Civitas Resources 10Q 2022 Q3 Quarterly report

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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 September 30, 2022

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

For the transition period from _________ to _________

Commission File Number: 001-35371

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.)

555 17th Street,

Suite 3700

Denver,

Colorado

80202

(Address of principal executive offices)

(Zip Code)

(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	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

☐

Smaller reporting company

☐

Emerging growth company

☐

If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 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

As of October 28, 2022, the registrant had 85,110,799 shares of common stock outstanding.

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CIVITAS RESOURCES, INC.

FORM 10-Q

FOR THE QUARTER ENDED SEPTEMBER 30, 2022

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PAGE

Part I.

Financial Information

Item 1.

Financial Statements (Unaudited)

Condensed Consolidated Balance Sheets as of September 30, 2022 and December 31, 2021

Condensed Consolidated Statements of Operations and Comprehensive Income for the Three and Nine Months Ended September 30, 2022 and 2021

Condensed Consolidated Statements of Stockholders' Equity for the Three and Nine Months Ended September 30, 2022 and 2021

Condensed Consolidated Statements of Cash Flows for the Nine Months Ended September 30, 2022 and 2021

Notes to the Condensed Consolidated Financial Statements

Item 2.

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

Item 3.

Quantitative and Qualitative Disclosures About Market Risk

Item 4.

Controls and Procedures

Unregistered Sales of Equity Securities and Use of Proceeds

Item 3.

Defaults Upon Senior Securities

Item 4.

Mine Safety Disclosures

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 of 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 our recent mergers and acquisitions, future opportunities for the combined companies, other plans and expectations with respect to these transactions, and the anticipated impact of these transactions 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, 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, including any future economic downturn, the impact of inflation, disruption in the financial markets, and the availability of credit;

•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;

•the 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 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 other important factors that could cause our actual results to differ materially from our expectations under “Item 1A. Risk Factors” and other sections of our Annual Report on Form 10-K for the fiscal year ended December 31, 2021, as updated by subsequent reports we file with the SEC (including 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 1. Financial Statements.

CIVITAS RESOURCES, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED BALANCE SHEETS (UNAUDITED)

(in thousands, except per share amounts)


	September 30, 2022		December 31, 2021
ASSETS
Current assets:
Cash and cash equivalents	$	682,138	$	254,454
Accounts receivable, net:
Oil, natural gas, and NGL sales	337,946		362,262
Joint interest and other	101,401		66,390
Prepaid expenses and other	33,069		21,052
Inventory of oilfield equipment	27,488		12,386
Derivative assets	5,727		3,393
Total current assets	1,187,769		719,937
Property and equipment (successful efforts method):
Proved properties	6,538,973		5,457,213
Less: accumulated depreciation, depletion, and amortization	(1,010,340)		(430,201)
Total proved properties, net	5,528,633		5,027,012
Unproved properties	631,117		688,895
Wells in progress	251,779		177,296
Other property and equipment, net of accumulated depreciation of $6,715 in 2022 and $4,742 in 2021	49,764		51,639
Total property and equipment, net	6,461,293		5,944,842
Long-term derivative assets	2,764		—
Right-of-use assets	28,150		39,885
Deferred income tax assets	—		22,284
Other noncurrent assets	8,821		14,085
Total assets	$	7,688,797	$	6,741,033
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities:
Accounts payable and accrued expenses	$	288,720	$	246,188
Production taxes payable	282,893		144,408
Oil and natural gas revenue distribution payable	494,548		466,233
Lease liability	15,616		18,873
Derivative liability	144,176		219,804
Income tax payable	18,897		—
Asset retirement obligations	24,000		24,000
Total current liabilities	1,268,850		1,119,506
Long-term liabilities:
Senior notes	392,897		491,710

Lease liability	13,122		21,398
Ad valorem taxes	304,016		232,147
Derivative liability	32,916		19,959
Deferred income tax liabilities	221,904		—
Asset retirement obligations	201,567		201,315
Total liabilities	2,435,272		2,086,035
Commitments and contingencies (Note 6)
Stockholders’ equity:
Preferred stock, $.01 par value, 25,000,000 shares authorized, none outstanding	—		—
Common stock, $.01 par value, 225,000,000 shares authorized, 85,105,363 and 84,572,846 issued and outstanding as of September 30, 2022 and December 31, 2021, respectively	4,917		4,912
Additional paid-in capital	4,204,742		4,199,108
Retained earnings	1,043,866		450,978
Total stockholders’ equity	5,253,525		4,654,998
Total liabilities and stockholders’ equity	$	7,688,797	$	6,741,033

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

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CIVITAS RESOURCES, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS AND COMPREHENSIVE INCOME (UNAUDITED)

(in thousands, except per share amounts)


	Three Months Ended September 30,				Nine Months Ended September 30,
	2022		2021		2022		2021
Operating net revenues:
Oil, natural gas, and NGL sales	$	1,007,951	$	189,963	$	2,977,125	$	420,157
Operating expenses:
Lease operating expense	45,063		11,560		122,959		28,649
Midstream operating expense	9,214		3,163		22,395		11,314
Gathering, transportation, and processing	84,482		14,105		214,404		32,793
Severance and ad valorem taxes	85,029		9,205		234,203		23,622
Exploration	4,355		1,513		6,436		5,156
Depreciation, depletion, and amortization	212,070		35,604		601,449		89,433
Abandonment and impairment of unproved properties	—		—		17,975		2,215
Unused commitments	193		3,364		2,700		7,692
Bad debt expense (recovery)	(11)		279		(7)		279
Merger transaction costs	1,814		5,580		23,766		27,121
General and administrative expense (including $10,244, $2,289, $24,469, and $6,096, respectively, of stock-based compensation)	37,296		11,724		102,682		33,119
Total operating expenses	479,505		96,097		1,348,962		261,393
Other income (expense):
Derivative gain (loss)	9,281		(36,224)		(358,862)		(133,613)
Interest expense	(7,468)		(3,025)		(24,650)		(6,685)
Gain (loss) on property transactions, net	(938)		951		15,859		951
Other income	12,769		687		17,865		964
Total other income (expense)	13,644		(37,611)		(349,788)		(138,383)
Income from operations before income taxes	542,090		56,255		1,278,375		20,381
Income tax expense	(136,338)		(15,596)		(312,163)		(5,160)
Net income	$	405,752	$	40,659	$	966,212	$	15,221

Comprehensive income	$	405,752	$	40,659	$	966,212	$	15,221

Net income per common share:
Basic	$	4.77	$	1.32	$	11.37	$	0.55
Diluted	$	4.74	$	1.31	$	11.30	$	0.55
Weighted-average common shares outstanding
Basic	85,069		30,849		84,968		27,485
Diluted	85,554		31,138		85,495		27,839

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

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CIVITAS RESOURCES, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ EQUITY (UNAUDITED)

(in thousands, except per share amounts)


				Additional
	Common Stock			Paid-In		Retained
	Shares	Amount		Capital		Earnings		Total
Balances, December 31, 2021	84,572,846	$	4,912	$	4,199,108	$	450,978	$	4,654,998

Restricted common stock issued	579,229	6		—		—		6
Stock used for tax withholdings	(215,811)	(2)		(12,932)		—		(12,934)
Exercise of stock options	5,294	—		178		—		178
Stock-based compensation	—	—		8,090		—		8,090
Cash dividends, $1.2125 per share	—	—		—		(104,444)		(104,444)
Net income	—	—		—		91,639		91,639
Balances, March 31, 2022	84,941,558	4,916		4,194,444		438,173		4,637,533

Restricted common stock issued	130,309	1		—		—		1
Stock used for tax withholdings	(40,646)	—		(2,813)		—		(2,813)
Exercise of stock options	742	—		24		—		24
Stock-based compensation	—	—		6,135		—		6,135
Cash dividends, $1.3625 per share	—	—		—		(117,151)		(117,151)
Net income	—	—		—		468,821		468,821
Balances, June 30, 2022	85,031,963	4,917		4,197,790		789,843		4,992,550
Restricted common stock issued	125,381	1		—		—		1
Stock used for tax withholdings	(52,879)	(1)		(3,322)		—		(3,323)
Exercise of stock options	898	—		30		—		30
Stock-based compensation	—	—		10,244		—		10,244
Cash dividends, 1.7625 per share	—	—		—		(151,729)		(151,729)
Net income	—	—		—		405,752		405,752
Balances, September 30, 2022	85,105,363	$	4,917	$	4,204,742	$	1,043,866	$	5,253,525


Balances, December 31, 2020	20,839,227	$	4,282	$	707,209	$	333,761	$	1,045,252

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

Net loss	—	—		—		(119)		(119)
Balances, March 31, 2021	20,839,727	4,282		708,836		333,642		1,046,760
Issuance pursuant to acquisition	9,802,166	98		374,835		—		374,933
Restricted common stock issued	261,539	—		—		—		—
Stock used for tax withholdings	(70,330)	(2)		(2,814)		—		(2,816)
Exercise of stock options	11,523	—		394		—		394
Stock-based compensation	—	—		2,195		—		2,195
Dividends declared, $0.3500 per share	—	—		—		(11,033)		(11,033)
Net loss	—	—		—		(25,319)		(25,319)
Balances, June 30, 2021	30,844,625	4,378		1,083,446		297,290		1,385,114

Restricted common stock issued	5,987	—		—		—		—
Stock used for tax withholdings	(1,725)	—		(74)		—		(74)
Exercise of stock options	9,926	—		307		—		307
Stock-based compensation	—	—		2,289		—		2,289
Dividends declared, $0.3500 per share	—	—		—		(11,045)		(11,045)
Net income	—	—		—		40,659		40,659
Balances, September 30, 2021	30,858,813	$	4,378	$	1,085,968	$	326,904	$	1,417,250

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

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CIVITAS RESOURCES, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (UNAUDITED)

(in thousands)


	Nine Months Ended September 30,
	2022		2021
Cash flows from operating activities:
Net income	$	966,212	$	15,221
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, depletion, and amortization	601,449		89,433
Deferred income tax expense	239,766		5,368

Abandonment and impairment of unproved properties	17,975		2,215
Stock-based compensation	24,469		6,096
Amortization of deferred financing costs	3,319		963
Derivative loss	358,862		133,613
Derivative cash settlements loss	(492,120)		(50,536)
Gain on property transactions, net	(15,859)		(951)
Other	202		14
Changes in current assets and liabilities:
Accounts receivable, net	39,027		(17,050)
Prepaid expenses and other assets	(2,099)		2,244
Accounts payable and accrued liabilities	241,662		9,504
Settlement of asset retirement obligations	(18,002)		(3,891)
Net cash provided by operating activities	1,964,863		192,243
Cash flows from investing activities:
Acquisition of oil and natural gas properties	(374,769)		(620)
Cash acquired	44,310		49,827
Exploration and development of oil and natural gas properties	(708,958)		(104,207)
Purchases of carbon offsets	(7,196)		—

Additions to other property and equipment	(97)		(72)
Other	126		204
Net cash used in investing activities	(1,046,584)		(54,868)
Cash flows from financing activities:
Proceeds from credit facility	100,000		155,000
Payments to credit facility	(100,000)		(249,000)

Redemption of senior notes	(100,000)		—
Proceeds from exercise of stock options	232		716
Dividends paid	(370,591)		(21,598)
Payment of employee tax withholdings in exchange for the return of common stock	(19,062)		(2,890)
Deferred financing costs	(1,174)		(3,915)
Other	—		(21)
Net cash used in financing activities	(490,595)		(121,708)
Net change in cash, cash equivalents, and restricted cash	427,684		15,667
Cash, cash equivalents, and restricted cash:
Beginning of period(1)	254,556		24,845
End of period(1)	$	682,240	$	40,512
Supplemental cash flow disclosure:


Cash paid for interest	$	(17,124)	$	(1,684)
Cash paid for income taxes	$	(59,800)	$	—


Changes in working capital related to drilling expenditures	$	33	$	(22,175)
(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 September 30, 2022 and 2021.

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

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CIVITAS RESOURCES, INC. AND SUBSIDIARIES

NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED)

NOTE 1 - 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. changed its name to Civitas Resources, Inc. Civitas is an independent Denver-based exploration and production company focused on the acquisition, development, and production of oil and associated liquids-rich natural gas in the Rocky Mountain region, primarily in the Wattenberg Field of the Denver-Julesburg Basin (“DJ Basin”).

Basis of Presentation

The accompanying unaudited condensed consolidated financial statements include the accounts of the Company and have been prepared in accordance with accounting principles generally accepted in the United States (“GAAP”) for interim financial information, the instructions to Quarterly Report on Form 10-Q, and Regulation S-X. Accordingly, pursuant to such rules and regulations, certain notes and other financial information included in audited financial statements have been condensed or omitted. In the opinion of management, all adjustments, consisting of normal recurring adjustments considered necessary for a fair presentation of interim financial information, have been included. All significant intercompany balances and transactions have been eliminated in consolidation.

The December 31, 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, 2021 (“2021 Form 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 2021 Form 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 September 30, 2022, through the filing date of this report. The results of operations for the three and nine months ended September 30, 2022 are not necessarily indicative of the results that may be expected for the full year or any other future period.

Significant Accounting Policies

The significant accounting policies followed by the Company are set forth in Note 1 - Summary of Significant Accounting Policies in the 2021 Form 10-K and are supplemented by the notes to the unaudited condensed consolidated financial statements included in this report.

Recently Issued and Adopted Accounting 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. We do not anticipate a material impact on the Company’s consolidated financial statements or related disclosures.

There are no other accounting standards applicable to the Company that would have a material effect on the Company’s financial statements and disclosures that have been issued but not yet adopted by the Company as of September 30, 2022, and through the filing date of this report.

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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 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 acquired HighPoint Resources 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 (the “HighPoint Merger”). Each eligible share of common stock of HighPoint issued and outstanding was automatically converted into the right to receive 0.11464 shares of common stock of Civitas (“Civitas Common Stock”). As a result, Civitas issued 487,952 shares of Civitas Common Stock to former HighPoint stockholders.

Concurrently with the HighPoint Merger and pursuant to the Prepackaged Plan, in exchange for the aggregate principal amount outstanding of HighPoint Operating Corporation's senior notes, Civitas issued 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 further discussion of the 7.5% Senior Notes.

Total merger consideration transferred under the HighPoint Merger was $474.9 million.

Extraction Merger

On November 1, 2021, Civitas completed its merger with Extraction Oil & Gas, Inc. (“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, each share of common stock of Extraction (the “Extraction Common Stock”) issued and outstanding 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, each unvested award of restricted stock units issued pursuant to Extraction’s 2021 Long Term Incentive Plan (the “Extraction Equity Plan”) 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”) using the Extraction Exchange Ratio. Each Converted RSU continued to be governed by the same terms and conditions that were applicable immediately prior to the Extraction Merger closing date.

Further, Civitas executed warrant agreements to replace the warrants previously issued by Extraction consisting of (i) 3.4 million Tranche A warrants to purchase Civitas Common Stock at an exercise price of $91.91 in whole or in part, at any time or from time to time on or before January 20, 2025, issued pursuant to a warrant agreement by and between Civitas and Broadridge Corporate Issuer Solutions, Inc., as warrant agent (“Broadridge”), dated as of November 1, 2021 (the “Tranche A Warrants”), and (ii) 1.7 million Tranche B warrants to purchase Civitas Common Stock at an exercise price of $104.45 in whole or in part, at any time or from time to time on or before (i) January 20, 2026, issued pursuant to a warrant agreement by and between Civitas and Broadridge, as warrant agent, dated as of November 1, 2021 (the “Tranche B Warrants,” and, together with the Tranche A Warrants, the “Warrants”). A holder of a 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 warrant agreement. Please refer to Note 8 - Fair Value Measurements for further discussion.

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Total merger consideration transferred under the Extraction Merger was $1.8 billion. The following table presents the preliminary purchase price allocation of the assets acquired and the liabilities assumed in the Extraction Merger:


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

The valuation of proved 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 assets acquired and liabilities assumed in the Extraction Merger as adjustments may be made to these measurements in subsequent periods (up to one year from the acquisition date). 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 potential outcomes of the assessment.

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Crestone Peak Merger

On November 1, 2021, Civitas completed its merger with CPPIB Crestone Peak Resources America Inc. (“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, the shares of Crestone Peak common stock were converted into the right to collectively receive 22.5 million shares of Civitas Common Stock, representing total merger consideration of $1.3 billion.

The following table presents the preliminary purchase price allocation of the assets acquired and the liabilities assumed in the Crestone Peak Merger:


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 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 assets acquired and liabilities assumed in the Crestone Peak Merger as adjustments may be made to these measurements in subsequent periods (up to one year from the acquisition date). 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 potential outcomes of the assessment.

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Revenue and earnings of the acquiree

The amount of revenue of HighPoint included in our statement of operations during the three and nine months ended September 30, 2021 was $84.7 million and $159.4 million, respectively, as the HighPoint Merger was completed on April 1, 2021. There was no revenue included in our statement of operations during the three and nine months ended September 30, 2021 related to the Extraction and Crestone Peak mergers as both mergers were completed after September 30, 2021. We determined that disclosing the amount of HighPoint, Extraction, and Crestone Peak related earnings included in the unaudited condensed consolidated statements of operations and comprehensive income (“statements of operations”) is impracticable, as the operations from these mergers were integrated into the operations of the Company from the dates of each acquisition.

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 and nine months ended September 30, 2021, assuming the HighPoint, Extraction, and Crestone Peak mergers had been completed as of January 1, 2020. The pro forma financial information is not necessarily indicative of the results of operations that would have been achieved if the mergers had been effective as of this date, or of future results, and includes certain non-recurring pro forma adjustments that were directly attributable to the business combinations (in thousands, except per share amounts).


	Three Months Ended September 30, 2021		Nine Months Ended September 30, 2021

Total revenue	$	619,913	$	1,713,023
Net income	103,485		859,756
Net income per common share - basic	$	1.23	$	10.20
Net income per common share - diluted	$	1.22	$	10.15

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 $280.4 million (the “Bison Acquisition”). Net assets acquired under the preliminary purchase price allocation were $294.0 million and consequently resulted in a bargain purchase gain of $13.6 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 related to the aforementioned mergers and acquisitions are accounted for separately from the assets acquired and liabilities assumed and are included in merger transaction costs in the statements of operations. The Company incurred merger transaction costs of $1.8 million and $5.6 million during the three months ended September 30, 2022 and 2021, respectively, and $23.8 million and $27.1 million during the nine months ended September 30, 2022 and 2021, respectively.

Acquisition of additional working interests in Company-operated wells

On July 5, 2022, the Company entered into and closed on Purchase and Sale Agreements to acquire additional working interests in certain Company-operated wells for cash consideration of $81.6 million, subject to customary purchase price adjustments.

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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 September 30,				Nine Months Ended September 30,
	2022		2021		2022		2021
Operating net revenues:
Oil sales	$	653,548	$	131,360	$	1,981,308	$	297,515
Natural gas sales	216,917		24,764		535,918		53,064
NGL sales	137,486		33,839		459,899		69,578
Oil, natural gas, and NGL sales	$	1,007,951	$	189,963	$	2,977,125	$	420,157

The 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 and nine months ended September 30, 2022 and 2021, revenue recognized in the reporting period related to performance obligations satisfied in prior reporting periods was insignificant. As of September 30, 2022 and December 31, 2021, the Company's receivables from contracts with customers were $337.9 million and $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):


	September 30, 2022		December 31, 2021
Accounts payable trade	$	15,885	$	19,623
Accrued drilling and completion costs	130,397		129,430
Accrued lease operating expense and gathering, transportation, and processing	83,793		19,077
Accrued general and administrative expense	15,927		21,163
Accrued merger transaction costs	—		1,475
Accrued oil and NGL hedging	19,406		26,601
Accrued interest expense	10,509		6,303
Accrued settlement	4,997		20,791
Other accrued expenses	7,806		1,725
Total accounts payable and accrued expenses	$	288,720	$	246,188

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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. 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 September 30, 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 two ratings agencies. The 5.0% Indenture also contains customary events of default.

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 , by and among Civitas Resources, U.S. Bank National Association, as trustee, and the guarantors party thereto. Interest accrued at the rate of 7.5% per annum and was payable semiannually in arrears on April 30 and October 31 of each year. On May 1, 2022, the Company redeemed all of the issued and outstanding 7.5% Senior Notes 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 either issuance. The tables below present the related carrying values as of September 30, 2022 and December 31, 2021 (in thousands):


	As of September 30, 2022
	Principal Amount		Unamortized Deferred Financing Costs		Net Amount

5.0% Senior Notes	$	400,000	$	7,103	$	392,897


	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

The Company is party to 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, that has an aggregate maximum commitment amount of $2.0 billion and matures on November 1, 2025 (with all subsequent amendments, the “Credit Facility” or the “Credit Agreement”).

The Credit Facility 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 properties evaluated in the most recently delivered reserve reports prior to the amendment effective date, including any engineering reports relating to the oil and natural gas properties of the restricted domestic subsidiaries of the Company, subject to customary exceptions.

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 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 (“permitted net leverage ratio”) of 3.00 to 1 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 was in compliance with all covenants under the Credit Facility as of September 30, 2022 and through the filing of this report.

On April 20, 2022, the Company entered into an amendment to the Credit Agreement that increased the Company’s borrowing base from $1.0 billion to $1.7 billion and increased the aggregate elected commitments from $800.0 million to $1.0 billion.

In addition, this amendment resulted in the removal and replacement of LIBOR with the Secured Overnight Financing Rate (“SOFR”) as a mechanism to determine interest for borrowings made under the Credit Facility using a term-specific SOFR. As a result, borrowings under the Credit Facility bear interest at a per annum rate equal to, at the option of the Company, either (i) the Alternate Base Rate (“ABR”, for ABR Revolving Credit Loans) plus the applicable margin, or (ii) the term-specific SOFR plus the applicable margin. ABR is established as a rate per annum equal to the greatest of (a) the rate of interest publicly announced by JPMorgan as its prime rate, (b) the applicable rate of interest published by the Federal Reserve Bank of New York plus 0.5%, or (c) the term-specific SOFR plus 1.0%, subject to a 1.50% floor plus the applicable margin of 1.00% to 2.00%, based on the utilization of the Credit Facility. Term-specific SOFR is based on one-, three-, or six-month terms as selected by the Company and is subject to a 0.50% floor plus the applicable margin of 2.00% to 3.00%, based on the utilization of the Credit Facility. Interest on borrowings that bear interest at the SOFR shall be payable on the last day of the applicable interest period selected by the Company, and interest on borrowings that bear interest at the ABR shall be payable quarterly in arrears.

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On October 27, 2022, and as part of the regularly scheduled, semi-annual borrowing base redetermination under the Credit Facility, the Company’s aggregate elected commitments of $1.0 billion were reaffirmed and borrowing base was increased from $1.7 billion to $1.85 billion. The next scheduled borrowing base redetermination date is set to occur in April 2023.

The following table presents the outstanding balance, total amount of letters of credit outstanding, and available borrowing capacity under the Credit Facility as of the dates indicated (in thousands):


	October 31, 2022		September 30, 2022		December 31, 2021
Revolving credit facility	$	—	$	—	$	—
Letters of credit	12,100		12,156		21,656
Available borrowing capacity	987,900		987,844		778,344
Total aggregate elected commitments	$	1,000,000	$	1,000,000	$	800,000

In connection with the amendments to the Credit Facility, the Company capitalized a total of approximately $11.9 million in deferred financing costs. Of the total post-amortization net capitalized amounts, (i) $6.3 million and $7.5 million are presented within the other noncurrent assets line item on the accompanying balance sheets as of September 30, 2022 and December 31, 2021, respectively, and (ii) $3.0 million and $2.7 million are presented within the prepaid expenses and other line item on the accompanying balance sheets as of September 30, 2022 and December 31, 2021, respectively.

Interest Expense

For the three months ended September 30, 2022 and 2021, the Company incurred interest expense of $7.5 million and $3.7 million and capitalized zero and $0.6 million, respectively. For the nine months ended September 30, 2022 and 2021, the Company incurred interest expense of $24.7 million and $7.9 million and capitalized zero and $1.2 million, respectively.

NOTE 6 - 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 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. 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 and Bison Acquisition, the Company assumed all obligations, whether asserted or unasserted, of HighPoint, Extraction, Crestone Peak, and Bison. 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, other than the following:

Boulder County. In prior periods, there was 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 of minerals contained within Boulder County, Colorado. Boulder County had initiated suit in District Court for Boulder County that was primarily a contract case, where the relevant contracts were the conservation easement over the Blue Paintbrush location, Extraction’s Surface Use Agreement 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. This litigation has been resolved as to all substantive issues, and the Company is awaiting final dismissal of the matter by the trial court.

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In May 2022, the Company became aware that Boulder County is alleging new legal theories and requesting termination of the leases previously at issue in the Blue Paintbrush litigation. No formal action has been initiated, but the Company intends to vigorously defend against all claims alleged by Boulder County. If an action is brought by Boulder County, an adverse outcome in any such litigation could result in the Company failing to meet its development objectives in Blue Paintbrush.

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 September 30, 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 one 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 12,500 barrels (“Bbl”) per day through April 2025, regardless of the amount of pipeline capacity utilized by the Company. The aggregate financial commitment fee over the remaining term was $37.7 million as of September 30, 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. Under the terms of the agreement, the Company is required to make periodic deficiency payments for any shortfalls in delivering the minimum gross volume commitment of 16,000 Bbls per day over a term ending in 2023. The aggregate financial commitment fee over the remaining term is $12.0 million as of September 30, 2022. Upon notifying the purchaser at least twelve months prior to the expiration date of the agreement, the Company may elect to extend the term of the agreement for up to three additional years. 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. The Gathering Agreement also includes a commitment to sell take-in-kind NGLs from other processing agreements of 7,500 Bbls a day through 2026 with the ability to roll forward up to a 10% shortfall in a given month to the subsequent month. The aggregate financial commitment over the remaining term is $141.1 million as of September 30, 2022, which fluctuates with commodity prices as this is a value-based percentage of proceeds sales contract. Based on current projections, the Company may incur approximately $59.0 million of shortfall payments under the Gathering Agreement during the remaining term of approximately seven years; however, the Company is actively engaging alternative strategies to reduce any potential contract deficiencies incurred in future periods.

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 two 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 million cubic feet of natural gas (“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 September 30, 2022. The Company has not, and does not, expect to incur any deficiency payments.

The Company is also party to additional individually immaterial 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 $10.7 million as of September 30, 2022.

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The minimum annual payments under these agreements for the next five years as of September 30, 2022 are presented below (in thousands):


	Firm Transportation		Minimum Volume(1)
Remainder of 2022	$	3,680	$	11,764
2023	14,600		33,192
2024	14,640		23,582
2025	4,800		20,688
2026	—		19,025
2027 and thereafter	—		55,578
Total	$	37,720	$	163,829

___________________________

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

Other commitments. The Company is party to a drilling commitment agreement with a third-party midstream provider such that the Company is required to drill a total of 106 horizontal wells, whereby a minimum number of wells out of the 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 lateral length. Wells operated by others can satisfy this commitment, subject to limitations. If the Company were to fail to complete the 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 cannot reasonably estimate how much, if any, damages will be paid.

Refer to Note 13 - 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 (“2017 LTIP”), which provides for the issuance of restricted stock units, performance stock units, and stock options, and reserved 2,467,430 shares of common stock. 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 under the LTIP on a straight-line basis over the vesting period 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 September 30,				Nine Months Ended September 30,
	2022		2021		2022		2021
Restricted and deferred stock units	$	5,809	$	1,561	$	14,991	$	4,628
Performance stock units	4,435		728		9,478		1,468

Total stock-based compensation	$	10,244	$	2,289	$	24,469	$	6,096

As of September 30, 2022, unrecognized compensation expense related to the awards granted under the LTIP will be amortized through the relevant periods as follows (in thousands):


	Unrecognized Compensation Expense		Final Year of Recognition
Restricted and deferred stock units	$	21,047	2025
Performance stock units	17,828		2024
Total unrecognized stock-based compensation	$	38,875

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

The Company typically grants RSUs to officers, directors, and employees and DSUs to directors as part of its LTIP. Each RSU and DSU represents a right to receive one share of the Company's common stock upon settlement of the award at the end of the specified vesting period.

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 quarterly installments over a one-year period following the grant date. DSUs are settled in shares of the Company's common stock upon the director’s separation of service from the Board. 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.

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A summary of the status and activity of non-vested RSUs and DSUs for the nine months ended September 30, 2022 is presented below:


	RSUs and DSUs	Weighted-Average Grant-Date Fair Value
Non-vested, beginning of year	815,062	$	42.18
Granted	565,578	51.16
Vested	(628,363)	42.38
Forfeited	(56,764)	39.31
Non-vested, end of period	695,513	$	49.54

The fair value of the RSUs and DSUs granted under the LTIP during the nine months ended September 30, 2022 was $28.9 million.

Performance Stock Units (“PSUs”)

The Company grants PSUs to officers as part of its LTIP. The number of shares of the Company’s common stock issued to settle PSUs ranges from zero to two times the number of PSUs granted and is determined based on performance achievement against certain criteria over a three-year performance period. PSUs generally vest and settle on the third anniversary of the date of the grant.

Performance achievement is determined based on one to two criteria. The first criterion is based on either, or a combination of, the Company’s absolute and relative total shareholder return (“TSR”) 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 over the 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 as follows for the relevant grant years:


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

As a portion of the 2020 PSUs depend on a performance-based settlement 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 expected ROCE performance.

Of the grant-date fair value, the portion of the PSUs tied to 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 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 TSR performance. Significant assumptions used in this simulation include the 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 peers.

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A summary of the status and activity of non-vested PSUs for the nine months ended September 30, 2022 is presented below:


	PSUs (1)	Weighted-Average Grant-Date Fair Value
Non-vested, beginning of year	319,367	$	57.58
Granted	282,224	65.65
Vested	(163,406)	40.90
Forfeited	(48,892)	49.39
Expired	(41,955)	22.77
Non-vested, end of period	347,338	$	77.35

___________________________

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

The fair value of the PSUs granted under the LTIP during the nine months ended September 30, 2022 was $18.5 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. In addition, certain PSUs vested during 2022 pursuant to change in control provisions in the applicable award agreements.

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.

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 option awards is derived from the 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 nine months ended September 30, 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	(6,934)	34.36
Forfeited	(1,218)	34.36
Outstanding, end of period	17,397	$	34.36	0.8	$	401
Options outstanding and exercisable	17,397	$	34.36	0.8	$	401

The aggregate intrinsic value of options exercised during the nine months ended September 30, 2022 was $0.2 million.

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NOTE 8 - FAIR VALUE MEASUREMENTS

The Company follows authoritative accounting guidance for measuring the fair value of assets and liabilities 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. 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 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 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.

Derivatives

The Company uses Level 2 inputs to measure the fair value of oil, gas, and NGL commodity price derivatives. The fair value of the Company's commodity price derivatives is estimated using industry-standard models that contemplate various inputs including, but not limited to, the contractual price of the underlying position, current market prices, forward commodity price curves, volatility factors, time value of money, and the credit risk of both the Company and 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 Company’s derivative instruments.

The following tables present the Company’s financial assets and liabilities that were accounted for at fair value on a recurring basis as of September 30, 2022 and December 31, 2021 and their classification within the fair value hierarchy (in thousands):


	As of September 30, 2022
	Level 1		Level 2		Level 3
Derivative assets	$	—	$	8,491	$	—
Derivative liabilities	$	—	$	177,092	$	—


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

Long-Term Debt

The 5.0% Senior Notes are recorded at cost, net of any unamortized deferred financing costs. As of September 30, 2022, the fair value of the 5.0% Senior Notes was $362.8 million. This fair value is based on quoted market prices, and as such, is 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 Note 5 - Long-Term Debt for additional information.

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Warrants

As discussed in Note 2 - Acquisitions and 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 warrants and therefore were not exercisable during the three and nine months ended September 30, 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 and unproved properties are valued based on a discounted cash flow approach utilizing Level 3 inputs, including, amongst other things, reserve quantities and 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 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 value of proved properties may not be recoverable, the Company uses Level 3 inputs to measure and record impairment at fair value. There were no proved property impairments during the three and nine months ended September 30, 2022 and 2021.

Impairments of Unproved Properties

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 acreage value based on prices received for similar, recent acreage transactions by the Company or other market participants. No abandonment and impairment of unproved properties expense was recorded during the three months ended September 30, 2022 and 2021. During the nine months ended September 30, 2022 and 2021, the Company incurred abandonment and impairment of unproved properties expense of $18.0 million and $2.2 million, respectively.

NOTE 9 - 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. The Company's commodity derivative contracts consist of swap and collar arrangements as well as Roll Differential swaps. As of September 30, 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 does not designate its commodity derivative contracts as hedging instruments.

In a typical swap arrangement, if the agreed upon published third-party index price (“index price”) is lower than the fixed contract price at the time of settlement, the Company receives the difference between the index price and the fixed contract price. If the index price is higher than the fixed contact price at the time of settlement, the Company pays the difference between the index price and the fixed contract price. In a fixed for floating swap arrangement, if the index price is lower than the fixed contract price at the time of settlement, the Company pays the difference between the index price and the fixed contract price. If the index price is higher than the fixed contact price at the time of settlement, the Company receives the difference between the index price and the 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 (“two-way collar”). When the index price is above the ceiling price at the time of settlement, the Company pays the difference between the index price and 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 and floor price. When the index price is between the floor price and ceiling price, 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 floor price (“three-way collar”). In these arrangements, when the index price is below the floor price at the time of settlement, the Company receives the difference between the index price and the floor price, capped at the difference between the floor price and the exercise price of the short put.

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

As of September 30, 2022, the Company had entered into the following commodity price derivative contracts:


	Contract Period
	Q4 2022		Q1 2023		Q2 2023		Q3 2023		Q4 2023		2024
Oil Derivatives (volumes in Bbl/day and prices in $/Bbls)
Swaps
NYMEX WTI Volumes	10,543		1,320		1,205		1,053		984		1,019
Weighted-Average Contract Price	$	51.94	$	74.29	$	73.49	$	70.92	$	70.61	$	66.78
Swaps (Fixed for Floating) (1)
NYMEX WTI Volumes	9,538		—		—		—		—		—
Weighted-Average Contract Price	$	77.55	$	—	$	—	$	—	$	—	$	—
Two-Way Collars
NYMEX WTI Volumes	9,131		1,054		—		—		—		—
Weighted-Average Ceiling Price	$	67.38	$	72.70	$	—	$	—	$	—	$	—
Weighted-Average Floor Price	$	42.39	$	40.00	$	—	$	—	$	—	$	—
Three-Way Collars
NYMEX WTI Volumes	—		1,721		1,436		1,302		1,172		143
Weighted-Average Ceiling Price	$	—	$	58.75	$	57.69	$	57.48	$	56.49	$	56.25
Weighted-Average Floor Price	$	—	$	49.31	$	48.10	$	47.91	$	49.04	$	45.00
Weighted-Average Sold Put Price	$	—	$	39.25	$	37.70	$	37.41	$	39.04	$	35.00
Roll Differential Swaps (2)
NYMEX WTI Volumes	2,000		—		—		—		—		—
Weighted-Average Contract Price	$	0.22	$	—	$	—	$	—	$	—	$	—
Natural Gas Derivatives (volumes in MMBtu/day and prices in $/million British thermal units (“MMBtu”))
Swaps
NYMEX HH Volumes	57,720		47,368		46,374		46,120		45,947		24,148
Weighted-Average Contract Price	$	2.92	$	2.65	$	2.64	$	2.61	$	2.60	$	2.70
CIG Volumes	10,000		—		—		—		—		—
Weighted-Average Contract Price	$	2.13	$	—	$	—	$	—	$	—	$	—
Two-Way Collars
NYMEX HH Volumes	79,148		9,558		1,563		1,887		1,756		1,033
Weighted-Average Ceiling Price	$	3.69	$	3.23	$	2.78	$	2.96	$	2.96	$	3.05
Weighted-Average Floor Price	$	2.60	$	2.03	$	2.21	$	2.34	$	2.38	$	2.38



Three-Way Collars
NYMEX HH Volumes	127		899		505		—		—		303
Weighted-Average Ceiling Price	$	2.74	$	3.19	$	3.33	$	—	$	—	$	3.49
Weighted-Average Floor Price	$	2.50	$	2.50	$	2.50	$	—	$	—	$	2.50
Weighted-Average Sold Put Price	$	2.00	$	2.00	$	2.00	$	—	$	—	$	2.00
NGL Derivatives (volumes in Bbls/day and prices in $/Bbl)
Swaps
OPIS Basket Volumes	4,000		—		—		—		—		—
Weighted-Average Contract Price	$	20.22	$	—	$	—	$	—	$	—	$	—

______________________________

(1) During the third quarter of 2022, the Company entered into fixed for floating swaps to achieve a fixed settlement of $30.71 per Bbl on the majority of its fourth quarter 2022 oil swap positions (weighted-average contract price of $46.84 per Bbl).

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

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 Company’s commodity derivative contracts as of the dates indicated (in thousands):


	September 30, 2022		December 31, 2021
Derivative Assets:
Commodity contracts - current	$	5,727	$	3,393
Commodity contracts - noncurrent	2,764		—
Total derivative assets	8,491		3,393
Amounts not offset in the accompanying balance sheets	(8,491)		(3,393)
Total derivative assets, net	$	—	$	—

Derivative Liabilities:
Commodity contracts - current	$	(144,176)	$	(219,804)
Commodity contracts - long-term	(32,916)		(19,959)
Total derivative liabilities	(177,092)		(239,763)
Amounts not offset in the accompanying balance sheets	8,491		3,393
Total derivative liabilities, net	$	(168,601)	$	(236,370)

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


	Three Months Ended September 30,				Nine Months Ended September 30,
	2022		2021		2022		2021
Derivative cash settlement loss:
Oil contracts	$	(67,623)	$	(19,838)	$	(307,563)	$	(41,454)
Gas contracts	(66,610)		(6,708)		(149,485)		(9,082)
NGL contracts	(9,678)		—		(35,072)		—
Total derivative cash settlement loss	(143,911)		(26,546)		(492,120)		(50,536)
Change in fair value gain (loss)	153,192		(9,678)		133,258		(83,077)
Total derivative gain (loss)	$	9,281	$	(36,224)	$	(358,862)	$	(133,613)

NOTE 10 - ASSET RETIREMENT OBLIGATIONS

The Company recognizes an estimated liability for future costs associated with the abandonment of its oil and gas properties, including facilities requiring decommissioning. A liability for the fair value of an asset retirement obligation and corresponding increase to the carrying value of the related long-lived asset are recorded at the time a well is drilled or acquired, or a facility is constructed. The increase in carrying value 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 the accretion of 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 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	2,718
Accretion expense	12,254
Liabilities settled	(14,720)


Balance as of September 30, 2022	$	225,567
Current portion	24,000
Long-term portion	$	201,567

NOTE 11 - EARNINGS PER SHARE

Earnings per basic and diluted share are calculated under the treasury stock method. Basic net income per common share is calculated by dividing net income by the basic weighted-average common shares outstanding for the respective period. Diluted net income per common share is calculated by dividing net income by the diluted weighted-average common shares outstanding, which includes the effect of potentially dilutive securities. Potentially dilutive securities 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 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 zero to two 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 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.

The following table sets forth the calculations of basic and diluted net income per common share (in thousands, except per share amounts):


	Three Months Ended September 30,				Nine Months Ended September 30,
	2022		2021		2022		2021
Net income	$	405,752	$	40,659	$	966,212	$	15,221

Basic net income per common share	$	4.77	$	1.32	$	11.37	$	0.55
Diluted net income per common share	$	4.74	$	1.31	$	11.30	$	0.55

Weighted-average shares outstanding - basic	85,069		30,849		84,968		27,485
Add: dilutive effect of contingent stock awards	485		289		527		354

Weighted-average shares outstanding - diluted	85,554		31,138		85,495		27,839

There were 109,519 and 115,448 shares that were anti-dilutive for the three months ended September 30, 2022 and 2021, respectively. There were 68,171 and 81,142 shares that were anti-dilutive for the nine months ended September 30, 2022 and 2021, respectively.

The exercise price of the Company's warrants was in excess of the Company's stock price during the three and nine months ended September 30, 2022; therefore, they were excluded from the earnings per share calculation.

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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 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. As a result of the HighPoint Merger, the Company recorded a valuation allowance 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 September 30, 2022 was $221.9 million, and the net deferred tax asset as of December 31, 2021 was $22.3 million. Additionally, income tax payable under current liabilities as of September 30, 2022 was $18.9 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, equity-based compensation, and other permanent differences including bargain purchase gain. During the three months ended September 30, 2022 and 2021, the Company recorded income tax expense of $136.3 million and $15.6 million, respectively. During the nine months ended September 30, 2022 and 2021, the Company recorded income tax expense of $312.2 million and $5.2 million, respectively.

The Company had no unrecognized tax benefits as of September 30, 2022 and December 31, 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 2022.

On August 16, 2022, the Inflation Reduction Act (“IRA”) was signed into law. Among other provisions, the IRA imposes a 15% corporate alternative minimum tax (“Corporate AMT”) for tax years beginning after December 31, 2022, imposes a 1% excise tax on corporate stock repurchases after December 31, 2022, and provides tax incentives to promote various energy efficient initiatives. The Company is evaluating the potential impact of the Corporate AMT on our current income tax expense and income taxes payable; however, we currently do not believe this will materially affect our income taxes paid for the 2023 tax year.

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NOTE 13 - LEASES

The Company’s right-of-use assets and lease liabilities are recognized on the accompanying balance sheets based on the present value of the expected lease payments over the lease term. The following table summarizes the asset classes of the Company’s operating leases (in thousands):


	September 30, 2022		December 31, 2021
Operating Leases
Field equipment(1)	$	18,524	$	29,312
Corporate leases	8,956		9,484
Vehicles	670		1,089
Total right-of-use asset	$	28,150	$	39,885

Field equipment(1)	$	18,524	$	29,312
Corporate leases	9,544		9,870
Vehicles	670		1,089
Total lease liability	$	28,738	$	40,271

____________________________

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

Future commitments by year for the Company’s leases with a lease term of one year or more as of September 30, 2022 are presented in the table below. Such commitments are reflected at undiscounted values and are reconciled to the discounted present value recognized on the accompanying balance sheets as follows (in thousands):


	Operating Leases
Remainder of 2022	$	5,000
2023	13,737
2024	5,414
2025	2,067
2026	1,775
Thereafter	2,369
Total lease payments	30,362
Less: imputed interest	(1,624)
Total lease liability	$	28,738

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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 2021 Form 10-K, 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 production of oil and associated liquids-rich natural gas in the Rocky Mountain region, primarily in the Wattenberg Field of the DJ 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. Key aspects of our strategy include multi-well pad development across our leasehold, continuous safety improvement, strict adherence to health and safety regulations, environmental stewardship, disciplined approach to acquisitions and divestitures and capital allocation, and prudent risk management.

Financial and Operating Results

Our financial and operational results include:

•Crude oil equivalent sales volumes increased 303% for the three months ended September 30, 2022 when compared to the same period during 2021 primarily due to the Extraction and Crestone Peak mergers as well as the Bison Acquisition;

•General and administrative expense per barrel of oil equivalent (“Boe”) decreased by 21% for the three months ended September 30, 2022 when compared to the same period during 2021 due to the synergies achieved through the Extraction and Crestone Peak mergers as well as the Bison Acquisition;

•Lease operating expense per Boe decreased by 3% for the three months ended September 30, 2022 when compared to the same period during 2021;

•Total liquidity was $1.7 billion as of September 30, 2022, consisting of cash on hand plus funds available under our Credit Facility. Please refer to Liquidity and Capital Resources below for additional discussion;

•Cash dividends of $150.8 million, or $1.7625 per share, declared and paid during the three months ended September 30, 2022;

•Cash flows provided by operating activities for the nine months ended September 30, 2022 were $2.0 billion, as compared to $192.2 million during the nine months ended September 30, 2021. Please refer to Liquidity and Capital Resources below for additional discussion; and

•Capital expenditures, inclusive of accruals, were $710.2 million during the nine months ended September 30, 2022, of which $55.7 million represents land and midstream capital expenditures.

Midstream Assets

The Company’s midstream assets provide reliable gathering, treating, and storage for the Company’s operated production while reducing facility site footprints, leading to more cost-efficient operations and reduced emissions and surface disturbance per Boe produced. Additionally, this infrastructure helps ensure that the Company’s production is not constrained by any single midstream service provider. The net book value of the Company’s midstream assets was $313.9 million as of September 30, 2022.

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Current Events and Outlook

Oil and natural gas prices continue to be impacted by efforts to contain COVID-19, uncertainty regarding the depth and duration of the post-pandemic economic recovery and changes to OPEC+ production levels. In addition, Russia’s invasion of Ukraine has led to regional instability. Although Russian export 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. Furthermore, the economy is experiencing elevated inflation levels as a result of global supply and demand imbalances resulting from COVID-19. Inflationary pressures could result in increases to our capital and operating expenses that are not fixed and could impact the cost of oilfield services, equipment, and personnel retention, among other things. Increases in interest rates as a result of inflation and a resulting potentially recessionary economic environment in the United States could also have a negative effect on the demand for oil and natural gas. The foregoing destabilizing factors have caused dramatic fluctuations in global financial markets and uncertainty about world-wide oil and natural gas supply and demand, which in turn has increased the volatility of oil and natural gas prices. While WTI oil prices have recovered to pre-pandemic levels, averaging approximately $98 per Bbl during the first nine months of 2022, in light of uncertainty associated with oil and natural gas demand, future monetary policy relating to inflationary pressures, and governmental policies aimed at transitions toward lower carbon energy, we cannot predict any future volatility in or levels of commodity prices or demand for oil and natural gas.

On April 1, 2021, we acquired HighPoint, and on November 1, 2021, we merged with Extraction and Crestone Peak. Additionally, on March 1, 2022, we acquired Bison. The Company believes it has successfully integrated the operations, production, and accounting databases derived from each of these mergers and acquisitions.

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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 September 30,
	2022		2021		Change		Percent Change
Revenues (in thousands):
Crude oil sales(1)	$	653,831	$	131,103	$	522,728	399	%
Natural gas sales(2)	215,853		23,387		192,466		823	%
NGL sales	137,486		33,838		103,648		306	%
Product revenue	$	1,007,170	$	188,328	$	818,842	435	%

Sales Volumes:
Crude oil (MBbls)	7,234.3		2,036.4		5,197.9		255	%
Natural gas (MMcf)	29,192.8		6,647.5		22,545.3		339	%
NGL (MBbls)	4,118.5		880.2		3,238.3		368	%
Crude oil equivalent (MBoe)(3)	16,218.3		4,024.5		12,193.8		303	%

Average Sales Prices (before derivatives)(4):
Crude oil (per Bbl)	$	90.38	$	64.38	$	26.00	40	%
Natural gas (per Mcf)	$	7.39	$	3.52	$	3.87	110	%
NGL (per Bbl)	$	33.38	$	38.44	$	(5.06)	(13)	%
Crude oil equivalent (per Boe)(3)	$	62.10	$	46.80	$	15.30	33	%

Average Sales Prices (after derivatives)(4):
Crude oil (per Bbl)	$	81.03	$	54.64	$	26.39	48	%
Natural gas (per Mcf)	$	5.11	$	2.51	$	2.60	104	%
NGL (per Bbl)	$	31.03	$	38.44	$	(7.41)	(19)	%
Crude oil equivalent (per Boe)(3)	$	53.23	$	40.20	$	13.03	32	%

_____________________________

(1)Crude oil sales excludes $(0.3) million and $0.2 million of oil transportation revenues from third parties, which do not have associated sales volumes, for the three months ended September 30, 2022 and 2021, respectively.

(2)Natural gas sales excludes $1.1 million and $1.4 million of gas gathering revenues from third parties, which do not have associated sales volumes, for the three months ended September 30, 2022 and 2021, respectively.

(3)Determined using the ratio of 6 thousand cubic feet (“Mcf”) of natural gas to 1 Bbl of crude oil.

(4)Derivatives economically hedge the price we receive for oil, natural gas, and NGL. For the three months ended September 30, 2022, the derivative cash settlement loss for oil, natural gas, and NGLs was $67.6 million, $66.6 million, and $9.7 million, respectively. For the three months ended September 30, 2021, the derivative cash settlement loss for oil and natural gas was $19.8 million and $6.7 million, respectively. Please refer to Note 9 - Derivatives under Part I, Item 1 of this report for additional disclosures.

Product revenues increased by 435% to $1.0 billion for the three months ended September 30, 2022 compared to $188.3 million for the three months ended September 30, 2021. The increase was largely due to a 303% increase in sales volumes and a $15.30, or 33%, increase in oil equivalent pricing, excluding the impact of derivatives. The increase in sales volumes is due to 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 168 gross wells to sales during the twelve-month period ending September 30, 2022.

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The following table summarizes our operating expenses for the periods indicated (in thousands, except per Boe amounts):


	Three Months Ended September 30,
	2022		2021		Change		Percent Change
Operating Expenses:
Lease operating expense	$	45,063	$	11,560	$	33,503	290	%
Midstream operating expense	9,214		3,163		6,051		191	%
Gathering, transportation, and processing	84,482		14,105		70,377		499	%
Severance and ad valorem taxes	85,029		9,205		75,824		824	%
Exploration	4,355		1,513		2,842		188	%
Depreciation, depletion, and amortization	212,070		35,604		176,466		496	%
Unused commitments	193		3,364		(3,171)		(94)	%
Bad debt expense (recovery)	(11)		279		(290)		(104)	%
Merger transaction costs	1,814		5,580		(3,766)		(67)	%
General and administrative expense	37,296		11,724		25,572		218	%
Operating expenses	$	479,505	$	96,097	$	383,408	399	%

Selected Costs ($ per Boe):
Lease operating expense	$	2.78	$	2.87	$	(0.09)	(3)	%
Midstream operating expense	0.57		0.79		(0.22)		(28)	%
Gathering, transportation, and processing	5.21		3.50		1.71		49	%
Severance and ad valorem taxes	5.24		2.29		2.95		129	%
Exploration	0.27		0.38		(0.11)		(29)	%
Depreciation, depletion, and amortization	13.08		8.85		4.23		48	%
Unused commitments	0.01		0.84		(0.83)		(99)	%
Bad debt expense (recovery)	—		0.07		(0.07)		(100)	%
Merger transaction costs	0.11		1.39		(1.28)		(92)	%
General and administrative expense	2.30		2.91		(0.61)		(21)	%
Operating expenses	$	29.57	$	23.89	$	5.68	24	%

Lease operating expense. Our lease operating expense increased $33.5 million, or 290%, to $45.1 million for the three months ended September 30, 2022 from $11.6 million for the three months ended September 30, 2021, and decreased 3% on an equivalent basis per Boe. Lease operating expense increased on an aggregate basis as a result of the Extraction and Crestone Peak mergers as well as the Bison Acquisition. Lease operating expense per Boe decreased as a result of the synergies achieved through the aforementioned mergers.

Midstream operating expense. Our midstream operating expense increased $6.0 million, or 191%, to $9.2 million for the three months ended September 30, 2022 from $3.2 million for the three months ended September 30, 2021, and decreased 28% on an equivalent basis per Boe. Midstream operating expense increased on an aggregate basis due to the acquisition of certain midstream assets through the Crestone Peak Merger. Conversely, while certain midstream operating expenses correlate to sales volumes, the majority of the costs, such as compression, are fixed and thereby result in a decrease in midstream operating expense per Boe period over period.

Gathering, transportation, and processing. Gathering, transportation, and processing expense increased $70.4 million, or 499%, to $84.5 million for the three months ended September 30, 2022 from $14.1 million for the three months ended September 30, 2021, and increased 49% on an equivalent basis per Boe. Sales volumes have a direct correlation to gathering, transportation, and processing expense and increased 303% during the comparable periods. Additionally, we are party to a number of value-based percentage of proceeds sales contracts, which track solely with natural gas and NGL pricing and thereby have further contributed to the increase in gathering, transportation, and processing expense. Finally, the Company continually monitors for the best sales volumes outlet and thereby incurred increased gathering, transportation, and processing expense during the three months ended September 30, 2022 relative to oil differentials (that would otherwise be recorded as a direct reduction of revenue) in order to receive an improvement in net margins.

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Severance and ad valorem taxes. Our severance and ad valorem taxes increased $75.8 million, or 824%, to $85.0 million for the three months ended September 30, 2022 from $9.2 million for the three months ended September 30, 2021, and increased 129% on an equivalent basis per Boe. Severance and ad valorem taxes primarily correlate to revenues, which increased by 435% for the three months ended September 30, 2022 when compared to the same period in 2021. Additionally, through the Extraction and Crestone Peak mergers, we now operate in certain taxing districts with incrementally higher severance and ad valorem tax rates that are thereby contributing to the aggregate increase in severance and ad valorem taxes.

Depreciation, depletion, and amortization. Our depreciation, depletion, and amortization expense increased $176.5 million, or 496%, to $212.1 million for the three months ended September 30, 2022 from $35.6 million for the three months ended September 30, 2021, and increased 48% on an equivalent basis per Boe. The increase in depreciation, depletion, and amortization expense is the result of (i) a $4.8 billion increase in the depletable property base primarily due to the Extraction and Crestone Peak mergers as well as the Bison Acquisition and (ii) a 303% increase in production between the comparable periods.

Unused commitments. During the three months ended September 30, 2022, we incurred $0.2 million in unused commitments primarily due to certain deficiency payments incurred under a minimum volume water commitment. During the three months ended September 30, 2021, we incurred $3.4 million in unused commitments primarily due to the assumption of two firm natural gas pipeline transportation contracts in the HighPoint Merger to provide a guaranteed outlet for production from properties HighPoint had previously sold. Both firm transportation contracts, which expired on July 31, 2021, required us to pay transportation charges regardless of the amount of pipeline capacity utilized.

Merger transaction costs. During the three months ended September 30, 2022, we incurred $1.8 million in legal, advisor, and other costs associated with the Extraction and Crestone Peak mergers. During the three months ended September 30, 2021, we incurred $5.6 million in legal, advisor, and other costs associated with the HighPoint, Extraction, and Crestone Peak mergers. Merger transaction costs include zero and $0.6 million of severance payments associated with merger activity for the three months ended September 30, 2022 and 2021, respectively.

General and administrative expense. Our general and administrative expense increased $25.6 million, or 218%, to $37.3 million for the three months ended September 30, 2022 from $11.7 million for the three months ended September 30, 2021, and decreased 21% on an equivalent basis per Boe. The primary drivers of the aggregate increase relate to an increase in salaries, benefits, and stock compensation expense associated with the Extraction and Crestone Peak mergers and an increase in charitable contributions. General and administrative expense per Boe decreased due to oil equivalent sales volumes being 303% higher during the three months ended September 30, 2022 as compared to the same period in 2021.

Derivative gain (loss). Our derivative gain for the three months ended September 30, 2022 was $9.3 million as compared to a loss of $36.2 million for the three months ended September 30, 2021. Our derivative gain for the three months ended September 30, 2022 is due to fair market value adjustments caused by market prices being lower relative to our future contracted hedge prices, partially offset by settlement losses caused by market prices being higher than our current contracted hedge prices. Please refer to Note 9 - Derivatives under Part I, Item 1 of this report for additional discussion.

Interest expense. Our interest expense for the three months ended September 30, 2022 and 2021 was $7.5 million and $3.0 million, respectively. Average debt outstanding for the three months ended September 30, 2022 and 2021 was $400.0 million and $86.8 million, respectively. The components of interest expense for the periods presented are as follows (in thousands):


	Three Months Ended September 30,
	2022		2021
Senior Notes	$	5,000	$	1,875
Credit Facility	—		777
Commitment and letter of credit fees under the Credit Facility	1,329		577
Amortization of deferred financing costs	1,139		437
Capitalized interest	—		(641)
Total interest expense	$	7,468	$	3,025

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


	Nine Months Ended September 30,
	2022		2021		Change		Percent Change
Revenues (in thousands):
Crude oil sales(1)	$	1,981,015	$	296,826	$	1,684,189	567	%
Natural gas sales(2)	533,581		50,451		483,130		958	%
NGL sales	459,899		69,578		390,321		561	%
Product revenue	$	2,974,495	$	416,855	$	2,557,640	614	%

Sales Volumes:
Crude oil (MBbls)	20,666.2		4,884.3		15,781.9		323	%
Natural gas (MMcf)	84,882.7		16,267.0		68,615.7		422	%
NGL (MBbls)	11,660.8		2,156.9		9,503.9		441	%
Crude oil equivalent (MBoe)(3)	46,474.1		9,752.4		36,721.7		377	%

Average Sales Prices (before derivatives)(4):
Crude oil (per Bbl)	$	95.86	$	60.77	$	35.09	58	%
Natural gas (per Mcf)	$	6.29	$	3.10	$	3.19	103	%
NGL (per Bbl)	$	39.44	$	32.26	$	7.18	22	%
Crude oil equivalent (per Boe)(3)	$	64.00	$	42.74	$	21.26	50	%

Average Sales Prices (after derivatives)(4):
Crude oil (per Bbl)	$	80.98	$	52.28	$	28.70	55	%
Natural gas (per Mcf)	$	4.53	$	2.54	$	1.99	78	%
NGL (per Bbl)	$	36.43	$	32.26	$	4.17	13	%
Crude oil equivalent (per Boe)(3)	$	53.41	$	37.56	$	15.85	42	%

_____________________________

(1)Crude oil sales excludes $0.3 million and $0.7 million of oil transportation revenues from third parties, which do not have associated sales volumes, for the nine months ended September 30, 2022 and 2021, respectively.

(2)Natural gas sales excludes $2.3 million and $2.6 million of gas gathering revenues from third parties, which do not have associated sales volumes, for the nine months ended September 30, 2022 and 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 oil, natural gas, and NGL. For the nine months ended September 30, 2022, the derivative cash settlement loss for oil, natural gas, and NGLs was $307.6 million, $149.5 million, and $35.1 million, respectively. For the nine months ended September 30, 2021, the derivative cash settlement loss for oil and natural gas was $41.5 million and $9.1 million, respectively. Please refer to Note 9 - Derivatives under Part I, Item 1 of this report for additional disclosures.

Product revenues increased by 614% to $3.0 billion for the nine months ended September 30, 2022 compared to $416.9 million for the nine months ended September 30, 2021. The increase was largely due to a 377% increase in sales volumes and a $21.26, or 50%, 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, 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 168 gross wells to sales during the twelve-month period ending September 30, 2022.

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The following table summarizes our operating expenses for the periods indicated (in thousands, except per Boe amounts):


	Nine Months Ended September 30,
	2022		2021		Change		Percent Change
Operating Expenses:
Lease operating expense	$	122,959	$	28,649	$	94,310	329	%
Midstream operating expense	22,395		11,314		11,081		98	%
Gathering, transportation, and processing	214,404		32,793		181,611		554	%
Severance and ad valorem taxes	234,203		23,622		210,581		891	%
Exploration	6,436		5,156		1,280		25	%
Depreciation, depletion, and amortization	601,449		89,433		512,016		573	%
Abandonment and impairment of unproved properties	17,975		2,215		15,760		712	%
Unused commitments	2,700		7,692		(4,992)		(65)	%
Bad debt expense (recovery)	(7)		279		(286)		(103)	%
Merger transaction costs	23,766		27,121		(3,355)		(12)	%
General and administrative expense	102,682		33,119		69,563		210	%
Operating expenses	$	1,348,962	$	261,393	$	1,087,569	416	%

Selected Costs ($ per Boe):
Lease operating expense	$	2.65	$	2.94	$	(0.29)	(10)	%
Midstream operating expense	0.48		1.16		(0.68)		(59)	%
Gathering, transportation, and processing	4.61		3.36		1.25		37	%
Severance and ad valorem taxes	5.04		2.42		2.62		108	%
Exploration	0.14		0.53		(0.39)		(74)	%
Depreciation, depletion, and amortization	12.94		9.17		3.77		41	%
Abandonment and impairment of unproved properties	0.39		0.23		0.16		70	%
Unused commitments	0.06		0.79		(0.73)		(92)	%
Bad debt expense (recovery)	—		0.03		(0.03)		(100)	%
Merger transaction costs	0.51		2.78		(2.27)		(82)	%
General and administrative expense	2.21		3.40		(1.19)		(35)	%
Operating expenses	$	29.03	$	26.81	$	2.22	8	%

Lease operating expense. Our lease operating expense increased $94.3 million, or 329%, to $123.0 million for the nine months ended September 30, 2022 from $28.7 million for the nine months ended September 30, 2021, and decreased 10% on an equivalent basis per Boe. Lease operating expense increased on an aggregate basis as a result of the HighPoint, Extraction, and Crestone Peak mergers as well as the Bison Acquisition. Lease operating expense per Boe decreased as a result of the synergies achieved through the aforementioned mergers.

Midstream operating expense. Our midstream operating expense increased $11.1 million, or 98%, to $22.4 million for the nine months ended September 30, 2022 from $11.3 million for the nine months ended September 30, 2021, and decreased 59% on an equivalent basis per Boe. Midstream operating expense increased on an aggregate basis due to the acquisition of certain midstream assets through the HighPoint and Crestone Peak mergers. Conversely, while certain midstream operating expenses correlate to sales volumes, the majority of the costs, such as compression, are fixed and thereby result in a decrease in midstream operating expense per Boe period over period.

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Gathering, transportation, and processing. Gathering, transportation, and processing expense increased $181.6 million, or 554%, to $214.4 million for the nine months ended September 30, 2022 from $32.8 million for the nine months ended September 30, 2021, and increased 37% on an equivalent basis per Boe. Sales volumes have a direct correlation to gathering, transportation, and processing expense and increased 377% during the comparable periods. Additionally, we are party to a number of value-based percentage of proceeds sales contracts, which track solely with natural gas and NGL pricing and thereby have further contributed to the increase in gathering, transportation, and processing expense. Finally, the Company continually monitors for the best sales volumes outlet and thereby incurred increased gathering, transportation, and processing expense during the nine months ended September 30, 2022 relative to oil differentials (that would otherwise be recorded as a direct reduction of revenue) in order to receive an improvement in net margins.

Severance and ad valorem taxes. Our severance and ad valorem taxes increased $210.6 million, or 891%, to $234.2 million for the nine months ended September 30, 2022 from $23.6 million for the nine months ended September 30, 2021, and increased 108% on an equivalent basis per Boe. Severance and ad valorem taxes primarily correlate to revenues, which increased by 614% for the nine months ended September 30, 2022 when compared to the same period in 2021. Additionally, through the Extraction and Crestone Peak mergers, we now operate in certain taxing districts with incrementally higher severance and ad valorem tax rates that are thereby contributing to the aggregate increase in severance and ad valorem taxes.

Depreciation, depletion, and amortization. Our depreciation, depletion, and amortization expense increased $512.0 million, or 573%, to $601.4 million for the nine months ended September 30, 2022 from $89.4 million for the nine months ended September 30, 2021, and increased 41% on an equivalent basis per Boe. The increase in depreciation, depletion, and amortization expense is the result of (i) a $4.8 billion increase in the depletable property base primarily due to the Extraction and Crestone Peak mergers as well as the Bison Acquisition and (ii) a 377% increase in production between the comparable periods.

Abandonment and impairment of unproved properties. During the nine months ended September 30, 2022, we incurred $18.0 million 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. During the nine months ended September 30, 2021, we incurred $2.2 million in abandonment and impairment of unproved properties due to the reassessment of estimated probable and possible reserve locations based primarily upon economic viability and the expiration of non-core leases.

Unused commitments. During the nine months ended September 30, 2022, we incurred $2.7 million in unused commitments primarily due to certain deficiency payments incurred under a minimum volume crude oil and a minimum volume water commitment. During the nine months ended September 30, 2021, we incurred $7.7 million in unused commitments primarily due to the assumption of two firm natural gas pipeline transportation contracts in the HighPoint Merger to provide a guaranteed outlet for production from properties HighPoint had previously sold. Both firm transportation contracts, which expired on July 31, 2021, required us to pay transportation charges regardless of the amount of pipeline capacity utilized.

Merger transaction costs. During the nine months ended September 30, 2022 and 2021, we incurred $23.8 million and $27.1 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 $1.7 million of severance payments associated with merger activity for the nine months ended September 30, 2022 and 2021, respectively.

General and administrative expense. Our general and administrative expense increased $69.6 million, or 210%, to $102.7 million for the nine months ended September 30, 2022 from $33.1 million for the nine months ended September 30, 2021, and decreased 35% on an equivalent basis per Boe. The primary drivers of the aggregate increase relate to an increase in salaries, benefits, and stock compensation expense associated with the HighPoint, Extraction, and Crestone Peak mergers and an increase in charitable contributions. General and administrative expense per Boe decreased due to oil equivalent sales volumes being 377% higher during the nine months ended September 30, 2022 as compared to the same period in 2021.

Derivative loss. Our derivative loss for the nine months ended September 30, 2022 was $358.9 million as compared to a loss of $133.6 million for the nine months ended September 30, 2021. Our derivative loss for the nine months ended September 30, 2022 is due to settlement losses caused by market prices being higher than our current contracted hedge prices, partially offset by fair market value adjustments caused by market prices being lower relative to our future contracted hedge prices. Please refer to Note 9 - Derivatives under Part I, Item 1 of this report for additional discussion.

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Interest expense. Our interest expense for the nine months ended September 30, 2022 and 2021 was $24.7 million and $6.7 million, respectively. Average debt outstanding for the nine months ended September 30, 2022 and 2021 was $447.4 million and $70.3 million, respectively. The components of interest expense for the periods presented are as follows (in thousands):


	Nine Months Ended September 30,
	2022		2021
Senior Notes	$	17,521	$	3,750
Credit Facility	116		1,937
Commitment and letter of credit fees under the Credit Facility	3,694		1,232
Amortization of deferred financing costs	3,319		963
Capitalized interest	—		(1,197)
Total interest expense	$	24,650	$	6,685

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 equity and/or debt 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, the impact of inflation and monetary policy, weather, product distribution, refining and processing capacity, regulatory constraints, and other supply chain dynamics, among other factors.

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 next twelve months and, based on current expectations, for the long term.

As of September 30, 2022, our liquidity was $1.7 billion, consisting of cash on hand of $682.1 million and $987.8 million of available borrowing capacity on our Credit Facility. Please refer to Note 5 - Long-Term Debt under Part I, Item 1 of this report for additional discussion.

During the three months ended September 30, 2022, there were no borrowings on our Credit Facility. As of September 30, 2022 and as of the date of filing, we had zero outstanding on our Credit Facility.

On April 20, 2022, the Company entered into an amendment to the Credit Agreement that increased the Company's borrowing base from $1.0 billion to $1.7 billion and the aggregate elected commitment amount from $800.0 million to $1.0 billion. On October 27, 2022, and as part of the regularly scheduled, semi-annual borrowing base redetermination under the Credit Facility, the Company’s aggregate elected commitments of $1.0 billion were reaffirmed and borrowing base was increased from $1.7 billion to $1.85 billion. Additionally, on May 1, 2022, we exercised an optional redemption on the 7.5% Senior Notes to redeem the full amount outstanding of $100.0 million. Please refer to Note 5 - 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):


	Nine Months Ended September 30,
	2022		2021
Net cash provided by operating activities	$	1,964,863	$	192,243
Net cash used in investing activities	(1,046,584)		(54,868)
Net cash used in financing activities	(490,595)		(121,708)
Cash, cash equivalents, and restricted cash	682,240		40,512
Acquisition of oil and gas properties	(374,769)		(620)
Exploration and development of oil and gas properties	(708,958)		(104,207)

Cash flows provided by operating activities

For the nine months ended September 30, 2022 and 2021, 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.

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Cash flows provided by (used in) investing activities

Net cash used in investing activities for the nine months ended September 30, 2022 and 2021 was primarily driven by $709.0 million and $104.2 million, respectively, on the exploration and development of oil and gas properties. Additionally, we invested $374.8 million and $0.6 million in acquisitions of oil and gas properties, partially offset by cash acquired of $44.3 million and $49.8 million during the nine months ended September 30, 2022 and 2021, respectively.

Cash flows used in financing activities

Net cash used in financing activities for the nine months ended September 30, 2022 and 2021 was $490.6 million and $121.7 million, respectively. The change was primarily due to increased dividends paid of $349.0 million, the optional redemption of the 7.5% Senior Notes principal of $100.0 million, and increased payments of employee tax withholdings in exchange for the return of common stock of $16.2 million, partially offset by a decrease in net payments on the Credit Facility of $94.0 million.

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, acquisitions, and to service debt. We are also subject to financial covenants under our Credit Facility based on adjusted EBITDAX ratios. See Note 5 - Long-Term Debt under Part I, Item 1 of this report for more information about financial covenants under our Credit Facility. 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, 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 and may vary among companies, the adjusted EBITDAX amounts presented may not be comparable to similar metrics of other companies.

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


	Three Months Ended September 30,				Nine Months Ended September 30,
	2022		2021		2022		2021
Net income	$	405,752	$	40,659	$	966,212	$	15,221
Exploration	4,355		1,513		6,436		5,156
Depreciation, depletion, and amortization	212,070		35,604		601,449		89,433
Abandonment and impairment of unproved properties	—		—		17,975		2,215
Stock-based compensation(1)	10,244		2,289		24,469		6,096
Non-recurring general and administrative expense(1)	5,481		150		11,816		1,444
Merger transaction costs	1,814		5,580		23,766		27,121
Unused commitments	193		3,364		2,700		7,692
(Gain) loss on property transactions, net	938		(951)		(15,859)		(951)
Interest expense	7,468		3,025		24,650		6,685
Derivative (gain) loss	(9,281)		36,224		358,862		133,613
Derivative cash settlements loss	(143,911)		(26,546)		(492,120)		(50,536)
Income tax expense	136,338		15,596		312,163		5,160
Adjusted EBITDAX	$	631,461	$	116,507	$	1,842,519	$	248,349
_______________________________
(1) Included as a portion of general and administrative expense in the accompanying statements of operations.

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New Accounting Pronouncements

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

Critical Accounting Estimates

Information regarding our critical accounting estimates is contained in Part II, Item 7 of our 2021 Form 10-K. During the three months ended September 30, 2022, there were no significant changes in the application of critical accounting policies.

Material Commitments

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

Item 3. Quantitative and Qualitative Disclosures About Market Risk.

Oil, Natural Gas, and NGL Price Risk

Our financial condition, results of operations, and capital resources are highly dependent upon the prevailing market prices of oil, natural gas, and NGL. 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, natural gas, and NGL prices include the level of global demand for oil, natural gas, and NGL, the global supply of oil, 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, natural gas, and NGL prices with any degree of certainty. Sustained weakness in oil, natural gas, and NGL 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, natural gas, and NGL 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 NGL 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 a derivative contract, 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.

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

Presently, our derivative contracts have been executed with 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 9 - Derivatives under Part I, Item 1 of this report for summary derivative activity tables.

Interest Rates

As of September 30, 2022 and on the filing date of this report, we had a zero balance on our Credit Facility. Borrowings under our Credit Facility bear interest at a fluctuating rate that is tied to an Alternate Base Rate or Secured Overnight Financing Rate, at our option. Any increases in these interest rates can have an adverse impact on our results of operations and cash flows. As of September 30, 2022 and through the filing date of this report, the Company was in compliance with all financial and non-financial covenants under the Credit Facility.

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Counterparty and Customer Credit Risk

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

We are also subject to credit risk due to concentration of our oil, natural gas, and NGL 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, natural gas, and NGL 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.

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, 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.

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 September 30, 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 September 30, 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 September 30, 2022 that materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

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PART II. OTHER INFORMATION

Item 1. Legal Proceedings.

Information regarding our legal proceedings can be found in Note 6 - Commitments and Contingencies under Part I, Item 1 of this report.

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 2021 Form 10-K, 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.

The following risk factor supplements the risk factors included in our 2021 Form 10-K:

Continuing or worsening inflationary pressures and associated changes in monetary policy may result in increases to the cost of our goods, services, and personnel, which in turn could cause our capital expenditures and operating costs to rise.

The U.S. inflation rate has been steadily increasing since 2021 and into 2022. These inflationary pressures may result in increases to the costs of our oilfield goods, services, and personnel, which would in turn cause our capital expenditures and operating costs to rise. Sustained levels of high inflation could cause the U.S. Federal Reserve and other central banks to continue to increase interest rates, which could have the effects of raising the cost of capital and depressing economic growth, either of which, or the combination thereof, could hurt the financial and operating results of our business.

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

Unregistered sales of securities. There were no sales of unregistered equity securities during the three month period ended September 30, 2022.

Issuer Purchases of Equity Securities. The following table contains information about our acquisition of equity securities during the three months ended September 30, 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
July 1, 2022 - July 31, 2022	—	$	—	—	—
August 1, 2022 - August 31, 2022	51,455	$	60.95	—	—
September 1, 2022 - September 30, 2022	1,515	$	61.87	—	—
Total	52,970	$	61.09	—	—

_________________________

(1)Represent shares that employees surrendered back to us that equaled in value the amount of taxes needed for payroll tax withholding obligations upon the vesting of 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.

Dividend Policy. In May 2021, we announced the initiation of a quarterly base cash dividend on our common stock. In March 2022, the Board approved the initiation of a quarterly variable cash dividend in addition to the aforementioned base dividend, equal to 50% of free cash flow after the base 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. During the nine months ended September 30, 2022, the quarterly base dividend was $0.45 per share of common stock ($1.85 annually) and was increased to $0.50 per share of common stock ($2.00 annually) beginning in the fourth quarter of 2022.

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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 and the indentures governing our senior notes restrict the payment of 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.

Amendments to Articles of Incorporation or Bylaws; Change in Fiscal Year.

On October 26, 2022, the Civitas Resources, Inc. (the “Company”) announced that its Board of Directors (the “Board”) had approved and recommended for adoption by its stockholders at the Company’s 2023 annual meeting of stockholders certain amendments to the Company’s Third Amended and Restated Certificate of Incorporation (the “Certificate of Incorporation”). If adopted, the amendments to the Certificate of Incorporation would, among other things: (i) allow special meetings to be called at request of holders of 15% of the Company’s outstanding common stock who have held such shares for at least one year, subject to certain conditions; (ii) allow stockholders to act by written consent, subject to certain conditions; and (iii) allow stockholders to fill vacancies in the Board resulting from the removal of directors. Further details about the proposed amendments to the Certificate of Incorporation will be included in the Company’s proxy statement for its 2023 annual meeting.

On October 26, 2022, the Board also adopted and approved, effective immediately, amended and restated bylaws (as amended, the “Sixth Amended and Restated Bylaws”) of the Company. The Sixth Amended and Restated Bylaws, among other things:

a.provide for majority voting in uncontested director elections, instead of plurality voting;

b.provide for “proxy access” that allows a stockholder, or a group of stockholders, owning at least three percent of the Company’s outstanding stock continuously for at least three years, with no limit on stockholders who may aggregate ownership, to nominate and include in the Company’s annual meeting proxy materials director nominees constituting up to the greater of two directors or 20% of the Board, provided that the stockholders and nominees satisfy the disclosure and procedural requirements specified in the Sixth Amended and Restated Bylaws;

c.revise procedures and disclosure requirements for the nomination of directors (outside of “proxy access”) and the submission of proposals for consideration at annual meetings of the stockholders of the Company;

d.clarify the powers of the Board and the chair of a stockholder meeting to establish rules for the conduct of any meeting of stockholders;

e.provide that the Board may delegate powers to any committee thereof to the fullest extent permitted by Section 141(c)(2) of the Delaware General Corporation Law; and

f.make certain other administrative, modernizing, clarifying and conforming changes, including making updates to reflect recent amendments to the Delaware General Corporation Law.

The foregoing description of the Sixth Amended and Restated Bylaws is not complete and is qualified in its entirety by reference to the complete text of the Sixth Amended and Restated Bylaws, which is filed as Exhibit 3.4 hereto and are incorporated herein by reference.

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Item 6. Exhibits.


Exhibit Number			Description
2.1			Agreement and Plan of Merger, dated as of November 9, 2020, by and among Bonanza Creek Energy, Inc., Boron Merger Sub, Inc. and HighPoint Resources Corporation (incorporated by reference to Exhibit 2.1 to Bonanza Creek Energy, Inc.’s Current Report on Form 8-K filed on November 9, 2020)
2.2			Amendment No. 1 to the Agreement and Plan of Merger, by and among Bonanza Creek Energy, Inc., Boron Merger Sub, Inc. and HighPoint Resources Corporation, dated as of January 29, 2021 (incorporated by reference to Exhibit 2.1 to Bonanza Creek Energy, Inc.’s Current Report on Form 8-K filed on February 1, 2021)
2.3			Agreement and Plan of Merger, dated as of May 9, 2021, by and among Bonanza Creek Energy, Inc., Raptor Eagle Merger Sub, Inc. and Extraction Oil & Gas, Inc. (incorporated by reference to Exhibit 2.1 to Bonanza Creek Energy, Inc.’s Current Report on Form 8-K filed on May 10, 2021).
2.4			Agreement and Plan of Merger, dated as of June 6, 2021, by and among Bonanza Creek Energy, Inc., Raptor Condor Merger Sub 1, Inc., Raptor Condor Merger Sub 2, LLC, Crestone Peak Resources LP, CPPIB Crestone Peak Resources America Inc., Crestone Peak Resources Management LP and Extraction Oil & Gas, Inc. (incorporated by reference to Exhibit 2.1 to Bonanza Creek Energy, Inc.’s Current Report on Form 8-K filed on June 8, 2021).
2.5			Amendment No.1 to Agreement and Plan of Merger, dated as of June 6, 2021, by and among Bonanza Creek Energy, Inc., Raptor Eagle Merger Sub, Inc. and Extraction Oil & Gas, Inc. (incorporated by reference to Exhibit 2.2 to Bonanza Creek Energy, Inc.’s Current Report on Form 8-K filed on June 8, 2021).
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).
3.2			Certificate of Amendment to the Third Amended and Restated Certificate of Incorporation of Bonanza Creek Energy, Inc. (incorporated by reference to Exhibit 3.1 to the Company’s Current Report on Form 8-K filed on November 3, 2021).
3.3			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).
3.4†			Sixth Amended and Restated Bylaws of Civitas Resources, Inc.
10.1*			Severance and Release Agreement, dated as of July 22, 2022, by and between Civitas Resources, Inc. and Dean Tinsley (incorporated by reference to Exhibit 10.1 to Civitas Resources, Inc.’s Current Report on Form 8-K filed on July 25, 2022).
31.1†			Certification of the Chief Executive Officer pursuant to Rule 13a-14(a)
31.2†			Certification of the Chief Financial Officer pursuant to Rule 13a-14(a)
32.1†			Certification of the Chief Executive Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 (furnished herewith)
32.2†			Certification of the Chief Financial Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 (furnished herewith)
101.INS†			XBRL Instance Document
101.SCH†			XBRL Taxonomy Extension Schema
101.CAL†			XBRL Taxonomy Extension Calculation Linkbase
101.DEF†			XBRL Taxonomy Extension Definition Linkbase
101.LAB†			XBRL Taxonomy Extension Label Linkbase
101.PRE†			XBRL Taxonomy Extension Presentation Linkbase
104			Cover Page Interactive Data File (formatted as Inline XBRL and contained in Exhibit 101)

_________________________

* Management Contract or Compensatory Plan or Arrangement

† Filed or furnished herewith

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SIGNATURES

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

CIVITAS RESOURCES, INC.

Date:

October 31, 2022

By:

/s/ Chris Doyle

Chris Doyle

President and Chief Executive Officer (principal executive officer)

By:

/s/ Marianella Foschi

Marianella Foschi

Chief Financial Officer (principal financial officer)

By:

/s/ Sandi K. Garbiso

Sandi K. Garbiso

Chief Accounting Officer and Treasurer (chief accounting officer)

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