified based on the lowest level of input that is significant to the fair value measurement. The Company’s assessment of the significance of a particular input to the fair value measurement requires judgment and may affect the valuation of the fair value of assets and liabilities and their placement within the fair value ~~hierarchy levels.~~hierarchy.

Derivatives

~~Fair~~The Company uses Level 2 inputs to measure the fair value of ~~all derivative instruments are~~oil, gas, and NGL commodity price derivatives. The fair value of the Company's commodity price derivatives is estimated ~~with~~using industry-standard models that ~~consider~~contemplate various ~~assumptions,~~inputs including, ~~quoted~~but not limited to, the contractual price of the underlying position, current market prices, forward ~~prices for commodities,~~commodity price curves, volatility factors, time value of money, ~~volatility factors,~~ and ~~current market~~the credit risk of both the Company and ~~contractual prices~~its counterparties. We validate our fair value estimate by corroborating the original source of inputs, monitoring changes in valuation methods and assumptions, and reviewing counterparty mark-to-market statements and other supporting documentation. Refer to Note 9 - Derivatives for more information regarding the ~~underlying instruments, as well as other relevant economic measures. All valuations were compared against counterparty statements to verify the reasonableness of the estimate. The~~ Company’s commodity swaps, collars, and puts were validated by observable transactions for the same or similar commodity options using the NYMEX futures index and were designated as Level 2 within the valuation hierarchy. derivative instruments.

The following tables present the ~~Company's~~Company’s financial assets and liabilities that were accounted for at fair value on a recurring basis as of March 31, 2022 and December 31, 2021 and their classification within the fair value hierarchy (in thousands):


	As of March 31, 2022
	Level 1		Level 2		Level 3
Derivative assets	$	—	$	—	$	—
Derivative liabilities	$	—	$	430,805	$	—

As of March 31, 2021
Level 1 Level 2 Level 3
Derivative assets $ 0 $ 92 $ 0
Derivative liabilities $ 0 $ 19,970 $ 0


	As of December 31, 2021
	Level 1		Level 2		Level 3
Derivative assets	$	—	$	3,393	$	—
Derivative liabilities	$	—	$	239,763	$	—

Long-Term Debt

The 7.5% Senior Notes and 5.0% Senior Notes are recorded at cost, net of any unamortized deferred financing costs. As of March 31, 2022, the fair values for the 7.5% Senior Notes and 5.0% Senior Notes were $100.3 million and $396.4 million, respectively. These fair values are based on quoted market prices, and as such, are designated as Level 1 within the fair value hierarchy. The recorded value of the Credit Facility approximates its fair value as it bears interest at a floating rate that approximates a current market rate. Please refer to

As of December 31, 2020
Level 1 Level 2 Level 3
Derivative assets $ 0 $ 7,482 $ 0
Derivative liabilities $ 0 $ 7,732 $ 0
Note 5 - Long-Term Debt for additional information.

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~~Proved Oil~~Warrants

As discussed in Note 2 - Acquisitions and ~~Gas~~Divestitures, the Company issued warrants in connection with the Extraction Merger. The warrants issued are indexed to the Company’s common stock and are required to be net share settled via a cashless exercise. The Company evaluated the warrants under authoritative accounting guidance and determined that they should be classified as equity instruments. The Company's share price traded below the exercise price of the replacement warrants and therefore were not exercisable during the three months ended March 31, 2022.

The fair value of the warrants on the issuance date was determined using Level 3 inputs including, but not limited to, volatility, risk-free rate, and dividend yield under the Cox-Ross-Rubinstein binomial option pricing model. The warrants were included as a component of merger consideration and are recorded within additional paid-in capital on the accompanying balance sheets at a fair value of $77.5 million, with no recurring fair value measurement required. There have been no changes to the initial carrying amount of the warrants since issuance.

Acquisitions and Impairments of Proved Properties

We utilize the acquisition method to account for acquisitions of businesses. Pursuant to this method, we allocate the cost of the acquisition, or purchase price, to assets acquired and liabilities assumed based on fair values as of the acquisition date. Proved ~~oil~~ and ~~gas property costs~~unproved properties are ~~evaluated for impairment~~valued based on a ~~nonrecurring basis~~discounted cash flow approach utilizing Level 3 inputs, including, amongst other things, reserve quantities and ~~reduced to~~classification, pace of drilling plans, future commodity prices, future development and lease operating costs, and discount rates using a market-based weighted average cost of capital determined at the time of the acquisition. When estimating the fair value ~~when there is an indication~~of unproved properties, additional risk-weighting adjustments are applied to probable and possible reserves. Net derivative liabilities assumed are valued based on Level 2 inputs similar to the Company's other commodity price derivatives.

Whenever events or circumstances indicate that the carrying ~~costs exceed the sum~~value of ~~the undiscounted cash flows of the underlying oil and gas reserves. Depending on the availability of data,~~proved properties may not be recoverable, the Company uses Level 3 inputs ~~and either the income valuation technique, which converts future amounts to a single present value amount~~ to measure ~~the~~and record impairment at fair value of proved properties through an application of risk-adjusted discount rates and price forecasts selected by the Company’s management, or the market valuation approach. The calculation of the risk-adjusted discount rate is a significant management estimate based on the best information available. Management believes that the risk-adjusted discount rate is representative of current market conditions and reflects the following factors: estimates of future cash payments, expectations of possible variations in the amount and/or timing of cash flows, the risk premium, and nonperformance risk. The price forecast is based on the Company's internal budgeting model derived from the NYMEX strip pricing, adjusted for management estimates and basis differentials. Future operating costs are also adjusted as deemed appropriate for these estimates. Proved properties classified as held for sale are valued using a market approach, based on an estimated selling price, as evidenced by the most current bid prices received from third parties. If a relevant estimated selling price is not available, the Company utilizes the income valuation technique discussed above.value. There were 0no proved oil and gas property impairments during the three months ended March 31, ~~2021~~2022 and ~~2020.~~2021.

Impairments of Unproved Properties

~~NOTE~~9~~- ASSET RETIREMENT OBLIGATIONS~~

~~The Company recognizes an~~Unproved properties are routinely evaluated for continued capitalization or impairment. On a quarterly basis, management assesses undeveloped leasehold costs for impairment by considering, among other things, remaining lease terms, future drilling plans and capital availability to execute such plans, commodity price outlooks, recent operational results, reservoir performance and geology, and estimated ~~liability for future costs to abandon its oil and gas properties. The fair~~acreage value of the asset retirement obligation is recorded as a liability when incurred, which is typically at the time the asset is acquired or placed in service. There is a corresponding increase to the carrying value of the asset, which is included in the proved properties line item in the accompanying balance sheets. The Company depletes the amount added to proved properties and recognizes expense in connection with accretion of the discounted liability over the remaining estimated economic lives of the properties.

~~The Company’s estimated asset retirement obligation liability is~~ based on ~~historical experience in abandoning wells, estimated economic lives, estimated costs to abandon~~prices received for similar, recent acreage transactions by the ~~wells,~~Company or other market participants. During the three months ended March 31, 2022 and ~~regulatory requirements. The liability is discounted using~~2021, the ~~credit-adjusted risk-free rate estimated at the time the liability is incurred.~~

~~A roll-forward~~Company incurred abandonment and impairment of ~~the Company's asset retirement obligation is as follows (in thousands):~~


	~~Amount~~
~~Beginning balance as of December 31, 2020~~	$	~~28,699~~
~~Liabilities settled~~	~~(406)~~
~~Additions~~	~~127~~
~~Accretion expense~~	~~244~~

~~Ending balance as of March 31, 2021~~	$	~~28,664~~

unproved properties expense of $18.0 million and zero, respectively.

NOTE 109 - DERIVATIVES

The Company periodically enters into commodity derivative contracts to mitigate a portion of its exposure to potentially adverse market changes in commodity prices for its expected future oil, natural gas, and NGL production and the associated impact on cash flows. ~~All~~The Company's commodity derivative contracts consist of swap and collar arrangements as well as roll differential swaps. As of March 31, 2022, all derivative counterparties were members of the Credit Facility lender group and all commodity derivative contracts are entered into for other-than-trading purposes. The ~~Company’s derivatives include swaps, collars, and puts for oil and natural gas, and 0ne of the~~Company does not designate its commodity derivative ~~instruments qualify~~contracts as ~~having~~ hedging ~~relationships.~~instruments.

In a typical ~~commodity fixed-price~~ swap ~~agreement,~~arrangement, if the agreed upon published third-party index price (“index price”) is lower than the ~~swap strike~~fixed contract price at the time of settlement, the Company receives the difference between the index price and the ~~agreed upon swap strike~~fixed contract price. If the index price is higher than the ~~swap strike~~fixed contact price at the time of settlement, the Company pays the difference. A swaption allows the counterparty, on a specific date, to extend an existing fixed-price swap for a certain period of time or to increase the notional volumes of an existing fixed-price swap.

~~A basis swap arrangement guarantees a price differential from a specified delivery point to an agreed upon reference point. An oil roll swap arrangement fixes the price differential~~difference between the ~~NYMEX WTI financial calendar month average settlement~~index price and the ~~physical crude calendar month average~~fixed contract price.

A typical collar arrangement effectively establishes a floor and ceiling price on contracted volumes through the use of a short call and a long put (“~~oil roll swaps”~~two-way collar”). ~~For both basis~~When the index price is above the ceiling price at the time of settlement, the Company pays the difference between the index price and ~~oil roll swap arrangements,~~the ceiling price. When the index price is below the floor price at the time of settlement, the Company receives the difference between the index price ~~differential~~ and floor price. When the ~~stated terms, if the~~index price ~~differential~~ is ~~greater than the stated terms. The Company pays the difference~~ between the floor price ~~differential and the stated terms, if the stated terms are greater than the price differential.~~

~~Table of~~ ~~Contents~~

~~A cashless collar arrangement establishes a floor~~ and ceiling price, ~~on future oil and gas production. When~~no payment or receipt occurs. A minority of our collar arrangements combine a two-way collar with a short put that holds an exercise price below the ~~settlement~~floor price ~~is above~~(“three-way collar”). In these arrangements, when the ~~ceiling price, the Company pays the difference between the settlement price and the ceiling price. When the settlement~~index price is below the floor price at the time of settlement, the Company receives the difference between the ~~settlement~~index price ~~and floor price. In the event that the settlement price is between the ceiling~~ and the floor ~~no payment or receipt occurs.~~

~~A put gives the owner the right to sell the underlying commodity~~price, capped at a set price over the term of the contract. If the index settlement price is higher than the put fixed price, the put will expire worthless. If the settlement price is lower than the put fixed price, the Company will exercise the put and receive the difference between the ~~settlement~~floor price and the ~~put fixed price.~~exercise price of the short put.

~~As of March 31, 2021,~~The Company has also entered into crude oil swap contracts to fix the differential in pricing between the NYMEX calendar month average and the physical crude oil delivery month (“Roll Differential”) in which the Company ~~had entered into~~pays the ~~following commodity derivative contracts:~~

~~Table of~~ ~~Contents~~

As of the filing date of this report, the Company had entered into the following commodity derivative contracts, including the commodity derivative contracts novated in conjunction with the HighPoint Acquisition (see ~~Note 13 - Subsequent Events~~ ~~for further discussion):~~

Crude Oil
(NYMEX WTI) Natural Gas
(NYMEX Henry Hub) Natural Gas
(CIG Basis) Natural Gas
(CIG)
Bbls/day Weighted Avg. Price per Bbl MMBtu/day Weighted Avg. Price per MMBtu MMBtu/day Weighted Avg. Basis Differential to CIG Price per MMBtu MMBtu/day Weighted Avg. Price per MMBtu
2Q21
Cashless Collar 2,500 $34.40/$49.82 20,000 $2.25/$2.52 — — — —
Swap 14,000 $54.20 — — 20,000 $0.43 20,000 $2.12
Oil Roll Swaps(1)
4,000 $0.16 — — — — — —
3Q21
Cashless Collar 3,000 $30.00/$50.62 20,000 $2.25/$2.52 — — 20,000 $2.15/$2.75
Swap 9,500 $54.41 — — 20,000 $0.43 20,000 $2.12
Oil Roll Swaps(1)
4,500 $0.16 — — — — — —
4Q21
Cashless Collar 4,000 $30.63/$50.34 20,000 $2.25/$2.52 — — 20,000 $2.15/$2.75
Swap 8,000 $54.49 — — 20,000 $0.43 13,370 $2.13
Oil Roll Swaps(1)
4,500 $0.16 — — — — — —
1Q22
Cashless Collar 5,500 $34.21/$56.56 — — — — 20,000 $2.15/$2.75
Swap 1,000 $50.15 — — — — 10,000 $2.13
Oil Roll Swaps(1)
2,000 $0.22 — — — — — —
Swaptions 4,000 $55.06 — — — — — —
2Q22
Cashless Collar 4,000 $35.79/$60.57 — — — — 20,000 $2.15/$2.75
Swap 1,000 $50.15 — — — — 10,000 $2.13
Oil Roll Swaps(1)
2,000 $0.22 — — — — — —
Swaptions 4,000 $55.06 — — — — — —
3Q22
Cashless Collar 2,500 $38.27/$63.45 — — — — — —
Swap 1,000 $50.15 — — — — 10,000 $2.13
Oil Roll Swaps(1)
2,000 $0.22 — — — — — —
Swaptions 2,000 $55.13 — — — — — —
4Q22
Cashless Collar 2,000 $39.09/$65.63 — — — — — —
Swap 1,000 $50.15 — — — — 10,000 $2.13
Oil Roll Swaps(1)
2,000 $0.22 — — — — — —
Swaptions 2,000 $55.13 — — — — — —

~~(1)~~periodic variable Roll Differential and receives a weighted-average fixed price differential. The ~~weighted average~~weighted-average differential represents the amount of reduction to NYMEX WTI prices for the notional volumes covered by the swap contracts.

As of March 31, 2022, the Company had entered into the following commodity price derivative contracts:


	Contract Period
	Q2 2022		Q3 2022		Q4 2022		Q1 2023		Q2 - Q4 2023		2024
Oil Derivatives (volumes in Bbls/day and prices in $/Bbls)
Swaps
NYMEX WTI Volumes	11,300		10,507		9,538		457		392		479
Weighted-Average Contract Price	$	49.56	$	47.00	$	46.84	$	45.42	$	46.59	$	53.96
Two-Way Collars
NYMEX WTI Volumes	9,775		8,296		7,393		1,054		—		—
Weighted-Average Ceiling Price	$	65.66	$	68.43	$	69.63	$	72.70	$	—	$	—
Weighted-Average Floor Price	$	38.75	$	40.66	$	40.97	$	40.00	$	—	$	—
Three-Way Collars
NYMEX WTI Volumes	3,642		2,241		1,738		1,721		1,303		143
Weighted-Average Ceiling Price	$	59.54	$	58.03	$	57.78	$	58.75	$	57.26	$	56.25
Weighted-Average Floor Price	$	48.96	$	48.59	$	48.42	$	49.31	$	48.32	$	45.00
Weighted-Average Sold Put Price	$	38.96	$	38.59	$	38.42	$	39.25	$	38.01	$	35.00
Roll Differential Swaps (1)
NYMEX WTI Volumes	2,000		2,000		2,000		—		—		—
Weighted-Average Contract Price	$	0.22	$	0.22	$	0.22	$	—	$	—	$	—
Natural Gas Derivatives (volumes in MMBtu/day and prices in $/MMBtu)
Swaps
NYMEX HH Volumes	55,618		54,952		54,783		44,641		43,883		22,309
Weighted-Average Contract Price	$	2.76	$	2.76	$	2.76	$	2.51	$	2.51	$	2.57
CIG Volumes	10,000		10,000		10,000		—		—		—
Weighted-Average Contract Price	$	2.13	$	2.13	$	2.13	$	—	$	—	$	—
Two-Way Collars
NYMEX HH Volumes	63,113		81,018		79,148		9,558		1,736		1,033
Weighted-Average Ceiling Price	$	3.49	$	3.68	$	3.69	$	3.23	$	2.91	$	3.05
Weighted-Average Floor Price	$	2.50	$	2.59	$	2.60	$	2.03	$	2.32	$	2.38
CIG Volumes	20,000		—		—		—		—		—
Weighted-Average Ceiling Price	$	2.75	$	—	$	—	$	—	$	—	$	—
Weighted-Average Floor Price	$	2.15	$	—	$	—	$	—	$	—	$	—
Three-Way Collars
NYMEX HH Volumes	148		136		127		899		167		303
Weighted-Average Ceiling Price	$	2.74	$	2.74	$	2.74	$	3.19	$	3.33	$	3.49
Weighted-Average Floor Price	$	2.50	$	2.50	$	2.50	$	2.50	$	2.50	$	2.50
Weighted-Average Sold Put Price	$	2.00	$	2.00	$	2.00	$	2.00	$	2.00	$	2.00
NGL Derivatives (volumes in Bbls/day and prices in $/Bbl)
Swaps
OPIS Basket Volumes	4,000		4,000		4,000		—		—		—
Weighted-Average Contract Price	$	20.22	$	20.22	$	20.22	$	—	$	—	$	—

______________________________

~~Table~~(1) The weighted-average differential represents the amount of ~~Contents~~reduction to NYMEX WTI prices for the notional volumes covered by the swap contracts.

The Company did not enter into any commodity price derivative contracts subsequent to March 31, 2022 through the filing of this report.

Derivative Assets and Liabilities Fair Value

The Company’s commodity price derivatives are measured at fair value and are included in the accompanying balance sheets as derivative assets and liabilities. The following table contains a summary of all the Company’s derivative positions reported on the accompanying balance sheets as well as a reconciliation between the gross assets and liabilities and the potential effects of master netting arrangements on the fair value of the ~~dates indicated in the table below~~Company’s commodity derivative contracts as of March 31, 2022 and December 31, 2021 (in thousands):


		March 31, 2021		December 31, 2020			March 31, 2022		December 31, 2021
Derivative Assets:	Derivative Assets:					Derivative Assets:
Commodity contracts - current	Commodity contracts - current	$	0	$	7,482	Commodity contracts - current	$	—	$	3,393
Commodity contracts - noncurrent	Commodity contracts - noncurrent	92		0		Commodity contracts - noncurrent	—		—
Total derivative assets						Total derivative assets	—		3,393
Amounts not offset in the accompanying balance sheets						Amounts not offset in the accompanying balance sheets	—		(3,393)
Total derivative assets, net						Total derivative assets, net	$	—	$	—

Derivative Liabilities:	Derivative Liabilities:					Derivative Liabilities:
Commodity contracts - current	Commodity contracts - current	(18,549)		(6,402)		Commodity contracts - current	$	(384,694)	$	(219,804)
Commodity contracts - noncurrent		(1,421)		(1,330)
Total derivative assets (liabilities), net		$	(19,878)	$	(250)
Commodity contracts - long-term						Commodity contracts - long-term	(46,111)		(19,959)
Total derivative liabilities						Total derivative liabilities	(430,805)		(239,763)
Amounts not offset in the accompanying balance sheets						Amounts not offset in the accompanying balance sheets	—		3,393
Total derivative liabilities, net						Total derivative liabilities, net	$	(430,805)	$	(236,370)

The following table summarizes the components of the derivative ~~gain (loss)~~loss presented on the accompanying statements of operations for the periods below (in thousands):


	Three Months Ended March 31,
	2022		2021
Derivative cash settlement loss:
Oil contracts	$	(125,162)	$	(2,822)
Gas contracts	(28,784)		(969)
NGL contracts	(12,632)		—
Total derivative cash settlement loss	(166,578)		(3,791)
Change in fair value loss	(128,915)		(19,628)
Total derivative loss	$	(295,493)	$	(23,419)

Three Months Ended March 31,
2021 2020
Derivative cash settlement gain (loss):
Oil contracts $ (2,822) $ 10,438
Gas contracts (969) 816
Total derivative cash settlement gain (loss)(1)
(3,791) 11,254
Change in fair value gain (loss) (19,628) 89,165
Total derivative gain (loss)(1)
$ (23,419) $ 100,419

~~(1)Total derivative gain (loss)~~

NOTE 10 - ASSET RETIREMENT OBLIGATIONS

The Company recognizes an estimated liability for future costs associated with the abandonment of its oil and ~~total derivative cash settlement gain (loss)~~gas properties, including facilities requiring decommissioning. A liability for the ~~three months ended March 31, 2021~~fair value of an asset retirement obligation and ~~2020~~corresponding increase to the carrying value of the related long-lived asset are ~~reported~~recorded at the time a well is drilled or acquired, or a facility is constructed. The increase in carrying value is included in the ~~derivative (gain) loss line item~~proved oil and ~~derivative cash settlement gain (loss)~~gas properties line item in the accompanying ~~statements~~balance sheets. The Company depletes the amount added to proved oil and gas property costs and recognizes expense in connection with the accretion of ~~cash flows, within~~the discounted liability over the remaining estimated economic lives of the respective long-lived assets. Cash paid to settle asset retirement obligations is included in the cash flows from operating ~~activities.~~ activities section of the accompanying statements of cash flows.

The Company’s estimated asset retirement obligation liability is based on historical experience plugging and abandoning wells, estimated economic lives, estimated plugging and abandonment cost, and regulatory requirements. The liability is discounted using the credit-adjusted risk-free rate estimated at the time the liability is incurred or revised.

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A roll-forward of the Company's asset retirement obligation is as follows (in thousands):


	Amount
Balance as of December 31, 2021	$	225,315
Additional liabilities incurred	1,748
Accretion expense	4,019
Liabilities settled	(5,131)


Balance as of March 31, 2022	$	225,951
Current portion	24,000
Long-term portion	$	201,951

NOTE 11- EARNINGS PER SHARE

Earnings per basic and diluted share are calculated under the treasury stock method. Basic net income (loss) per common share is calculated by dividing net income (loss) by the basic weighted-average common shares outstanding for the respective period. Diluted net income (loss) per common share is calculated by dividing net income (loss) by the diluted weighted-average common shares outstanding, which includes the effect of potentially dilutive securities. Potentially dilutive securities for this calculation consist of unvested RSUs, DSUs, PSUs as well as outstanding in-the-money stock options and warrants. When the Company recognizes a loss from continuing operations, all potentially dilutive shares are anti-dilutive and are consequently excluded from the calculation of diluted earnings per share.

The Company issues RSUs and DSUs, which represent the right to receive, upon vesting, ~~one~~1 share of the Company's common stock. The number of potentially dilutive shares related to unvested RSUs and DSUs is based on the number of shares, if any, that would be issuable at the end of the respective reporting period, assuming that date was the end of the vesting period. The Company issues PSUs, which represent the right to receive, upon settlement of the PSUs, a number of shares of the Company's common stock that ranges from 0zero to 2 times the number of PSUs granted on the award date. The number of potentially dilutive shares related to PSUs is based on the number of shares, if any, that would be issuable at the end of the respective reporting period, assuming that date was the end of the performance period applicable to such PSUs. The Company has also issued stock options and warrants, which both represent the right to purchase the Company's common stock at a specified exercise price. The number of potentially dilutive shares related to the stock options and warrants is based on the number of shares, if any, that would be exercisable at the end of the respective reporting period, assuming ~~that~~the date was the end of such stock options' or warrants' term.

Stock options and warrants are only dilutive when the average price of the common stock during the period exceeds the exercise price. Please refer to Note 7 -Stock-Based Compensation for additional discussion.

~~Table~~The following table sets forth the calculations of ~~Contents~~

~~The Company uses the treasury stock method to calculate earnings~~basic and diluted net income (loss) per common share ~~as shown in the following table~~ (in thousands, except per share amounts):


	Three Months Ended March 31,
	2022		2021
Net income (loss)	$	91,639	$	(119)

Basic net income (loss) per common share	$	1.08	$	(0.01)
Diluted net income (loss) per common share	$	1.07	$	(0.01)

Weighted-average shares outstanding - basic	84,840		20,839
Add: dilutive effect of contingent stock awards	486		—
Weighted-average shares outstanding - diluted	85,326		20,839

Three Months Ended March 31,
2021 2020
Net income (loss) $ (119) $ 78,551
Basic net income (loss) per common share $ (0.01) $ 3.80
Diluted net income (loss) per common share $ (0.01) $ 3.80
Weighted-average shares outstanding - basic 20,839 20,649
Add: dilutive effect of contingent stock awards 0 35
Weighted-average shares outstanding - diluted 20,839 20,684

There were ~~807,782~~18,436 and ~~648,476~~807,782 shares that were anti-dilutive for the three months ended March 31, ~~2021~~2022 and ~~2020,~~2021, respectively. ~~The Company was in a net loss position for the three months ended March 31, 2021, which made all potentially dilutive shares anti-dilutive.~~

The exercise price of the Company's ~~stock~~ warrants ~~were~~was in excess of the Company's stock price during the three months ended March 31, ~~2020;~~2022; therefore, they were excluded from the earnings per share calculation. ~~The Company's warrants expired on April 30, 2020.~~

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NOTE 12 - INCOME TAXES

Deferred tax assets and liabilities are measured by applying the provisions of enacted tax laws to determine the amount of taxes payable or refundable currently or in future years related to cumulative temporary differences between the tax basis of assets and liabilities and amounts reported in the ~~Company's~~accompanying balance sheets. The tax effect of the net change in the cumulative temporary differences during each period in the deferred tax assets and liabilities determines the periodic provision for deferred taxes.

The following table outlines the Federal net operating loss (“NOL”) carryforwards acquired and deferred tax assets and liabilities recorded as a result of the mergers that closed in 2021 (in millions):


	HighPoint Merger		Extraction Merger		Crestone Peak Merger
Federal NOL carryforwards	$	219.0	$	479.9	$	555.7

Deferred tax asset (liability)	$	110.5	$	49.2	$	(125.1)
Valuation allowance	(48.1)		—		—
Net	$	62.4	$	49.2	$	(125.1)

The Company assesses the recoverability of its deferred tax assets each period by considering whether it is more likely than not that all or a portion of the deferred tax assets will be realized. In making such determination, the Company considers all available (both positive and negative) evidence, including future reversals of temporary differences, tax-planning strategies, projected future taxable income, and results of operations. ~~The~~As a result of the HighPoint Merger, the Company ~~has cumulative book income for the prior three years and is forecasting future book income, which resulted in the full~~recorded a valuation allowance ~~being removed~~of $48.1 million during 2021 against certain acquired net operating losses and other tax attributes due to the limitation on realizability caused by the change of ownership provisions of Section 382 of the Code. The net deferred tax liability as of March 31, 2022 was $5.8 million, and the net deferred tax asset as of December 31, ~~2020.~~2021 was $22.3 million. The Company will continue to monitor facts and circumstances in the reassessment of the likelihood that the deferred tax assets will be realized.

Federal income tax expense differs from the amount that would be provided by applying the statutory United States federal income tax rate of 21% to income before income taxes primarily due to the effect of state income taxes, ~~changes in valuation allowances, rate changes,~~equity-based compensation, and other permanent ~~differences.~~differences including bargain purchase gain. During the three months ended March 31, ~~2021~~2022 and ~~2020,~~2021, the Company recorded income tax expense of $23.4 million and income tax benefit of ~~an immaterial amount and 0,~~less than $0.1 million, respectively.

AsThe Company had no unrecognized tax benefits as of March 31, ~~2021~~2022 and December 31, ~~2020, the Company had 0 unrecognized tax benefits.~~2021. The Company's management does not believe that there are any new items or changes in facts or judgments that would impact the Company's tax position taken thus far in ~~2021.~~

~~NOTE 13 - SUBSEQUENT EVENTS~~

~~HighPoint Acquisition~~

On April 1, 2021, BCEI completed its previously announced acquisition of HighPoint Resources Corporation, a Delaware corporation (“HighPoint”), pursuant to the terms of HighPoint’s prepackaged plan of reorganization under Chapter 11 of the United States Bankruptcy Code (the “Prepackaged Plan”), which was confirmed by the U.S. Bankruptcy Court for the District of Delaware on March 18, 2021 pursuant to a confirmation order, and went effective on April 1, 2021 (the “HighPoint Acquisition”).2022.

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NOTE 13 - LEASES

The ~~Prepackaged Plan implements~~Company’s right-of-use assets and lease liabilities are recognized on the ~~merger (the “Merger”) and restructuring transactions in accordance with~~accompanying balance sheets based on the Agreement and Plan of Merger, dated as of November 9, 2020 (the “Merger Agreement”), by and among Bonanza Creek, HighPoint and Boron Merger Sub, Inc., a wholly-owned subsidiary of Bonanza Creek (“Merger Sub”). Pursuant to the Prepackaged Plan and the Merger Agreement, at the effective time of the Merger (the “Effective Time”) and the effective date under the Prepackaged Plan, Merger Sub merged with and into HighPoint, with HighPoint continuing as the surviving corporation and wholly-owned subsidiary of Bonanza Creek. At the Effective Time, each eligible share of common stock, par value $0.001 per share, of HighPoint issued and outstanding immediately prior to the Effective Time was automatically converted into the right to receive 0.11464 shares of common stock, par value $0.01 per share, of Bonanza Creek (“Bonanza Creek Common Stock”), with cash paid in lieu of the issuance of any fractional shares. As a result, the Company issued approximately 487,952 shares of Bonanza Creek Common Stock to former HighPoint stockholders.

Concurrently with the Merger and pursuant to the Prepackaged Plan, and in exchange for the $625 million in aggregate principal amount outstanding of 7.0% Senior Notes due 2022 of HighPoint Operating Company (“HighPoint OpCo”) and 8.75% Senior Notes due 2025 of HighPoint OpCo (collectively, the “HighPoint Senior Notes”), Bonanza Creek issued to all holders of HighPoint Senior Notes an aggregate of (i) 9,314,214 shares of Bonanza Creek Common Stock and (ii) $100 million aggregate principal amount of 7.5% Senior Notes due 2026 of Bonanza Creek (“Bonanza Creek Senior Notes”).

Immediately after the Effective Time, in connection with the Merger, Bonanza Creek entered into the Second Amendment, dated April 1, 2021, to the Credit Facility to, among other things: (i) increase the aggregate maximum commitment amount from $750,000,000 to $1,000,000,000; (ii) increase the available borrowing base from $260,000,000 to $500,000,000; (iii) increase (A) the LIBOR floor from 0 to .50% and (B) the alternate base rate floor from 0 to 1.50%; (iv) increase the maximum amount of unrestricted cash and cash equivalents subject to a first priority lien in favor of the Administrative Agent that can be netted against total debt in the calculation of the maximum permitted leverage ratio, from $25,000,000 to $35,000,000; (v) decrease for any fiscal quarter ending on or after April 1, 2021, the maximum permitted net leverage ratio from 3.50 to 3.0; and (vi) amend certain other covenants and provisions. In addition, the maximum permitted leverage ratio for purposes of making a restricted payment, investment, or optional or voluntary redemption was decreased from 2.75 to 1.0; however, a new provision was added that allows restricted payments that do not exceed available free cash flow, so long as there are no deficiencies or defaults under the Credit Facility, the leverage ratio does not exceed 2.25 to 1.0, and borrowings under the Credit Facility do not exceed 80% of the borrowing base.

Under the Credit Facility and as amended by the Second Amendment, Bonanza Creek’s Credit Facility will be guaranteed by all restricted domestic subsidiaries of Bonanza Creek including by HighPoint and its subsidiaries, and will be secured by first priority security interests on substantially all assets, including a mortgage on at least 90% of the totalpresent value of the ~~proved oil~~expected lease payments over the lease term. The following table summarizes the asset classes of the Company's operating leases (in thousands):


	March 31, 2022		December 31, 2021
Operating Leases
Field equipment(1)	$	26,470	$	29,312
Corporate leases	8,666		9,484
Vehicles	918		1,089
Total right-of-use asset	$	36,054	$	39,885

Field equipment(1)	$	26,470	$	29,312
Corporate leases	9,120		9,870
Vehicles	918		1,089
Total lease liability	$	36,508	$	40,271

____________________________

(1) Includes compressors, certain natural gas processing equipment, and gas properties evaluated in the most recently delivered reserve reports prior to the amendment effective date, including any engineering reports relating to the oil and gas properties of HighPoint and its subsidiaries, of each of Bonanza Creek, all restricted domestic subsidiaries of Bonanza Creek and HighPoint and its subsidiaries, in each case, subject to customary exceptions.other field equipment.

~~Acquisition~~

The Company incurred gross short-term lease costs of ~~$3.3~~$9.0 million ~~related to the HighPoint Acquisition are included in merger transaction costs in the Company's statements of operations~~and less than $0.1 million for the three months ended March 31, ~~2021. We expect~~2022 and 2021, respectively. A portion of these costs may have been or will be billed to ~~account~~other working interest owners, and the Company's net share of these costs, once paid, are capitalized to property and equipment or recognized as expense.

Future commitments by year for the ~~HighPoint Acquisition under~~Company's leases with a lease term of one year or more as of March 31, 2022 are presented in the ~~acquisition method of accounting for business combinations~~table below. Such commitments are reflected at undiscounted values and are ~~currently in~~reconciled to the process of determining preliminary estimated acquisition date fair values of identifiable assets acquired and liabilities assumed. HighPoint's post-acquisition date results of operations will be incorporated intodiscounted present value recognized on the ~~Company's interim condensed consolidated financial statements for the three and six months ended June 30, 2021.~~accompanying balance sheets as follows (in thousands):


	Operating Leases
Remainder of 2022	$	15,271
2023	13,389
2024	5,333
2025	1,695
2026	1,195
Thereafter	1,586
Total lease payments	38,469
Less: imputed interest	(1,961)
Total lease liability	$	36,508

~~HighPoint Legal Proceedings~~

Upon closing of the HighPoint Acquisition, the Company assumed all obligations, whether asserted or unasserted, of HighPoint Resources Corporation. As of the filing date of this report, there were no probable, material pending, or overtly threatened legal actions against the Company that were associated with HighPoint of which it was aware, other than the following:

~~Table of~~ ~~Contents~~

On June 15, 2020, Sterling Energy Investments LLC (“Sterling”) filed a complaint against HighPoint Operating Corporation, a subsidiary of HighPoint Resources Corporation, for breach of contract related to a Gas Purchase Agreement dated effective November 1, 2017. Sterling alleges that HighPoint OpCo breached the contract by failing to use reasonable commercial efforts to deliver to Sterling at Sterling’s receipt points all quantities of gas not otherwise dedicated to other gas purchase agreements. Sterling seeks monetary damages in an amount not yet specified. On July 31, 2020, the HighPoint Resources Corporation filed a counterclaim against Sterling for breach of Sterling’s obligations under the Gas Purchase Agreement. The Company continues to vigorously deny Sterling’s claims and is seeking monetary damages in an amount not yet specified. The case is scheduled to go to trial in July 2021. At this time, the Company is unable to determine whether any loss is probable or reasonably estimate a range of such loss, and accordingly has not recognized any liability associated with this matter.

Disclosure of certain environmental matters is required when a governmental authority is a party to the proceedings and the proceedings involve potential monetary sanctions that the Company believes could exceed $300,000. HighPoint Resources Corporation received Notices of Alleged Violations (“NOAV”) from the Colorado Oil and Gas Conservation Commission (“COGCC”) alleging violations of various Colorado statutes and COGCC regulations governing oil and gas operations. The Company continues to engage in discussions regarding resolution of the alleged violations. The Company recognized approximately $1.3 million upon acquiring HighPoint Resources Corporation associated with the NOAVs, as they are probable and reasonably estimable.

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Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations.

The following discussion and analysis of our financial condition and results of operations should be read in conjunction with “Management’s Discussion and Analysis of Financial Condition and Results of Operations” contained in our ~~Annual Report on~~2021 Form 10-K ~~for the year ended December 31, 2020,~~, as well as the unaudited condensed consolidated financial statements and notes thereto included in this Quarterly Report on Form 10-Q.

Executive Summary

We are an independent Denver-based exploration and production company focused on the acquisition, development, and ~~extraction~~production of oil and associated liquids-rich natural gas in the ~~United States. Our oil and liquids-weighted assets and operations are concentrated~~Rocky Mountain region, primarily in ~~the rural portions of~~ the Wattenberg Field ~~in Colorado. Our development and extraction activities are primarily directed at the horizontal development~~ of ~~the Niobrara and Codell formations in~~ the Denver-Julesburg (“DJ”) ~~Basin.~~Basin of Colorado. We believe our acreage in the DJ Basin has been significantly delineated by our own drilling success and by the success of offset operators, providing confidence that our inventory is repeatable and will continue to generate economic returns. The majority of our revenues are generated through the sale of oil, natural gas, and natural gas liquids production.

The Company’s primary objective is to maximize shareholder returns by responsibly developing our oil and natural gas resources. ~~We seek to balance production growth with maintaining a conservative balance sheet.~~ Key aspects of our strategy include multi-well pad development across our leasehold, ~~enhanced completions through continuous design evaluation, utilization of scaled infrastructure,~~ continuous safety improvement, strict adherence to health and safety regulations, environmental stewardship, disciplined approach to acquisitions and ~~environmental stewardship.~~divestitures and capital allocation, and prudent risk management.

Financial and Operating Results

Our financial and operational results include:

•~~General and administrative expense decreased by 2% during the three months ended March 31, 2021 when compared to the same period in 2020;~~

•~~Lease operating expense~~Crude oil equivalent sales volumes increased ~~by 1%~~663% for the three months ended March 31, ~~2021~~2022 when compared to the same period ~~in 2020;~~during 2021 primarily due to the HighPoint, Extraction, and Crestone Peak mergers as well as the Bison Acquisition;

•~~Crude oil equivalent sales volumes~~General and administrative expense per Boe decreased by 49% for the three months ended March 31, 2022 when compared to the same period during 2021 due to the synergies achieved through the HighPoint, Extraction, and Crestone Peak mergers;

•Lease operating expense per Boe decreased by 17% for the three months ended March 31, ~~2021~~2022 when compared to the same period ~~in 2020 due to adverse weather conditions;~~

•~~Borrowings under our Credit Facility remained at zero~~ during ~~the three months ended March 31,~~ 2021;

•Total liquidity ~~of $298.7 million~~was $0.9 billion at March 31, ~~2021,~~2022, consisting of cash on hand plus funds available under our Credit ~~Facility.~~Facility, after giving effect to an aggregate of $12.4 million of undrawn letters of credit. Please refer to Liquidity and Capital Resources below for additional discussion;

•Cash dividends of $103.6 million, or $1.2125 per share, declared and paid during the three months ended March 31, 2022;

•Cash flows provided by operating activities for the three months ended March 31, ~~2021~~2022 were ~~$43.0~~$532.5 million, as compared to ~~cash flows provided by operating activities of $48.0~~$43.0 million during the three months ended March 31, ~~2020.~~2021. Please refer to Liquidity and Capital Resources below for additional discussion; and

•Capital expenditures, inclusive of accruals, ~~of $32.9~~were $234.5 million during the three months ended March 31, ~~2021.~~2022.

~~Rocky Mountain Infrastructure~~

Midstream Assets

The Company's midstream assets provide reliable gathering, treating, and storage for the Company’s operated production ~~facilities, maintained under its Rocky Mountain Infrastructure, LLC (“RMI”) subsidiary, provide many operational benefits~~while reducing facility site footprints, leading to ~~the Company~~more cost-efficient operations and ~~provide cost economies of a centralized system. The RMI facilities reduce gathering system pressures at the wellhead, thereby improving hydrocarbon recovery.~~reduced emissions and surface disturbance per Boe produced. Additionally, ~~with eleven interconnects to four different natural gas processors, RMI~~this infrastructure helps ensure that the Company's production is not constrained by any single midstream service provider. ~~Furthermore,~~

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Rocky Mountain Infrastructure (“RMI”), together with adjacent gathering assets acquired from HighPoint, serves the Company’s eastern acreage position with multiple interconnects to four different natural gas processors. Significant cost and operational synergies have been realized with the combination of RMI and HighPoint midstream assets. Additionally, in 2019, the Company installed a new oil gathering line to Riverside Terminal (on the Grand Mesa Pipeline), which resulted in a corresponding $1.25 to $1.50 per barrel reduction to our oil differentials for barrels transported on such gathering line. The ~~total value~~Company completed an additional oil interconnect in September 2021, thus providing additional outlets that provide flow assurance and minimize differentials.

As a result of ~~reduced~~the Crestone Peak Merger, the Company acquired a gas gathering system that serves the Company's southern acreage position and an oil ~~differentials during~~gathering system that serves a portion of the ~~three months ended March 31, 2021~~Company's western acreage. The gas gathering system ensures reliable, low-pressure service at the wellhead. The capacity of this system is in the process of being expanded with the addition of another compressor station. The oil gathering system gathers, treats, and ~~2020 was approximately $1.2 million~~stores oil and ~~$1.3 million, respectively. Finally,~~water from multiple nearby producing pads and subsequently delivers each to downstream outlets. The Company is in the ~~RMI~~process of adding an oil gathering system ~~reduces facility site footprints, leading~~in the southern acreage position and has also acquired an oil terminal that collects and stores product for subsequent delivery to ~~more cost-efficient operations and reduced surface disturbance.~~ downstream outlets.

The net book value of the Company's ~~RMI~~midstream assets was ~~$155.1~~$286.0 million as of March 31, ~~2021.~~2022.

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Current Events and Outlook

~~The~~Oil and natural gas prices continue to be impacted by the efforts to contain COVID-19, the pace of economic recovery, and changes to OPEC+ production levels. There is increased economic optimism as governments worldwide ~~outbreak~~continue to distribute the COVID-19 vaccines. However, although vaccination campaigns are underway, several regions continue to deal with a rising number of COVID-19 ~~the uncertainty regarding the impact~~cases. In addition, Russia’s invasion of ~~COVID-19, and various governmental actions taken~~Ukraine has led to ~~mitigate the impact of COVID-19, resulted in an unprecedented decline in demand for oil and natural gas. At the same time, the decision by Saudi Arabia in March 2020 to drastically reduce~~regional instability, Although Russian export ~~prices and increase oil production further increased the excess supply~~volumes of oil and gas have been only modestly impacted so far, uncertainty regarding potential future impacts of sanctions and buyer aversion to Russian hydrocarbons presents significant risk to future supply and demand balances. The foregoing destabilizing factors have caused dramatic fluctuations in global financial markets and uncertainty about world-wide oil supply and demand, which in turn has increased the volatility of oil, natural gas, ~~throughout 2020. However,~~and NGL prices. West Texas Intermediate (“WTI”) oil prices have recovered to pre-pandemic levels, averaging approximately $94 per barrel during the first quarter of ~~2021, expectations surrounding~~2022. With the current shortage of other sources of energy, and the economic growth associated with what appears to be a global emergence from the pandemic, the demand for and price of oil has increased.

On April 1, 2021, we completed the previously announced acquisition of HighPoint, and ~~natural gas have stimulated a rise in oil~~on November 1, 2021, we completed the previously announced mergers with Extraction and ~~natural gas prices.~~

Crestone Peak. Additionally, on March 1, 2022, we completed the previously announced acquisition of Bison. The ~~COVID-19 outbreak~~Company believes it has successfully integrated the operations, production and ~~its development into a pandemic in March 2020 also required that we take precautionary measures intended to help minimize the risk to our business, employees, customers, suppliers,~~accounting databases derived from each of these mergers and the communities in which we operate. Our operational employees are currently still able to work on site. However, we have taken various precautionary measures with respect to our operational employees such as requiring them to verify they have not experienced any symptoms consistent with COVID-19, or been in close contact with someone showing such symptoms, before reporting to the work site, quarantining any operational employees who have shown signs of COVID-19 (regardless of whether such employee has been confirmed to be infected), and imposing social distancing requirements on work sites, all in accordance with the guidelines released by the Centers for Disease Control and Prevention. We have not yet experienced any material operational disruptions (including disruptions from our suppliers and service providers) as a result of a COVID-19 outbreak.acquisitions.

The Company's ~~stand-alone first quarter 2021~~2022 drilling and completion capital budget of ~~$35~~$825 million to ~~$40~~$950 million contemplates running an average of 3.5 operated rigs and ~~combined second through fourth quarter 2021 capital budget (reflecting the closing of the HighPoint Acquisition on April 1, 2021) of $115~~3 operated crews that will drill 190 to 210 and complete 165 to 175 gross operated wells. Additionally, we intend to invest approximately $70 million to ~~$130~~$90 million ~~includes completing 45 gross (39.9 net) drilled, uncompleted wells,~~in land, midstream, and ~~picking up a drilling rig in the fourth quarter of 2021, with completions of those newly drilled wells to begin in 2022. Actual~~other capital ~~expenditures could vary significantly based on, among other things, market conditions, commodity prices, drilling~~activity that will support our acreage positions and ~~completion costs, and well results.~~

overall infrastructure.

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Results of Operations

The following table summarizes our product revenues, sales volumes, and average sales prices for the periods indicated:

Three Months Ended March 31,
2021 2020 Change Percent Change
Revenues (in thousands):
Crude oil sales(1)
$ 49,800 $ 50,589 $ (789) (2) %
Natural gas sales(2)
12,286 4,962 7,324 148 %
Natural gas liquids sales 10,963 3,241 7,722 238 %
Product revenue $ 73,049 $ 58,792 $ 14,257 24 %
Sales Volumes:
Crude oil (MBbls) 942.7 1,229.4 (286.7) (23) %
Natural gas (MMcf) 3,213.9 3,562.7 (348.8) (10) %
Natural gas liquids (MBbls) 398.1 436.9 (38.8) (9) %
Crude oil equivalent (MBoe)(3)
1,876.5 2,260.1 (383.6) (17) %
Average Sales Prices (before derivatives):
Crude oil (per Bbl) $ 52.83 $ 41.15 $ 11.68 28 %
Natural gas (per Mcf) $ 3.82 $ 1.39 $ 2.43 175 %
Natural gas liquids (per Bbl) $ 27.54 $ 7.42 $ 20.12 271 %
Crude oil equivalent (per Boe)(3)
$ 38.93 $ 26.01 $ 12.92 50 %
Average Sales Prices (after derivatives)(4):
Crude oil (per Bbl) $ 49.83 $ 49.64 $ 0.19 — %
Natural gas (per Mcf) $ 3.52 $ 1.62 $ 1.90 117 %
Natural gas liquids (per Bbl) $ 27.54 $ 7.42 $ 20.12 271 %
Crude oil equivalent (per Boe)(3)
$ 36.91 $ 30.99 $ 5.92 19 %


	Three Months Ended March 31,
	2022		2021		Change		Percent Change
Revenues (in thousands):
Crude oil sales(1)	$	548,966	$	49,800	$	499,166	1,002	%
Natural gas sales(2)	112,430		12,286		100,144		815	%
Natural gas liquids sales	155,147		10,963		144,184		1,315	%
Product revenue	$	816,543	$	73,049	$	743,494	1,018	%

Sales Volumes:
Crude oil (MBbls)	6,123.5		942.7		5,180.8		550	%
Natural gas (MMcf)	26,786.4		3,213.9		23,572.5		733	%
Natural gas liquids (MBbls)	3,722.7		398.1		3,324.6		835	%
Crude oil equivalent (MBoe)(3)	14,310.6		1,876.5		12,434.1		663	%

Average Sales Prices (before derivatives)(4):
Crude oil (per Bbl)	$	89.65	$	52.83	$	36.82	70	%
Natural gas (per Mcf)	$	4.20	$	3.82	$	0.38	10	%
Natural gas liquids (per Bbl)	$	41.68	$	27.54	$	14.14	51	%
Crude oil equivalent (per Boe)(3)	$	57.06	$	38.93	$	18.13	47	%

Average Sales Prices (after derivatives)(4):
Crude oil (per Bbl)	$	69.21	$	49.83	$	19.38	39	%
Natural gas (per Mcf)	$	3.12	$	3.52	$	(0.40)	(11)	%
Natural gas liquids (per Bbl)	$	38.28	$	27.54	$	10.74	39	%
Crude oil equivalent (per Boe)(3)	$	45.42	$	36.91	$	8.51	23	%

_____________________________

(1)Crude oil sales excludes ~~$0.3~~$0.5 million and ~~$0.6~~$0.3 million of oil transportation revenues from third parties, which do not have associated sales volumes, for the three months ended March 31, ~~2021~~2022 and ~~2020,~~2021, respectively.

(2)Natural gas sales excludes ~~$0.8~~$0.7 million and ~~$1.0~~$0.8 million of gas gathering revenues from third parties, which do not have associated sales volumes, for the three months ended March 31, ~~2021~~2022 and ~~2020,~~2021, respectively.

(3)Determined using the ratio of 6 Mcf of natural gas to 1 Bbl of crude oil.

(4)Derivatives economically hedge the price we receive for ~~crude~~ oil, natural gas, and NGL. For the three months ended March 31, 2022, the derivative cash settlement loss for oil, natural ~~gas.~~gas, and NGLs was $125.2 million, $28.8 million, $12.6 million, respectively. For the three months ended March 31, 2021, the derivative cash settlement loss for oil and natural gas ~~contracts~~ was $2.8 million and $1.0 million, respectively. ~~For the three months ended March 31, 2020, the derivative cash settlement gain for oil and natural gas contracts was $10.4 million and $0.8 million, respectively.~~ Please refer to Note 109 - Derivatives ofunder Part I, Item 1 of this report for additional disclosures.

Product revenues increased by ~~24%~~1,018% to $816.5 million for the three months ended March 31, 2022 compared to $73.0 million for the three months ended March 31, 2021. The increase was largely due to a 663% increase in sales volumes and an $18.13, or 47%, increase in oil equivalent pricing, excluding the impact of derivatives. The increase in sales volumes is due to the HighPoint Merger that closed on April 1, 2021, ~~compared~~the Extraction and Crestone Peak mergers that closed on November 1, 2021, and the Bison Acquisition that closed on March 1, 2022. Additionally, we turned 49 gross wells to ~~$58.8 million for~~sales during the three months ended March 31, 2020. The primary driver of the increase in revenue is the 50%, or $12.92 per Boe, increase in oil equivalent pricing, partially offset by a 17% decrease in sales volumes. The decrease in sales volumes is due to production being temporarily suspended due to adverse weather conditions. We turned 19 gross wells to sales during the twelve-month period ending March 31, 2021.2022.

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The following table summarizes our operating expenses for the periods ~~indicated:~~

Three Months Ended March 31,
2021 2020 Change Percent Change
Expenses (in thousands):
Lease operating expense $ 5,731 $ 5,699 $ 32 1 %
Midstream operating expense 3,905 4,014 (109) (3) %
Gathering, transportation, and processing 4,967 3,481 1,486 43 %
Severance and ad valorem taxes 4,604 5,173 (569) (11) %
Exploration 96 373 (277) (74) %
Depreciation, depletion, and amortization 18,823 21,584 (2,761) (13) %
Abandonment and impairment of unproved properties — 30,057 (30,057) (100) %
Bad debt expense — 576 (576) (100) %
Merger transaction costs 3,295 — 3,295 100 %
General and administrative expense 9,251 9,429 (178) (2) %
Operating Expenses $ 50,672 $ 80,386 $ (29,714) (37) %
Selected Costs ($ per Boe):
Lease operating expense $ 3.05 $ 2.52 $ 0.53 21 %
Midstream operating expense 2.08 1.78 0.30 17 %
Gathering, transportation, and processing 2.65 1.54 1.11 72 %
Severance and ad valorem taxes 2.45 2.29 0.16 7 %
Exploration 0.05 0.17 (0.12) (71) %
Depreciation, depletion, and amortization 10.03 9.55 0.48 5 %
Abandonment and impairment of unproved properties — 13.30 (13.30) (100) %
Bad debt expense — 0.25 (0.25) (100) %
Merger transaction costs 1.76 — 1.76 100 %
General and administrative expense 4.93 4.17 0.76 18 %
Operating Expenses $ 27.00 $ 35.57 $ (8.57) (24) %
indicated (in thousands, except per Boe amounts):


	Three Months Ended March 31,
	2022		2021		Change		Percent Change
Operating Expenses:
Lease operating expense	$	36,019	$	5,731	$	30,288	528	%
Midstream operating expense	5,712		3,905		1,807		46	%
Gathering, transportation, and processing	50,403		4,967		45,436		915	%
Severance and ad valorem taxes	63,304		4,604		58,700		1,275	%
Exploration	528		96		432		450	%
Depreciation, depletion, and amortization	184,860		18,823		166,037		882	%
Abandonment and impairment of unproved properties	17,975		—		17,975		100	%
Unused commitments	776		—		776		100	%

Merger transaction costs	20,534		3,295		17,239		523	%
General and administrative expense	35,720		9,251		26,469		286	%
Operating expenses	$	415,831	$	50,672	$	365,159	721	%

Selected Costs ($ per Boe):
Lease operating expense	$	2.52	$	3.05	$	(0.53)	(17)	%
Midstream operating expense	0.40		2.08		(1.68)		(81)	%
Gathering, transportation, and processing	3.52		2.65		0.87		33	%
Severance and ad valorem taxes	4.42		2.45		1.97		80	%
Exploration	0.04		0.05		(0.01)		(20)	%
Depreciation, depletion, and amortization	12.92		10.03		2.89		29	%
Abandonment and impairment of unproved properties	1.26		—		1.26		100	%
Unused commitments	0.05		—		0.05		100	%

Merger transaction costs	1.43		1.76		(0.33)		(19)	%
General and administrative expense	2.50		4.93		(2.43)		(49)	%
Operating expenses	$	29.06	$	27.00	$	2.06	8	%

Lease operating expense. Our lease operating expense ~~remained consistent at~~increased $30.3 million, or 528%, to $36.0 million for the three months ended March 31, 2022 from $5.7 million for the three months ended March 31, 2021, and ~~2020 and increased 21%~~decreased 17% on an equivalent basis per Boe. Lease operating expense on an aggregate basis increased as a result of the HighPoint, Extraction, and Crestone Peak mergers as well as the Bison Acquisition. Lease operating expense per ~~unit increased on~~Boe decreased as a ~~higher percentage basis due to oil equivalent sales volumes being 17% lower in~~result of the ~~later period.~~synergies achieved through the aforementioned mergers.

Midstream operating expense. Our midstream operating expense ~~remained relatively consistent at~~increased $1.8 million, or 46%, to $5.7 million for the three months ended March 31, 2022 from $3.9 million for the three months ended March 31, 2021, ~~compared~~and decreased 81% on an equivalent basis per Boe. The aggregate increase is due to ~~$4.0 million for~~ the ~~three months ended March 31, 2020, and increased 17% on a per Boe basis during~~acquisition of certain midstream assets through the ~~comparable periods. While~~Crestone Peak Merger. Conversely, while certain midstream operating expenses correlate to sales volumes, the majority of the costs, such as compression, are ~~fixed. Therefore, the consistency~~fixed and thereby result in a decrease in midstream operating expense per Boe period over ~~period is reasonable.~~period.

Gathering, transportation, and processing. Gathering, transportation, and processing expense increased ~~by $1.5~~$45.4 million, or 915%, to $50.4 million for the three months ended March 31, 2022 from $5.0 million for the three months ended March 31, 2021, ~~from $3.5 million for the three months ended March 31, 2020. Generally, natural~~and increased 33% on an equivalent basis per Boe. Natural gas and ~~NGLs~~NGL sales volumes have a direct correlation to gathering, transportation, and processing expense. ~~Although~~Natural gas and NGL sales volumes increased 777% during the comparable periods. Additionally, our value-based percentage of proceeds sales contract, which tracks solely with natural gas and ~~NGLs sales volumes decreased 9% during the comparable periods, the overall increase relates to one of~~NGL pricing, is now our largest sales ~~contracts that determines gathering, transportation, and processing expense based on~~contract as a ~~value based percentage~~result of ~~proceeds basis.~~the mergers completed in 2021.

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Severance and ad valorem taxes. Our severance and ad valorem taxes ~~decreased 11%~~increased $58.7 million, or 1,275%, to $63.3 million for the three months ended March 31, 2022 from $4.6 million for the three months ended March 31, 2021, ~~from $5.2 million for the three months ended March 31, 2020.~~and increased 80% on an equivalent basis per Boe. Severance and ad valorem taxes primarily correlate to revenues, ~~and revenues~~which increased by ~~24% during~~1,018% for the three months ended March 31, ~~2021~~2022 when compared to the three months ended March 31, 2020. However, during the second half of 2020, we refined our tax estimate based on current mill levies, taxing districts, and company results based on commodity prices, thereby resultingsame period in ~~a reduction of severance and ad valorem expense as a percentage of revenues.~~2021.

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Depreciation, depletion, and amortization. Our depreciation, depletion, and amortization expense ~~decreased 13%~~increased $166.0 million, or 882%, to $184.9 million for the three months ended March 31, 2022 from $18.8 million for the three months ended March 31, 2021, ~~from $21.6 million for the three months ended March 31, 2020,~~ and increased 5%29% on aan equivalent basis per ~~Boe basis during the comparable periods.~~Boe. The increase in depreciation, depletion, and amortization expense ~~per Boe during the three months ended March 31, 2021 when compared to the three months ended March 31, 2020~~ is the result of (i) a ~~$113.0 million~~$4.9 billion increase in the depletable property base ~~offset by~~primarily due to the HighPoint, Extraction, and Crestone Peak mergers as well as the Bison Acquisition and (ii) a ~~decrease in the depletion rate driven by a 17% decrease~~663% increase in production between the comparable periods.

Abandonment and impairment of unproved properties.During the three months ended March 31, 2022 and 2021, ~~the Company did not incur any abandonment~~we incurred $18.0 million and ~~impairment of unproved properties. Conversely, during the three months ended March 31, 2020, the Company incurred $30.1 million~~zero, respectively, in abandonment and impairment of unproved properties due the Company's assessment of its locations and replacement of non-core legacy locations with newly acquired locations.

Unused commitments. During the three months ended March 31, 2022 and 2021, we incurred $0.8 million and zero, respectively, in unused commitments primarily due to certain deficiency payments incurred under a minimum volume water commitment.

Merger transaction costs. During the ~~reassessment~~three months ended March 31, 2022 and 2021, we incurred $20.5 million and $3.3 million, respectively, in legal, advisor, and other costs associated with the HighPoint, Extraction, and Crestone Peak mergers as well as the Bison Acquisition. Merger transaction costs include $7.6 million and zero of ~~estimated probable~~severance payments for the three months ended March 31, 2022 and ~~possible reserve locations based primarily upon economic viability.~~2021, respectively.

General and ~~administrative.~~administrative expense. Our general and administrative expense increased $26.5 million, or 286%, to $35.7 million for the three months ended March 31, 2022 from $9.3 million for the three months ended March 31, 2021, ~~was commensurate with~~and decreased 49% on an equivalent basis per Boe. The primary drivers of the ~~three months ended March 31, 2020,~~aggregate increase relate to an increase in salaries, benefits, and ~~increased by 18% on a per Boe basis.~~stock compensation expense due to the aforementioned mergers. General and administrative expense per Boe ~~increased~~decreased due to oil equivalent sales volumes being ~~17% lower~~663% higher during the three months ended March 31, ~~2021~~2022 as compared to the same period in ~~2020.~~2021.

Derivative ~~gain (loss).~~loss. Our derivative loss for the three months ended March 31, ~~2021~~2022 was $295.5 million as compared to a loss of $23.4 million for the three months ended March 31, 2021. Our derivative loss is due to settlements and fair market value adjustments caused by market prices being higher than our contracted hedge prices. Our derivative gain of $100.4 million for the three months ended March 31, 2020 is due to settlements and fair market value adjustments caused by market prices being lower than our contracted hedge prices. Please refer to Note 109 - Derivatives ofunder Part I, Item 1 of this report for additional discussion.

Interest expense. Our interest expense for the three months ended March 31, 2022 and 2021 was $9.1 million and ~~2020 was~~ $0.4 million, respectively. No interest was capitalized during the three months ended March 31, 2022 and ~~$0.2 million, respectively.~~2021. Average debt outstanding for the three months ended March 31, 2022 and 2021 was $500.0 million and ~~2020 was~~ zero, ~~and $84.8 million,~~ respectively. The components of interest expense for the periods presented are as follows (in thousands):


	Three Months Ended March 31,
	2022		2021
Senior Notes	$	6,875	$	—

Commitment fees on available borrowing base under the Credit Facility	982		326
Letter of credit fees under the Credit Facility	131		—
Amortization of deferred financing costs	1,078		93

Total interest expense	$	9,066	$	419

Three Months Ended March 31,
2021 2020
Credit Facility $ — $ 810
Commitment fees on available borrowing base under the Credit Facility 326 251
Amortization of deferred financing costs 93 123
Capitalized interest — (967)
Total interest expense, net $ 419 $ 217

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Liquidity and Capital Resources

The Company's anticipated sources of liquidity include cash from operating activities, borrowings under the Credit Facility, potential proceeds from sales of assets, and potential proceeds from ~~capital~~equity and/or debt ~~markets.~~capital markets transactions. Our cash flows from operating activities are subject to significant volatility due to changes in commodity prices, as well as variations in our production. The prices for these commodities are driven by a number of factors beyond our control, including global and regional product supply and demand, weather, product distribution, refining and processing capacity, regulatory constraints, and other supply chain dynamics, among other factors. ~~To mitigate some~~

Although we cannot provide any assurance, we believe cash flows from operating activities and availability under our Credit Facility should be sufficient to meet our cash requirements inclusive of, but not limited to, normal operating needs, debt service obligations, planned capital expenditures and commitments for at least the ~~pricing risk, as of March 31, 2021, we have hedged approximately 5,700 Bbls per day~~next twelve months and, based on current expectations, for the ~~remainder of 2021, representing more than 50% of our oil sales volume during the three months ended March 31, 2021.~~long term.

As of March 31, ~~2021,~~2022, our liquidity was ~~$298.7 million,~~$0.9 billion, consisting ~~of $38.7 million~~ of cash on hand of $154.3 million and ~~$260.0 million~~$0.8 billion of available borrowing capacity on ~~the~~our Credit ~~Facility.~~Facility, after giving effect to an aggregate of $12.4 million of undrawn letters of credit. Please refer to Note 5 - Long-Term Debt under Part I, Item 1 of this report for additional discussion.

Our weighted-average interest rate on borrowings from the Credit Facility was not applicable for the three months ended March 31, ~~2021~~2022 as there were no borrowings on our Credit Facility during the period. As of both March 31, ~~2021~~2022 and as of the date of ~~this~~ filing, we had zero ~~and $129.0 million, respectively,~~ outstanding on our Credit Facility.

~~Table of~~ ~~Contents~~

On April ~~1, 2021, in conjunction with the HighPoint Acquisition, the Company, together with certain of its subsidiaries,~~20, 2022, we entered into the Second Amendment to the Amended and Restated Credit ~~Facility.~~Facility to increase our borrowing base from $1.0 billion to $1.7 billion and the aggregate elected commitment amount from $0.8 billion to $1.0 billion. Additionally, on May 1, 2022, we exercised the Optional Redemption on the 7.5% Senior Notes to redeem the full amount outstanding of $100.0 million. Please refer to Note 135 - ~~Subsequent Events~~Long-Term Debt under Part I, Item 1 of this report for additional information.

The following table summarizes our cash flows and other financial measures for the periods indicated (in thousands):

Three Months Ended March 31,
2021 2020
Net cash provided by operating activities $ 42,964 $ 47,994
Net cash used in investing activities (28,948) (26,871)
Net cash used in financing activities (64) (21,071)
Cash, cash equivalents, and restricted cash 38,797 11,147
Acquisition of oil and gas properties (180) (284)
Exploration and development of oil and gas properties (28,730) (26,225)


	Three Months Ended March 31,
	2022		2021
Net cash provided by operating activities	$	532,541	$	42,964
Net cash used in investing activities	(516,300)		(28,948)
Net cash used in financing activities	(116,346)		(64)
Cash, cash equivalents, and restricted cash	154,451		38,797
Acquisition of oil and gas properties	(300,087)		(180)
Exploration and development of oil and gas properties	(260,667)		(28,730)

Cash flows provided by operating activities

~~Our cash flows for~~For the three months ended March 31, 2022 and 2021, ~~and 2020 include~~the cash receipts and disbursements were attributable to our normal operating cycle.See Results of Operations above for more information on the factors driving these changes.

Cash flows provided by (used in) investing activities

Net cash used in investing activities

~~Expenditures~~ for ~~development~~the three months ended March 31, 2022 was primarily driven by $300.1 million of acquisitions of oil and ~~natural~~ gas properties, ~~are the primary use~~partially offset by cash acquired of ~~our capital resources. The Company~~$44.3 million. Additionally, we spent ~~$28.7~~$260.7 million and ~~$26.2~~$28.7 million on the exploration and development of oil and gas properties during the three months ended March 31, ~~2021~~2022 and ~~2020,~~2021, respectively.

Cash flows ~~provided by~~used in financing activities

Net cash used in financing activities for the three months ended March 31, 2022 and 2021 ~~and 2020~~ was ~~$0.1~~$116.3 million and ~~$21.1~~$0.1 million, respectively. The change was primarily due to ~~a $21.0~~dividends paid totaling $103.6 million ~~decrease~~and the payment of employee tax withholdings in ~~net payments on our Credit Facility between~~exchange for the ~~comparable periods.~~return of common stock totaling $12.9 million.

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Non-GAAP Financial Measures

Adjusted EBITDAX represents earnings before interest, income taxes, depreciation, depletion, and amortization, exploration expense, and other non-cash and non-recurring charges. Adjusted EBITDAX excludes certain items that we believe affect the comparability of operating results and can exclude items that are generally non-recurring in nature or whose timing and/or amount cannot be reasonably estimated. Adjusted EBITDAX is a non-GAAP measure that we present because we believe it provides useful additional information to investors and analysts, as a performance measure, for analysis of our ability to internally generate funds for exploration, development, ~~and~~ acquisitions, and to service debt. We are also subject to financial covenants under our Credit Facility based on adjusted EBITDAX ratios as further described above in ~~Note 5 - Long-Term Debt~~Liquidity and Capital Resources ~~in Part I, Item I of this document.~~. In addition, adjusted EBITDAX is widely used by professional research analysts and others in the valuation, comparison, and investment recommendations of companies in the oil and gas exploration and production industry. Adjusted EBITDAX should not be considered in isolation or as a substitute for net income, ~~income from operations,~~ net cash provided by operating activities, or other profitability or liquidity measures prepared under GAAP. Because adjusted EBITDAX excludes some, but not all items that affect net income ~~(loss)~~ and may vary among companies, the adjusted EBITDAX amounts presented may not be comparable to similar metrics of other companies.

~~Table of~~ ~~Contents~~

The following table presents a reconciliation of the GAAP financial measure of net income to the non-GAAP financial measure of ~~Adjusted~~adjusted EBITDAX (in thousands):


		Three Months Ended March 31,					Three Months Ended March 31,
		2021		2020					2022		2021
Net income (loss)	Net income (loss)	$	(119)	$	78,551			Net income (loss)	$	91,639	$	(119)
Exploration	Exploration	96		373				Exploration	528		96
Depreciation, depletion, and amortization	Depreciation, depletion, and amortization	18,823		21,584				Depreciation, depletion, and amortization	184,860		18,823
Abandonment and impairment of unproved properties	Abandonment and impairment of unproved properties	—		30,057				Abandonment and impairment of unproved properties	17,975		—
Stock-based compensation (1)	Stock-based compensation (1)	1,612		1,239				Stock-based compensation(1)	8,090		1,612
Severance costs (1)		—		413
Non-recurring general and administrative expense(1)								Non-recurring general and administrative expense(1)	2,886		—
Merger transaction costs	Merger transaction costs	3,295		—				Merger transaction costs	20,534		3,295

Interest expense, net		419		217

Derivative (gain) loss		23,419		(100,419)
Derivative cash settlements gain (loss)		(3,791)		11,254
Income tax benefit		(44)		—
Unused commitments								Unused commitments	776		—
Gain on property transactions, net								Gain on property transactions, net	(16,797)		—
Interest expense								Interest expense	9,066		419
Derivative loss								Derivative loss	295,493		23,419
Derivative cash settlements loss								Derivative cash settlements loss	(166,578)		(3,791)
Income tax (benefit) expense								Income tax (benefit) expense	23,361		(44)
Adjusted EBITDAX	Adjusted EBITDAX	$	43,710	$	43,269			Adjusted EBITDAX	$	471,833	$	43,710
_____________________________
_______________________________								_______________________________
(1) Included as a portion of general and administrative expense in the accompanying statements of operations.	(1) Included as a portion of general and administrative expense in the accompanying statements of operations.					(1) Included as a portion of general and administrative expense in the accompanying statements of operations.

New Accounting Pronouncements

Please refer to Note ~~2 —~~1 - Summary of Significant Accounting Policies, Basis of Presentationunder Part I, Item 1 of this report and Note 2 - Basis of Presentation in the 2021 Form 10-Kfor any recently issued or adopted accounting standards.

Critical Accounting Policies and Estimates

Information regarding our critical accounting policies and estimates is contained in Part II, Item 7 of our ~~2020~~2021 Form ~~10-K.~~10-K. During the three months ended March 31, 2022, there were no significant changes in the application of critical accounting policies.

Material Commitments

There have been no significant changes from our ~~2020~~2021 Form 10-K in our obligations and commitments, other than what is disclosed within ~~Note 3 - Leases~~,Item1, Note 6 - Commitments and Contingencies, and Item 1, Note 13 - ~~Subsequent Events~~Leases ~~under Part I, Item 1~~ of this report.

~~Cautionary Note Regarding Forward-Looking Statements~~

This Quarterly Report on Form 10-Q contains various statements, including those that express belief, expectation, or intention, as well as those that are not statements of historic fact, that are forward-looking statements within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities and Exchange Act of 1934, as amended (the “Exchange Act”). When used in this Quarterly Report on Form 10-Q, the words “could,” “believe,” “anticipate,” “intend,” “estimate,” “expect,” “may,” “continue,” “predict,” “potential,” “project,” “plan,” “will,” and similar expressions are intended to identify forward-looking statements, although not all forward-looking statements contain such identifying words. These forward-looking statements are based on management's current belief, based on currently available information, as to the outcome and timing of future events.

~~Forward-looking statements include statements related to, among other things:~~

•~~the Company's business strategies;~~

•~~reserves estimates;~~

•~~estimated sales volumes;~~

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•~~amount and allocation of forecasted capital expenditures and plans for funding capital expenditures and operating expenses;~~

•~~ability to modify future capital expenditures;~~

•~~anticipated costs;~~

•~~compliance with debt covenants;~~

•~~ability to fund and satisfy obligations related to ongoing operations;~~

•~~compliance with government regulations, including environmental, health, and safety regulations and liabilities thereunder;~~

•~~adequacy of gathering systems and continuous improvement of such gathering systems;~~

•~~impact from the lack of available gathering systems and processing facilities in certain areas;~~

•~~impact of any pandemic or other public health epidemic, including the ongoing COVID-19 pandemic;~~

•~~natural gas, oil, and natural gas liquid prices and factors affecting the volatility of such prices;~~

•~~impact of lower commodity prices;~~

•~~sufficiency of impairments;~~

•~~the ability to use derivative instruments to manage commodity price risk and ability to use such instruments in the future;~~

•~~our drilling inventory and drilling intentions;~~

•~~impact of potentially disruptive technologies;~~

•~~our estimated revenue gains and losses;~~

•~~the timing and success of specific projects;~~

•~~our implementation of standard and long reach laterals;~~

•~~our use of multi-well pads to develop the Niobrara and Codell formations;~~

•~~intention to continue to optimize enhanced completion techniques and well design changes;~~

•~~stated working interest percentages;~~

•~~management and technical team;~~

•~~outcomes and effects of litigation, claims, and disputes;~~

•~~primary sources of future production growth;~~

•~~full delineation of the Niobrara B, C, and Codell benches in our legacy, French Lake, and northern acreage;~~

•~~our ability to replace oil and natural gas reserves;~~

•~~our ability to convert proved undeveloped reserves to producing properties within five years of their initial proved booking;~~

•~~impact of recently issued accounting pronouncements;~~

•~~impact of the loss a single customer or any purchaser of our products;~~

•~~timing and ability to meet certain volume commitments related to purchase and transportation agreements;~~

•~~the impact of customary royalty interests, overriding royalty interests, obligations incident to operating agreements, liens for current taxes, and other industry-related constraints;~~

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•~~our financial position;~~

•~~our cash flow and liquidity;~~

•~~the adequacy of our insurance;~~

•the results, effects, benefits, and synergies of the HighPoint Acquisition, future opportunities for the combined company, other plans and expectations with respect to the HighPoint Acquisition, and the anticipated impact of the HighPoint Acquisition on the combined company’s results of operations, financial position, growth opportunities, and competitive position; and

•~~other statements concerning our operations, economic performance, and financial condition.~~

~~Factors that could cause actual results to differ materially include, but are not limited to, the following:~~

•~~the risk factors discussed in Part I, Item 1A of our Annual Report on Form 10-K for the year ended December 31, 2020 and in Part II, Item 1A of this report;~~

•~~further declines or volatility in the prices we receive for our oil, natural gas liquids, and natural gas;~~

•~~general economic conditions, whether internationally, nationally or in the regional and local market areas in which we do business;~~

•~~the effects of disruption of our operations or excess supply of oil and natural gas due to the COVID-19 pandemic and the actions by certain oil and natural gas producing countries;~~

•~~the scope, duration and severity of the COVID-19 pandemic, including any recurrence, as well as the timing of the economic recovery following the pandemic;~~

•~~ability of our customers to meet their obligations to us;~~

•~~our access to capital;~~

•~~our ability to generate sufficient cash flow from operations, borrowings, or other sources to enable us to fully develop our undeveloped acreage positions;~~

•~~the presence or recoverability of estimated oil and natural gas reserves and the actual future sales volume rates and associated costs;~~

•~~uncertainties associated with estimates of proved oil and gas reserves;~~

•~~the possibility that the industry may be subject to future local, state, and federal regulatory or legislative actions (including additional taxes and changes in environmental regulation);~~

•~~environmental risks;~~

•~~seasonal weather conditions;~~

•~~lease stipulations;~~

•~~drilling and operating risks, including the risks associated with the employment of horizontal drilling and completion techniques;~~

•~~our ability to acquire adequate supplies of water for drilling and completion operations;~~

•~~availability of oilfield equipment, services, and personnel;~~

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•~~exploration and development risks;~~

•~~operational interruption of centralized gas and oil processing facilities;~~

•~~competition in the oil and natural gas industry;~~

•~~management’s ability to execute our plans to meet our goals;~~

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

•~~our ability to maintain effective internal controls;~~

•~~access to adequate gathering systems and pipeline take-away capacity;~~

•~~costs and other risks associated with perfecting title for mineral rights in some of our properties;~~

•~~continued hostilities in the Middle East, South America, and other sustained military campaigns or acts of terrorism or sabotage; and~~

•~~other economic, competitive, governmental, legislative, regulatory, geopolitical, and technological factors that may negatively impact our businesses, operations, or pricing.~~

All forward-looking statements speak only as of the date of this report. We disclaim any obligation to update or revise these statements unless required by law, and you should not place undue reliance on these forward-looking statements. Although we believe that our plans, intentions, and expectations reflected in or suggested by the forward-looking statements we make in this report are reasonable, we can give no assurance that these plans, intentions, or expectations will be achieved. We disclose important factors that could cause our actual results to differ materially from our expectations under Part II, Item 1A. ~~Risk Factors~~ ~~and Part I, Item 2.~~ ~~Management’s Discussion and Analysis of Financial Condition and Results of Operations~~ ~~and elsewhere in this report. These cautionary statements qualify all forward-looking statements attributable to us or persons acting on our behalf.~~

Item 3. Quantitative and Qualitative Disclosures About Market Risk.

Oil and Natural Gas Price Risk

Our financial condition, results of operations, and capital resources are highly dependent upon the prevailing market prices of oil and natural gas. These commodity prices are subject to wide fluctuations and market uncertainties due to a variety of factors that are beyond our control. Factors influencing oil and natural gas prices include the level of global demand for oil and natural gas, the global supply of oil and natural gas, the establishment of and compliance with production quotas by oil exporting countries, weather conditions which determine the demand for natural gas, the price and availability of alternative fuels, local and global politics, and overall economic conditions. It is impossible to predict future oil and natural gas prices with any degree of certainty. Sustained weakness in oil and natural gas prices may adversely affect our financial condition and results of operations, and may also reduce the amount of oil and natural gas reserves that we can produce economically. Any reduction in our oil and natural gas reserves, including reductions due to price fluctuations, can have an adverse effect on our ability to obtain capital for our exploration and development activities. Similarly, any improvements in oil and natural gas prices can have a favorable impact on our financial condition, results of operations, and capital resources.

Commodity Price Derivative Contracts

Our primary commodity risk management objective is to protect the Company’s balance sheet via the reduction in cash flow volatility. We enter into derivative contracts for oil, natural gas, and natural gas liquids using NYMEX futures or over-the-counter derivative financial instruments. The types of derivative instruments that we use include swaps, collars, and puts.

Upon settlement of the contract(s), if the relevant market commodity price exceeds our contracted swap price, or the collar’s ceiling strike price, we are required to pay our counterparty the difference for the volume of production associated with the contract. Generally, this payment is made up to 15 business days prior to the receipt of cash payments from our customers. This could have an adverse impact on our cash flows for the period between derivative settlements and payments for revenue earned.

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While we may reduce the potential negative impact of lower commodity prices, we may also be prevented from realizing the benefits of favorable ~~commodity~~ price ~~changes.~~changes in the physical market.

Presently, our derivative contracts have been executed with ~~seven~~10 counterparties, all of which are members of our Credit Facility syndicate. We enter into contracts with counterparties whom we believe are well capitalized. However, if our counterparties fail to perform their obligations under the contracts, we could suffer financial loss.

Please refer to the Note 109 - Derivativesin Part I, Item 1 of this report for summary derivative activity tables.

Interest Rates

~~As of~~At March 31, ~~2021~~2022 and on the filing date of this report, we had a zero ~~and $129.0 million, respectively, outstanding under~~balance on our Credit Facility. Borrowings under our Credit Facility bear interest at a fluctuating rate that is tied to an adjusted Base Rate or LIBOR, at our option. Any increases in these interest rates can have an adverse impact on our results of operations and cash ~~flow.~~flows. As of March 31, ~~2021,~~2022 and through the filing date of this report, the Company was in compliance with all financial and non-financial ~~covenants in the Credit Facility.~~covenants.

Counterparty and Customer Credit Risk

In connection with our derivatives activity, we have exposure to financial institutions in the form of derivative transactions. ~~Seven~~Presently, our derivative contracts have been executed with 10 counterparties, all of which are members of our Credit Facility ~~syndicate are~~syndicate. All counterparties on our derivative instruments currently in place ~~and currently~~ have investment grade credit ratings.

We are also subject to credit risk due to concentration of our oil and natural gas receivables with certain significant customers. The inability or failure of our significant customers to meet their obligations to us or their insolvency or liquidation may adversely affect our financial results. We review the credit rating, payment history, and financial resources of our customers, but we do not require our customers to post collateral.

Marketability of Our Production

The marketability of our production depends in part upon the availability, proximity, and capacity of third-party refineries, access to regional trucking, pipeline and rail infrastructure, natural gas gathering systems, and processing facilities. We deliver crude oil and natural gas produced through trucking services, pipelines, and rail facilities that we do not own. The lack of availability or capacity on these systems and facilities could reduce the price offered for our production or result in the shut-in of producing wells or the delay or discontinuance of development plans for properties.

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A portion of our production may also be interrupted, or shut in, from time to time for numerous other reasons, including as a result of accidents, weather, or field labor issues or strikes, or we might voluntarily curtail production in response to market conditions. If a substantial amount of our production is interrupted at the same time, it could adversely affect our cash flow.

Currently, there are no pipeline systems that service wells in our French Lake area of the Wattenberg Field. If neither we nor a third-party constructs the required pipeline system, we may not be able to fully test or develop our resources in French Lake.

~~There have not been material changes to the interest rate risk analysis or oil and gas price sensitivity analysis disclosed in our Annual Report on Form 10-K for the year ended December 31, 2020.~~

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Item 4. Controls and Procedures.

Evaluation of Disclosure Controls and Procedures

Our management, with the participation of our principal executive officer and principal financial officer, evaluated the effectiveness of our disclosure controls and procedures as of March 31, ~~2021.~~2022. The term “disclosure controls and procedures,” as defined in Rules 13a-15(e) and 15d-15(e) under the Exchange Act, means controls and other procedures of a company that are designed to ensure that information required to be disclosed by a company in the reports that it files or submits under the Exchange Act is recorded, processed, summarized, and reported, within the time periods specified in SEC rules and forms. Disclosure controls and procedures include, without limitation, controls and procedures designed to ensure that information required to be disclosed by a company in the reports that it files or submits under the Exchange Act is accumulated and communicated to the company’s management, including its principal executive and principal financial officers and internal audit function, as appropriate, to allow timely decisions regarding required disclosure. Based on the evaluation of our disclosure controls and procedures as of March 31, ~~2021,~~2022, our principal executive officer and principal financial officer concluded that, as of such date, our disclosure controls and procedures were effective at the reasonable assurance level.

Management recognizes that any controls and procedures, no matter how well designed and operated, can provide only reasonable assurance of achieving their objectives, and management necessarily applies its judgment in evaluating the cost-benefit relationship of possible controls and procedures. To assist management, we have established an internal audit function to verify and monitor our internal controls and procedures. The Company’s internal control system is supported by written policies and procedures, contains self-monitoring mechanisms, and is audited by the internal audit function. Appropriate actions are taken by management to correct deficiencies as they are identified.

Changes in Internal Control over Financial Reporting

There were no changes in our internal control over financial reporting identified in management’s evaluation pursuant to Rules 13a-15(d) or 15d-15(d) of the Exchange Act during the quarter ended March 31, ~~2021~~2022 that materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

PART II. OTHER INFORMATION

~~PART II~~-~~OTHER INFORMATION~~

Item 1. Legal Proceedings.

From time to time, we are subject to legal proceedings and claims that arise in the ordinary course of business. Like other oil and gas producers and marketers, our operations are subject to extensive and rapidly changing federal and state environmental, health, and safety and other laws and regulations governing air emissions, wastewater discharges, and solid and hazardous waste management activities. Upon closing of the HighPoint Acquisition, the Company assumed all obligations, whether asserted or unasserted, of HighPoint Resources Corporation. As of the date of this filing, there were no probable, material pending or overtly threatened legal actions against us of which we were aware, other than the following:

On June 15, 2020, Sterling filed a complaint against HighPoint OpCo, a subsidiary of HighPoint Resources Corporation, for breach of contract related to a Gas Purchase Agreement dated effective November 1, 2017. Sterling alleges that HighPoint OpCo breached the contract by failing to use reasonable commercial efforts to deliver to Sterling at Sterling’s receipt points all quantities of gas not otherwise dedicated to other gas purchase agreements. Sterling seeks monetary damages in an amount not yet specified. On July 31, 2020, the HighPoint Resources Corporation filed a counterclaim against Sterling for breach of Sterling’s obligations under the Gas Purchase Agreement. Upon closing of the HighPoint Acquisition, the Company assumed all legal proceedings of HighPoint Resources Corporation, inclusive of this complaint. The Company continues to vigorously deny Sterling’s claims and is seeking monetary damages in an amount not yet specified. The case is scheduled to go to trial in July 2021. At this time the Company is unable to determine whether any loss is probable or reasonably estimate a range of such loss, and accordingly has not recognized any liability associated with this matter.

Disclosure of certain environmental matters is required when a governmental authority is a party to the proceedings and the proceedings involve potential monetary sanctions that we reasonably believe could exceed $300,000. HighPoint Resources Corporation received NOAV from the COGCC alleging violations of various Colorado statutes and COGCC regulations governing oil and gas operations. The Company continues to engage in discussionsInformation regarding resolution of the alleged violations. The Company recognized approximately $1.3 million upon acquiring HighPoint Resources Corporation associated with the NOAVs, as they are probable and reasonably estimable.

~~There have been no other material changes to~~ our legal proceedings ~~from those described~~can be found in ~~our Annual Report on Form 10-K for the year ended December 31, 2020.~~Note 6 - Commitments and Contingencies of Part I, Item 1 of this report.

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Item 1A. Risk Factors.

Our business faces many risks. Any of the risk factors discussed in this report or our other SEC filings could have a material impact on our business, financial position, or results of operations. Additional risks and uncertainties not presently known to us or that we currently believe to be immaterial may also impair our business operation. For a discussion of our potential risks and uncertainties, see the risk factors in Part I, Item 1A in our Annual Report on Form 10-K for the year ended December 31, ~~2020,~~2021, together with other information in this report and other reports and materials we file with the SEC. We have identified these risk factors as important factors that could cause our actual results to differ materially from those contained in any written or oral forward-looking statements made by us or on our behalf.

~~Risks Relating to the HighPoint Acquisition~~

~~We may not achieve the anticipated benefits of the HighPoint Acquisition.~~

The success of the HighPoint Acquisition will depend, in part, on our ability to realize the anticipated benefits and cost savings from combining our and HighPoint’s businesses, and there can be no assurance that we will be able to successfully integrate HighPoint or otherwise realize the anticipated benefits of the HighPoint Acquisition. Difficulties in integrating HighPoint into our Company may result in the combined company performing differently than expected, in operational challenges or in the failure to realize anticipated expense-related efficiencies. Potential difficulties that may be encountered in the integration process include, among others:

•~~the inability to successfully integrate HighPoint into our Company in a manner that permits us to achieve the anticipated benefits and cost savings from the HighPoint Acquisition;~~

•~~complexities associated with managing a larger, more complex, integrated business;~~

•~~not realizing anticipated operating synergies;~~

•~~integrating personnel from the two companies;~~

•~~potential unknown liabilities and unforeseen expenses associated with the HighPoint Acquisition;~~

•~~integrating relationships with customers, vendors and business partners;~~

•~~performance shortfalls as a result of the diversion of management’s attention caused by the HighPoint Acquisition and the integration of HighPoint’s operations into our Company;~~

•~~managing expanded environmental and other regulatory compliance obligations related to HighPoint's facilities and operations;~~

•~~consolidating information technology systems; and~~

•~~the disruption of, or the loss of momentum in, our business or inconsistencies in standards, controls, procedures and policies.~~

~~Our results may suffer if we do not effectively manage our expanded operations following the HighPoint Acquisition.~~

Following completion of the HighPoint Acquisition, the size of our business has increased significantly. Our future success will depend, in part, on our ability to manage this expanded business, which poses numerous risks and uncertainties, including the need to integrate the operations and business of HighPoint into our existing business in an efficient and timely manner, to combine systems and management controls and to integrate relationships with various business partners. Failure to successfully manage the combined company may have an adverse effect on our financial condition, results of operations or cash flows.

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Following the HighPoint Acquisition, we are proportionately more exposed to regulatory and operational risks associated with oil and gas operations in Colorado and other risks associated with a more geographically-concentrated asset base.

Substantially all of HighPoint’s properties, production and reserves immediately prior to the HighPoint Acquisition were located in Colorado. As a result of the HighPoint Acquisition, the amount of our properties, production and reserves that are located in Colorado have increased and our exposure to the risk of unfavorable regulatory developments in the state have therefore increased as well. The increase of our combined production located in the Wattenberg Field following the HighPoint Acquisition has proportionately increased our exposure to this risk, as well as other risks associated with operating in a more concentrated geographic area.

~~The market price of our common stock will continue to fluctuate, and may decline if the benefits of the HighPoint Acquisition do not meet the expectations of financial analysts.~~

The market price of our common stock may fluctuate significantly, including if we do not achieve the anticipated benefits of the HighPoint Acquisition as rapidly, or to the extent anticipated by, financial analysts or if the effect of the HighPoint Acquisition on our financial results is not consistent with the expectations of financial analysts.

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

Unregistered sales of securities. There were no sales of unregistered equity securities during the three month period ended March 31, ~~2021.~~2022.

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Issuer ~~purchases~~Purchases of ~~equity securities~~Equity Securities.. The following table contains information about ~~acquisitions~~our acquisition of ~~our~~ equity securities during the three ~~month period~~months ended March 31, ~~2021:~~2022.

Total Number of Shares Maximum Number of
Total Number Purchased as Part of Shares that May Be
of Shares Average Price Publicly Announced Purchased Under Plans
Purchased(1)
Paid per Share Plans or Programs or Programs
January 1, 2021 - January 31, 2021 — $ — — —
February 1, 2021 - February 28, 2021 — $ — — —
March 1, 2021 - March 31, 2021 38 $ 34.70 — —
Total 38 $ 34.70 — —


				Total Number of Shares	Maximum Number of
	Total Number			Purchased as Part of	Shares that May Be
	of Shares	Average Price		Publicly Announced	Purchased Under Plans
	Purchased(1)	Paid per Share		Plans or Programs	or Programs
January 1, 2022 - January 31, 2022	149,126	$	54.92	—	—
February 1, 2022 - February 28, 2022	66,685	$	52.07	—	—
March 1, 2022 - March 31, 2022	—	$	—	—	—
Total	215,811	$	54.56	—	—

~~_____________________________~~_________________________

(1)~~Represents~~Represent shares that employees surrendered back to us that equaled in value the amount of taxes ~~required~~needed for payroll tax withholding obligations upon the vesting of ~~equity awards under the LTIP.~~restricted stock awards. These repurchases were not part of a publicly announced plan or program to repurchase shares of our common stock, nor do we have a publicly announced plan or program to repurchase shares of our common stock.

~~Our~~Dividend Policy. On May 3, 2021, we announced the initiation of an annual cash dividend in the amount of $1.40 per share of our common stock payable quarterly, which began on July 14, 2021. Beginning with the fourth quarter of 2021, the annual cash dividend was increased to $1.85 per share of our common stock, and, in March 2022, the Board approved the initiation of a quarterly variable cash dividend, equal to 50% of free cash flow after the fixed cash dividend for the preceding twelve-month period and pro forma for all acquisition and divestiture activity, assuming pro forma compliance with certain leverage targets. The Company’s inaugural quarterly variable cash dividend has been declared at $0.75 per share and was paid in combination with the fixed cash dividend on March 30, 2022 to shareholders of record on March 18, 2022, resulting a total quarterly dividend of $1.2125 per share. The decision to pay any future dividends is solely within the discretion of, and subject to approval by, the Board. The Board's’ determination with respect to any such dividends, including the record date, the payment date and the actual amount of the dividend, will depend upon our profitability and financial condition, contractual restrictions, restrictions imposed by applicable law and other factors that the Board deems relevant at the time of such determination. Additionally, covenants contained in our Credit Facility ~~contains restrictions on~~and the indentures governing our senior notes restrict the payment of ~~dividends.~~cash dividends on our common stock, as discussed further in Note 5 - Long-Term Debt under Part I, Item 1 of this report.

Item 3. Defaults Upon Senior Securities.

None.

Item 4. Mine Safety Disclosures.

Not applicable.

Item 5. Other Information.

None.

3642

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Item 6. Exhibits.


Exhibit ~~No.~~	Number	Description ~~of Exhibit~~

~~2.1~~		Agreement and Plan of Merger, dated as of November 9, 2020, by and among Bonanza Creek Energy, Inc., HighPoint Resources Corporation and Boron Merger Sub, Inc. (incorporated by reference to Exhibit 2.1 to Bonanza Creek Energy, Inc.’s Current Report on Form 8-K filed on November 9, 2020).

3.1		Third Amended and Restated Certificate of Incorporation of Bonanza Creek Energy, Inc. (incorporated by reference to Exhibit 3.1 to Bonanza Creek Energy, Inc.’s Registration Statement on Form 8-A filed on April 28, ~~2017)~~2017 ).

3.2		~~Fourth~~Certificate of Amendment to the Third Amended and Restated ~~Bylaws~~Certificate of Incorporation of Bonanza Creek Energy, Inc. (incorporated by reference to Exhibit ~~3.2~~3.1 to ~~Bonanza Creek Energy, Inc.’s Registration Statement~~the Company’s Current Report on Form ~~8-A~~8-K filed on ~~April 28, 2017)~~November 3, 2021).

~~4.1~~3.3	Fifth Amended and Restated Bylaws of Civitas Resources, Inc. (incorporated by reference to Exhibit 3.2 to Civitas Resources, Inc.’s Current Report on Form 8-K, File No. 001-35371, filed on November 3, 2021).
3.4	~~Indenture,~~Certificate of Elimination of Series A Junior Participating Preferred Stock of Civitas Resources, Inc. (incorporated by reference to Exhibit 3.3 to Civitas Resources, Inc.’s Current Report on Form 8-K filed on November 3, 2021).
10.1 *	Civitas Resources, Inc. Eighth Amended and Restated Executive Change in Control and Severance Benefit Plan (incorporated by reference to Exhibit 10.1 to Civitas Resources, Inc.’s Current Report on Form 8-K filed on January 25, 2022).
10.2	Membership Interest Purchase Agreement, dated as of ~~April 1, 2021,~~January 31, 2022, by and among ~~Bonanza Creek Energy,~~Civitas Resources, Inc., ~~U.S. Bank National Association, as trustee,~~Bison Oil & Gas Partners II, LLC, and ~~the subsidiary guarantors party thereto~~Bison Oil & Gas II, LLC (incorporated by reference to Exhibit 10.1 to Civitas Resources, Inc.’s Current Report on Form 8-K filed on February 1, 2022).
10.3	First Amendment to Membership Interest Purchase Agreement, dated as of February 27, 2022, by and among Civitas Resources, Inc., Bison Oil & Gas Partners II, LLC, and Bison Oil & Gas II, LLC. (incorporated by reference to Exhibit 10.1 to Civitas Resources, Inc.’s Current Report on Form 8-K filed on March 2, 2022).
10.4	.1Severance, Release and Consulting Agreement, dated January 31, 2022 (incorporated by reference to ~~Bonanza Creek Energy,~~Exhibit 10.2 to Civitas Resources, Inc.’s Current Report on Form 8-K filed on February 1, 2022).
10.5†	Form of Performance Stock Unit Agreement (Absolute TSR) under the Civitas Resources, Inc. 2021 Long Term Incentive Plan.
10.6†	Form of Performance Stock Unit Agreement (Relative TSR) under the Civitas Resources, Inc. 2021 Long Term Incentive Pla n.
10.7†	Form of Restricted Stock Unit Agreement under the Civitas Resources, Inc. 2021 Long Term Incentive Plan.
10.8	Second Amendment to Amended and Restated Credit Agreement, among Civitas Resources, Inc., the guarantors party thereto, the lenders party thereto and JPMorgan Chase Bank, N.A., as the administrative agent (incorporated by reference to Exhibit 10.1 to Civitas Resources, Inc.’s Current Report on Form 8-K filed on April ~~1, 2021)~~21, 2022).

~~4.2~~31.1†		First Supplemental Indenture, dated as of April 1, 2021, by and among Bonanza Creek Energy, Inc., U.S. Bank National Association, as trustee, HighPoint Resources Corporation, HighPoint Operating Corporation and Fifth Pocket Productions, LLC (incorporated by reference to Exhibit 4.2 to Bonanza Creek Energy, Inc.'s Current Report on Form 8-K filed on April 1, 2021).

~~4.3~~		~~Confirmation Order, filed March 18, 2021 (incorporated by reference to Exhibit 99.1 to Bonanza Creek Energy, Inc.’s Current Report on Form 8-K filed on March 22, 2021).~~

~~10.1~~		Second Amendment to Credit Agreement, dated as of April 1, 2021, between Bonanza Creek Energy, Inc., JPMorgan Chase Bank, N.A., as the administrative agent, and a syndicate of financial institutions, as lenders ~~(incorporated by reference to Exhibit~~ ~~10.1~~ ~~to Bonanza Creek Energy, Inc.’s~~ ~~Current Report on Form 8-K filed~~ o ~~n April~~ 1 ~~, 20~~21 ).

~~10.2~~		~~Registration Rights Agreement, dated April 1, 2021, between Bonanza Creek Energy, Inc., and Franklin Advisers, Inc. (incorporated by reference to Exhibit 10.~~2 ~~to Bonanza Creek Energy, Inc.’s Current Report on Form 8-K filed on April 1, 2021).~~

31.1*		Certification of the ~~Principal~~Chief Executive Officer pursuant to Rule 13a-14(a).

31.2*31.2†		Certification of the ~~Principal~~Chief Financial Officer pursuant to Rule 13a-14(a).

32.1**32.1†		Certification of the ~~Principal~~Chief Executive Officer pursuant to ~~18.U.S.C.~~18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 (furnished herewith).

32.2**32.2†		Certification of the ~~Principal~~Chief Financial Officer pursuant to ~~18.U.S.C.~~18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 (furnished herewith).

101.INS*101.INS†		XBRL Instance Document
101.SCH†
101.SCH*		XBRL Taxonomy Extension Schema

101.CAL*	101.CAL†	XBRL Taxonomy Extension Calculation Linkbase
101.DEF†
101.DEF*		XBRL Taxonomy Extension Definition Linkbase
101.LAB†
101.LAB*		XBRL Taxonomy Extension Label Linkbase

101.PRE*	101.PRE†	XBRL Taxonomy Extension Presentation Linkbase

104		Cover Page Interactive Data File (formatted as Inline XBRL)
~~__________________________________________~~
*	~~Filed with this report~~

**	~~Furnished with this report~~

†	~~Management Contract or Compensatory Plan or Agreement~~

_________________________

* Management Contract or Compensatory Plan or Arrangement

† Filed or furnished herewith

3743

Table of Contents

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.

~~BONANZA CREEK ENERGY,~~CIVITAS RESOURCES, INC.

Date:

May ~~3, 2021~~4, 2022

By:

/s/ ~~Eric T. Greager~~Chris Doyle

~~Eric T. Greager~~Chris Doyle

President and Chief Executive Officer

~~(principal~~ (principal executive officer)

By:

/s/ ~~Brant DeMuth~~Marianella Foschi

~~Brant DeMuth~~Marianella Foschi

~~Executive Vice President and~~ Chief Financial Officer

~~(principal~~ (principal financial officer)

By:

/s/ Sandi K. Garbiso

Sandi K. Garbiso

~~Vice President and~~ Chief Accounting Officer

~~(chief~~ and Treasurer (chief accounting officer)

3844


	As of March 31,
	2021		2020
Cash and cash equivalents	$	38,695	$	11,052
Restricted cash(1)	102		95
Total cash, cash equivalents, and restricted cash	$	38,797	$	11,147


	Operating Leases		Finance Leases(1)
Remainder of 2021	$	10,151	$	96
2022	10,448		0
2023	6,430		0
2024	2,471		0
2025	139		0
Thereafter	5		0
Total lease payments	29,644		96
Less: imputed interest	(1,401)		0
Total lease liability	$	28,243	$	96



	As of March 31, 2021		As of December 31, 2020
Accrued drilling and completion costs	$	4,824	$	453
Accounts payable trade	14,006		1,931
Accrued general and administrative expense	3,306		7,529
Accrued lease operating expense	1,936		1,793
Accrued interest expense	329		322
Accrued oil and gas hedging	2,036		0
Accrued production and ad valorem taxes and other	13,170		25,397
Total accounts payable and accrued expenses	$	39,607	$	37,425


	NGL Crude Commitments(1)
Remainder of 2021	$	17,571
2022	23,097
2023	4,202
2024	0
2025	0
2026 and thereafter	0
Total	$	44,870


	Unrecognized Compensation Expense		Final Year of Recognition
Restricted stock units	$	6,469	2023
Performance stock units	1,489		2022
	$	7,958


	Performance Stock Units(1)	Weighted-Average Grant-Date Fair Value
Non-vested, beginning of year	185,588	$	22.63
Granted	0	0
Vested	0	0
Forfeited	0	0
Non-vested, end of quarter	185,588	$	22.63


	Stock Options	Weighted-Average Exercise Price		Weighted-Average Remaining Contractual Term (in years)	Aggregate Intrinsic Value (in thousands)
Outstanding, beginning of year	72,368	$	34.36	0	0
Granted	0	0
Exercised	(429)	34.36
Forfeited	(222)	34.36
Outstanding, end of quarter	71,717	$	34.36	6.1	$	98
Number of options outstanding and exercisable	71,717	$	34.36	6.1	$	98


	Crude Oil (NYMEX WTI)		Natural Gas (NYMEX Henry Hub)		Natural Gas (CIG Basis)		Natural Gas (CIG)
	Bbls/day	Weighted Avg. Price per Bbl	MMBtu/day	Weighted Avg. Price per MMBtu	MMBtu/day	Weighted Avg. Basis Differential to CIG Price per MMBtu	MMBtu/day	Weighted Avg. Price per MMBtu
2Q21
Cashless Collar	2,500	$34.40/$49.82	20,000	$2.25/$2.52	—	—	—	—
Swap	4,000	$54.13	—	—	20,000	$0.43	—	—
3Q21
Cashless Collar	3,000	$30.00/$50.62	20,000	$2.25/$2.52	—	—	20,000	$2.15/$2.75
Swap	2,500	$54.45	—	—	20,000	$0.43	—	—
4Q21
Cashless Collar	4,000	$30.63/$50.34	20,000	$2.25/$2.52	—	—	20,000	$2.15/$2.75
Swap	1,000	$55.20	—	—	20,000	$0.43	—	—
1Q22
Cashless Collar	5,000	$33.64/$54.96	—	—	—	—	20,000	$2.15/$2.75

2Q22
Cashless Collar	3,500	$35.19/$58.86	—	—	—	—	20,000	$2.15/$2.75
3Q22
Cashless Collar	2,000	$37.84/$61.19	—	—	—	—	—	—
4Q22
Cashless Collar	1,500	$38.78/$63.33	—	—	—	—	—	—