Table of Contents
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 June 30, 20212022
or
☐ TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the transition period from _________ to _________
 Commission File Number:  001-35371
Bonanza Creek Energy, Inc.civi-20220630_g1.jpg
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.)
410555 17th Street,Suite 14003700
Denver,Colorado 80202
(Address of principal executive offices) (Zip Code)
(720) 440-6100(303) 293-9100
(Registrant’s telephone number, including area code)
Securities registered pursuant to Section 12(b) of the Act:
Title of each classTrading SymbolName of exchange on which registered
Common Stock, par value $0.01 per shareBCEICIVINew York Stock Exchange
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.  ☒ Yes ☐  No
Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit such files).  ☒ Yes  ☐  No
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, smaller reporting company, or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer”, “smaller reporting company,” and “emerging growth company” in Rule 12b-2 of the Exchange Act.
Large Accelerated Filer☐☒Accelerated Filer☒☐
Non-accelerated Filer☐
Emerging growthSmaller reporting company☐Smaller reporting
Emerging growth company☐
If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. ☐
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). ☐ Yes ☒  No
Indicate by check mark whether the registrant has filed all documents and reports required to be filed by Sections 12, 13 or 15(d) of the Securities Exchange Act of 1934 subsequent to the distribution of securities under a plan confirmed by a court. ☒  Yes ☐  No
As of August 5, 2021,1, 2022, the registrant had 30,848,88785,031,963 shares of common stock outstanding.


1
Table of Contents
BONANZA CREEK ENERGY,CIVITAS RESOURCES, INC.
INDEXFORM 10-Q
FOR THE QUARTER ENDED JUNE 30, 2022

TABLE OF CONTENTS

         PAGE
 
Condensed Consolidated Balance Sheets as of June 30, 20212022 and December 31, 20202021
16
 
27
2021
38
 
Condensed Consolidated Statements of Cash Flows for the Six Months Ended June 30, 20212022 and 20202021
49
 
510
2628
39
40
 
 
40
 
41
 
4641
 
4641
 
4641
 
4641
 
4642



2
Table of Contents
PART
Information Regarding Forward-Looking Statements
This Quarterly Report on Form 10-Q contains various statements, including those that express belief, expectation or intention, as well as those that are not statements of historic fact, that are forward-looking statements within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities and Exchange Act of 1934, as amended (the “Exchange Act”). When used in this Quarterly Report on Form 10-Q, the words “could,” “believe,” “anticipate,” “intend,” “estimate,” “expect,” “may,” “continue,” “predict,” “potential,” “project,” “plan,” “will,” and similar expressions are intended to identify forward-looking statements, although not all forward-looking statements contain such identifying words. These forward-looking statements are based on management's current belief, based on currently available information, as to the outcome and timing of future events.
Forward-looking statements include statements related to, among other things:
•the Company’s business strategies;
•reserves estimates;
•estimated sales volumes;
•the amount and allocation of forecasted capital expenditures and plans for funding capital expenditures and operating expenses;
•our ability to modify future capital expenditures;
•anticipated costs;
•compliance with debt covenants;
•our ability to fund and satisfy obligations related to ongoing operations;
•compliance with government regulations, including environmental, health, and safety regulations and liabilities thereunder;
•the adequacy of gathering systems and continuous improvement of such gathering systems;
•the impact from the lack of available gathering systems and processing facilities in certain areas;
•the impact of any pandemic or other public health epidemic, including the ongoing COVID-19 pandemic;
•oil, natural gas, and natural gas liquid prices and factors affecting the volatility of such prices;
•the impact of lower commodity prices;
•sufficiency of impairments;
•the ability to use derivative instruments to manage commodity price risk and ability to use such instruments in the future;
•our drilling inventory and drilling intentions;
•the impact of potentially disruptive technologies;
•our estimated revenue gains and losses;
•the timing and success of specific projects;
•our implementation of standard and long reach laterals;
•our intention to continue to optimize enhanced completion techniques and well design changes;
•stated working interest percentages;
•our management and technical team;
•outcomes and effects of litigation, claims, and disputes;
•primary sources of future production growth;
•our ability to replace oil and natural gas reserves;
•our ability to convert proved undeveloped reserves to producing properties within five years of their initial proved booking;
3
Table of Contents
•our ability to pay future cash dividends on our common stock;
•the impact of the loss a single customer or any purchaser of our products;
•the timing and ability to meet certain volume commitments related to purchase and transportation agreements;
•the impact of customary royalty interests, overriding royalty interests, obligations incident to operating agreements, liens for current taxes, and other industry-related constraints;
•our anticipated financial position, including our cash flow and liquidity;
•the adequacy of our insurance;
•the results, effects, benefits, and synergies of 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, - FINANCIAL INFORMATIONItem 1A of our Annual Report on Form 10-K for the year ended December 31, 2021 and in Part II, Item 1A of this report;
•declines or volatility in the prices we receive for our oil, natural gas, and natural gas liquids;
•general economic conditions, whether internationally, nationally or in the regional and local market areas in which we do business;
•the effects of disruption of our operations or excess supply of oil and natural gas due to world health events, including the COVID-19 pandemic, and the actions by certain oil and natural gas producing countries;
•the continuing effects of the COVID-19 pandemic, including any recurrence or the worsening thereof;
•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;
•exploration and development risks;
4
Table of Contents
•operational interruption of centralized oil and natural gas processing facilities;
•competition in the oil and natural gas industry;
•management’s ability to execute our plans to meet our goals;
•our ability to attract and retain key members of our senior management and key technical employees;
•our ability to maintain effective internal controls;
•access to adequate gathering systems and pipeline take-away capacity;
•our ability to secure adequate processing capacity for natural gas we produce, to secure adequate transportation for oil, natural gas, and natural gas liquids we produce, and to sell the oil, natural gas, and natural gas liquids at market prices;
•costs and other risks associated with perfecting title for mineral rights in some of our properties;
•political conditions in or affecting other producing countries, including conflicts in or relating to the Middle East, South America, and Russia (including the current events involving Russia and Ukraine), and other sustained military campaigns or acts of terrorism or sabotage; and
•other economic, competitive, governmental, legislative, regulatory, geopolitical, and technological factors that may negatively impact our businesses, operations, or pricing.
All forward-looking statements speak only as of the filing date of this report. We disclaim any obligation to update or revise these statements unless required by law, and you should not place undue reliance on these forward-looking statements. Although we believe that our plans, intentions, and expectations reflected in or suggested by the forward-looking statements we make in this report are reasonable, we can give no assurance that these plans, intentions, or expectations will be achieved. We disclose important factors that could cause our actual results to differ materially from our expectations under “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.
5
Table of Contents

PART I. FINANCIAL INFORMATION
Item 1. Financial Statements.
BONANZA CREEK ENERGY,CIVITAS RESOURCES, INC. AND SUBSIDIARIES
CONDENSEDCONSOLIDATED BALANCE SHEETS (UNAUDITED)
(in thousands, except per share amounts)
 June 30, 2021December 31, 2020
ASSETS  
Current assets:  
Cash and cash equivalents$24,403 $24,743 
Accounts receivable, net:  
Oil and gas sales77,533 32,673 
Joint interest and other20,082 14,748 
Prepaid expenses and other6,046 3,574 
Inventory of oilfield equipment13,990 9,185 
Derivative assets (note 10)0 7,482 
Total current assets142,054 92,405 
Property and equipment (successful efforts method):
  
Proved properties1,670,453 1,056,773 
Less: accumulated depreciation, depletion, and amortization(264,147)(211,432)
Total proved properties, net1,406,306 845,341 
Unproved properties96,348 98,122 
Wells in progress50,366 50,609 
Other property and equipment, net of accumulated depreciation of $4,065 in 2021 and $3,737 in 20205,718 3,239 
Total property and equipment, net1,558,738 997,311 
Right-of-use assets (note 4)28,595 29,705 
Deferred income tax assets (note 12)181,262 60,520 
Other noncurrent assets5,531 2,871 
Total assets$1,916,180 $1,182,812 
LIABILITIES AND STOCKHOLDERS’ EQUITY  
Current liabilities:  
Accounts payable and accrued expenses (note 4)$83,097 $37,425 
Oil and gas revenue distribution payable54,090 18,613 
Lease liability (note 2)12,313 12,044 
Derivative liability (note 10)80,866 6,402 
Total current liabilities230,366 74,484 
Long-term liabilities:  
Senior notes (note 5)100,000 0 
Credit facility (note 5)99,000 0 
Lease liability (note 4)16,543 17,978 
Ad valorem taxes and other22,678 15,069 
Derivative liability (note 10)11,285 1,330 
Asset retirement obligations for oil and gas properties (note 9)51,194 28,699 
Total liabilities531,066 137,560 
Commitments and contingencies (note 6)00
Stockholders’ equity:  
Preferred stock, $0.01 par value, 25,000,000 shares authorized, NaN outstanding0 0 
Common stock, $0.01 par value, 225,000,000 shares authorized, 30,844,625 and 20,839,227 issued and outstanding as of June 30, 2021 and December 31, 2020, respectively4,378 4,282 
Additional paid-in capital1,083,446 707,209 
Retained earnings297,290 333,761 
Total stockholders’ equity1,385,114 1,045,252 
Total liabilities and stockholders’ equity$1,916,180 $1,182,812 
June 30, 2022December 31, 2021
ASSETS  
Current assets:  
Cash and cash equivalents$439,251 $254,454 
Accounts receivable, net:  
Oil, natural gas, and NGL sales432,694 362,262 
Joint interest and other95,253 66,390 
Prepaid expenses and other31,064 21,052 
Inventory of oilfield equipment21,195 12,386 
Derivative assets— 3,393 
Total current assets1,019,457 719,937 
Property and equipment (successful efforts method):
  
Proved properties6,132,620 5,457,213 
Less: accumulated depreciation, depletion, and amortization(803,774)(430,201)
Total proved properties, net5,328,846 5,027,012 
Unproved properties666,821 688,895 
Wells in progress303,071 177,296 
Other property and equipment, net of accumulated depreciation of $6,072 in 2022 and $4,742 in 202150,243 51,639 
Total property and equipment, net6,348,981 5,944,842 
Right-of-use assets31,487 39,885 
Deferred income tax assets— 22,284 
Other noncurrent assets14,505 14,085 
Total assets$7,414,430 $6,741,033 
LIABILITIES AND STOCKHOLDERS’ EQUITY  
Current liabilities:  
Accounts payable and accrued expenses$306,270 $246,188 
Production taxes payable303,182 144,408 
Oil and natural gas revenue distribution payable494,091 466,233 
Lease liability17,452 18,873 
Derivative liability278,600 219,804 
Income tax payable50,385 — 
Asset retirement obligations24,000 24,000 
Total current liabilities1,473,980 1,119,506 
Long-term liabilities:  
Senior notes392,508 491,710 
Lease liability14,576 21,398 
Ad valorem taxes186,603 232,147 
Derivative liability43,225 19,959 
Deferred income tax liabilities107,884 — 
Asset retirement obligations203,104 201,315 
Total liabilities2,421,880 2,086,035 
Commitments and contingencies (Note 6)00
Stockholders’ equity:  
Preferred stock, $.01 par value, 25,000,000 shares authorized, none outstanding— — 
Common stock, $.01 par value, 225,000,000 shares authorized, 85,031,963 and 84,572,846 issued and outstanding as of June 30, 2022 and December 31, 2021, respectively4,917 4,912 
Additional paid-in capital4,197,790 4,199,108 
Retained earnings789,843 450,978 
Total stockholders’ equity4,992,550 4,654,998 
Total liabilities and stockholders’ equity$7,414,430 $6,741,033 
The accompanying notes are an integral part of these condensed consolidated financial statements.
16
Table of Contents
BONANZA CREEK ENERGY,CIVITAS RESOURCES, INC. AND SUBSIDIARIES
CONDENSEDCONSOLIDATED STATEMENTS OF OPERATIONS AND COMPREHENSIVE INCOME (LOSS) (UNAUDITED)
(in thousands, except per share amounts)
Three Months Ended June 30,Six Months Ended June 30,Three Months Ended June 30,Six Months Ended June 30,
2021202020212020 2022202120222021
Operating net revenues:Operating net revenues:  Operating net revenues:
Oil and gas sales$156,035 $36,192 $230,194 $96,597 
Oil, natural gas, and NGL salesOil, natural gas, and NGL sales$1,151,364 $156,035 $1,969,174 $230,194 
Operating expenses:Operating expenses: Operating expenses:
Lease operating expenseLease operating expense11,358 5,795 17,089 11,494 Lease operating expense41,877 11,358 77,896 17,089 
Midstream operating expenseMidstream operating expense4,246 3,354 8,151 7,368 Midstream operating expense7,469 4,246 13,181 8,151 
Gathering, transportation, and processingGathering, transportation, and processing13,721 3,711 18,688 7,192 Gathering, transportation, and processing79,519 13,721 129,922 18,688 
Severance and ad valorem taxesSeverance and ad valorem taxes9,813 3,478 14,417 8,651 Severance and ad valorem taxes85,870 9,813 149,174 14,417 
ExplorationExploration3,547 112 3,643 485 Exploration1,553 3,547 2,081 3,643 
Depreciation, depletion, and amortizationDepreciation, depletion, and amortization35,006 22,283 53,829 43,867 Depreciation, depletion, and amortization204,519 35,006 389,379 53,829 
Abandonment and impairment of unproved propertiesAbandonment and impairment of unproved properties2,215 309 2,215 30,366 Abandonment and impairment of unproved properties— 2,215 17,975 2,215 
Unused commitmentsUnused commitments4,328 0 4,328 0 Unused commitments1,731 4,328 2,507 4,328 
Bad debt expenseBad debt expense0 0 0 576 Bad debt expense4 — 4 — 
Merger transaction costsMerger transaction costs18,246 21 21,541 21 Merger transaction costs1,418 18,246 21,952 21,541 
General and administrative expense (including $2,195, $1,474, $3,807, and $2,713 respectively, of stock-based compensation)12,144 8,385 21,395 17,814 
General and administrative expense (including $6,135, $2,195, $14,225, and $3,807, respectively, of stock-based compensation)General and administrative expense (including $6,135, $2,195, $14,225, and $3,807, respectively, of stock-based compensation)29,666 12,144 65,386 21,395 
Total operating expensesTotal operating expenses114,624 47,448 165,296 127,834 Total operating expenses453,626 114,624 869,457 165,296 
Other income (expense):Other income (expense):  Other income (expense):
Derivative gain (loss)(73,970)(25,146)(97,389)75,273 
Interest expense, net(3,241)(984)(3,660)(1,201)
Loss on property transactions, net0 (1,398)0 (1,398)
Other income (expense)89 (118)277 (1,788)
Total other income (expense)(77,122)(27,646)(100,772)70,886 
Income (loss) from operations before taxes(35,711)(38,902)(35,874)39,649 
Income tax benefit10,392 0 10,436 0 
Derivative lossDerivative loss(72,650)(73,970)(368,143)(97,389)
Interest expenseInterest expense(8,116)(3,241)(17,182)(3,660)
Gain on property transactions, netGain on property transactions, net— — 16,797 — 
Other incomeOther income4,313 89 5,096 277 
Total other expenseTotal other expense(76,453)(77,122)(363,432)(100,772)
Income (loss) from operations before income taxesIncome (loss) from operations before income taxes621,285 (35,711)736,285 (35,874)
Income tax benefit (expense)Income tax benefit (expense)(152,464)10,392 (175,825)10,436 
Net income (loss)Net income (loss)$(25,319)$(38,902)$(25,438)$39,649 Net income (loss)$468,821 $(25,319)$560,460 $(25,438)
Comprehensive income (loss)Comprehensive income (loss)$(25,319)$(38,902)$(25,438)$39,649 Comprehensive income (loss)$468,821 $(25,319)$560,460 $(25,438)
Net income (loss) per common share:Net income (loss) per common share:Net income (loss) per common share:
BasicBasic$(0.83)$(1.87)$(0.99)$1.91 Basic$5.52 $(0.83)$6.60 $(0.99)
DilutedDiluted$(0.83)$(1.87)$(0.99)$1.91 Diluted$5.48 $(0.83)$6.56 $(0.99)
Weighted-average common shares outstanding:
Weighted-average common shares outstandingWeighted-average common shares outstanding
BasicBasic30,655 20,776 25,774 20,713 Basic84,993 30,655 84,917 25,774 
DilutedDiluted30,655 20,776 25,774 20,759 Diluted85,554 30,655 85,453 25,774 
The accompanying notes are an integral part of these condensed consolidated financial statements.




27
Table of Contents
BONANZA CREEK ENERGY,CIVITAS RESOURCES, INC. AND SUBSIDIARIES
CONDENSEDCONSOLIDATED STATEMENTS OF STOCKHOLDERS'STOCKHOLDERS’ EQUITY (UNAUDITED)
(in thousands, except per share amounts)
Additional
Common StockPaid-InRetained
SharesAmountCapitalEarningsTotal
Balances, December 31, 202020,839,227 $4,282 $707,209 $333,761 $1,045,252 
Restricted common stock issued109 — — — — 
Stock used for tax withholdings(38)— — — — 
Exercise of stock options429 — 15 — 15 
Stock-based compensation— — 1,612 — 1,612 
Net loss— — — (119)(119)
Balances, March 31, 202120,839,727 4,282 708,836 333,642 1,046,760 
Issuance pursuant to acquisition9,802,166 98 374,835 — 374,933 
Restricted common stock issued261,539 — — — — 
Stock used for tax withholdings(70,330)(2)(2,814)— (2,816)
Exercise of stock options11,523 — 394 — 394 
Stock-based compensation— — 2,195 — 2,195 
Dividends declared— — — (11,033)(11,033)
Net loss— — — (25,319)(25,319)
Balances, June 30, 202130,844,625 $4,378 $1,083,446 $297,290 $1,385,114 
Additional
Common StockPaid-InRetained
SharesAmountCapitalEarningsTotal
Balances, December 31, 202184,572,846 $4,912 $4,199,108 $450,978 $4,654,998 
Restricted common stock issued579,229 6 — — 6 
Stock used for tax withholdings(215,811)(2)(12,932)— (12,934)
Exercise of stock options5,294 — 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, 202284,941,558 4,916 4,194,444 438,173 4,637,533 
Restricted common stock issued130,309 1 — — 1 
Stock used for tax withholdings(40,646)— (2,813)— (2,813)
Exercise of stock options742 — 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, 202285,031,963 $4,917 $4,197,790 $789,843 $4,992,550 

Balances, December 31, 201920,643,738 $4,284 $702,173 $230,233 $936,690 
Balances, December 31, 2020Balances, December 31, 202020,839,227 $4,282 $707,209 $333,761 $1,045,252 
Restricted common stock issuedRestricted common stock issued13,674 — — — — Restricted common stock issued109 — — — — 
Stock used for tax withholdingsStock used for tax withholdings(38)— — — — 
Exercise of stock optionsExercise of stock options429 — 15 — 15 
Stock-based compensationStock-based compensation— — 1,612 — 1,612 
Net lossNet loss— — — (119)(119)
Balances, March 31, 2021Balances, March 31, 202120,839,727 4,282 708,836 333,642 1,046,760 
Issuance pursuant to acquisitionIssuance pursuant to acquisition9,802,166 98 374,835 — 374,933 
Restricted common stock issuedRestricted common stock issued261,539 — — — — 
Stock used for tax withholdingsStock used for tax withholdings(2,330)— (61)— (61)Stock used for tax withholdings(70,330)(2)(2,814)— (2,816)
Exercise of stock optionsExercise of stock options11,523 — 394 — 394 
Stock-based compensationStock-based compensation— — 1,239 — 1,239 Stock-based compensation— — 2,195 — 2,195 
Net income— — — 78,551 78,551 
Balances, March 31, 202020,655,082 4,284 703,351 308,784 1,016,419 
Restricted common stock issued228,149 — — — — 
Stock used for tax withholdings(56,904)(2)(951)— (953)
Stock-based compensation— — 1,474 — 1,474 
Dividends declared, $0.3500 per shareDividends declared, $0.3500 per share— — — (11,033)(11,033)
Net lossNet loss— — — (38,902)(38,902)Net loss— — — (25,319)(25,319)
Balances, June 30, 202020,826,327 $4,282 $703,874 $269,882 $978,038 
Balances, June 30, 2021Balances, June 30, 202130,844,625 $4,378 $1,083,446 $297,290 $1,385,114 
The accompanying notes are an integral part of these condensed consolidated financial statements.


38
Table of Contents
BONANZA CREEK ENERGY,CIVITAS RESOURCES, INC. AND SUBSIDIARIES
CONDENSEDCONSOLIDATED STATEMENTS OF CASH FLOWS
(UNAUDITED)
(in thousands)
 Six Months Ended June 30,
 20212020
Cash flows from operating activities:
Net income (loss)$(25,438)$39,649 
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation, depletion, and amortization53,829 43,867 
Deferred income tax benefit(10,228)0 
Abandonment and impairment of unproved properties2,215 30,366 
Well abandonment costs and dry hole expense0 (8)
Stock-based compensation3,807 2,713 
Non-cash lease component(35)(103)
Amortization of deferred financing costs526 680 
Derivative (gain) loss97,389 (75,273)
Derivative cash settlement gain (loss)(23,990)33,867 
Loss on property transactions, net0 1,398 
Other0 (2,708)
Changes in current assets and liabilities:
Accounts receivable, net(14,686)24,521 
Prepaid expenses and other assets2,500 2,812 
Accounts payable and accrued liabilities(3,428)(31,957)
Settlement of asset retirement obligations(2,902)(1,595)
Net cash provided by operating activities79,559 68,229 
Cash flows from investing activities:
Acquisition of oil and gas properties(549)(549)
Cash acquired49,827 0 
Exploration and development of oil and gas properties(57,269)(51,054)
Additions to other property and equipment(38)(416)
Net cash used in investing activities(8,029)(52,019)
Cash flows from financing activities:
Proceeds from credit facility155,000 30,000 
Payments to credit facility(210,000)(52,000)
Proceeds from exercise of stock options409 0 
Payment of employee tax withholdings in exchange for the return of common stock(2,816)(1,014)
Dividends paid(10,789)0 
Deferred financing costs(3,653)(13)
Principal payments on finance lease obligations(21)(40)
Net cash used in financing activities(71,870)(23,067)
Net change in cash, cash equivalents, and restricted cash(340)(6,857)
Cash, cash equivalents, and restricted cash:
Beginning of period24,845 11,095 
End of period$24,505 $4,238 
Supplemental cash flow disclosure(1):
Cash paid for interest, net of capitalization$87 $670 
Receivables exchanged for additional interests in oil and gas properties$0 $8,299 
Changes in working capital related to drilling expenditures$(16,285)$(2,382)
(1) Refer to Note 4 - Leases in the notes to the condensed consolidated financial statements for supplemental cash flows related to leases.
 Six Months Ended June 30,
 20222021
Cash flows from operating activities:
Net income (loss)$560,460 $(25,438)
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation, depletion, and amortization389,379 53,829 
Deferred income tax expense (benefit)125,440 (10,228)
Abandonment and impairment of unproved properties17,975 2,215 
Stock-based compensation14,225 3,807 
Amortization of deferred financing costs2,180 526 
Derivative loss368,143 97,389 
Derivative cash settlements loss(348,209)(23,990)
Gain on property transactions, net(16,797)— 
Other155 (35)
Changes in current assets and liabilities:
Accounts receivable, net(32,776)(14,686)
Prepaid expenses and other assets(6,579)2,500 
Accounts payable and accrued liabilities192,839 (3,428)
Settlement of asset retirement obligations(11,667)(2,902)
Net cash provided by operating activities1,254,768 79,559 
Cash flows from investing activities:
Acquisition of oil and natural gas properties(303,602)(549)
Cash acquired44,310 49,827 
Exploration and development of oil and natural gas properties(467,186)(57,269)
Purchases of carbon offsets(7,196)— 
Proceeds from (additions to) other property and equipment66 (38)
Other117 — 
Net cash used in investing activities(733,491)(8,029)
Cash flows from financing activities:
Proceeds from credit facility100,000 155,000 
Payments to credit facility(100,000)(210,000)
Redemption of senior notes(100,000)— 
Proceeds from exercise of stock options202 409 
Dividends paid(219,768)(10,789)
Payment of employee tax withholdings in exchange for the return of common stock(15,740)(2,816)
Deferred financing costs(1,174)(3,653)
Other— (21)
Net cash used in financing activities(336,480)(71,870)
Net change in cash, cash equivalents, and restricted cash184,797 (340)
Cash, cash equivalents, and restricted cash:
Beginning of period254,556 24,845 
End of period(1)
$439,353 $24,505 
Supplemental cash flow disclosure:
Cash paid for interest$(15,821)$(87)
Cash paid for income taxes$(6,300)$— 
Changes in working capital related to drilling expenditures$(2,666)$(16,285)
(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 June 30, 2022 and 2021.
The accompanying notes are an integral part of these condensed consolidated financial statements.
49
Table of Contents
BONANZA CREEK ENERGY,CIVITAS RESOURCES, INC. AND SUBSIDIARIES
NOTES TO THE CONDENSEDCONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED)

NOTE 1 - ORGANIZATION AND BUSINESSSUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
Description of Operations
When we use the terms “Civitas,” the “Company,” “we,” “us,” or “our,” we are referring to Civitas Resources, Inc. and its consolidated subsidiaries unless the context otherwise requires. Effective November 1, 2021, Bonanza Creek Energy, Inc. (“BCEI” or, together with our consolidated subsidiaries,changed its name to Civitas Resources, Inc. Civitas is an independent Denver-based exploration and production company focused on the “Company”) is engaged primarily in acquiring, developing, extracting,acquisition, development, and producingproduction of oil and associated liquids-rich natural gas properties. The Company’s assets and operations are concentrated in the rural portions ofRocky Mountain region, primarily in the Wattenberg Field in Colorado.of the Denver-Julesburg Basin (“DJ Basin”).
Basis of Presentation
NOTE 2 - BASIS OF PRESENTATION
TheseThe accompanying unaudited condensed consolidated financial statements include the accounts of the Company and have been prepared in accordance with U.S.accounting principles generally accepted accounting principlesin the United States (“GAAP”) for interim financial statementsinformation, the instructions to Quarterly Report on Form 10-Q, and Regulation S-X. Accordingly, pursuant to thesuch rules and regulations, of the Securitiescertain notes and Exchange Commission.other financial information included in audited financial statements have been condensed or omitted. In the opinion of management, the accompanying unaudited condensed consolidated financial statements reflect all adjustments, consisting of normal recurring adjustments asconsidered necessary for a fair presentation of our financial position and results of operations.
Theinterim financial information, as ofhave been included. All significant intercompany balances and transactions have been eliminated in consolidation.
The December 31, 2020,2021 unaudited condensed consolidated balance sheet data has been derived from the audited consolidated financial statements contained in our Annual Report on Form 10-K for the year ended December 31, 20202021 (“20202021 Form 10-K”10-K”), but does not include all disclosures, including notes required by GAAP. As such, this quarterly report should be read in conjunction with the audited consolidated financial statements and related notes included in our 20202021 Form 10-K. The Company follows the same accounting principles for preparing quarterly and annual reports. Certain prior period amounts have been reclassified to conform to the current period presentation.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 June 30, 2021,2022, through the filing date of this report.
Principles of Consolidation
The condensed consolidated balance sheets (“balance sheets”) include the accounts of the Company and its wholly owned subsidiaries, Bonanza Creek Energy Operating Company, LLC, Boron Merger Sub, Inc., Holmes Eastern Company, LLC, and Rocky Mountain Infrastructure, LLC. All intercompany accounts and transactions have been eliminated.
Use of Estimates
The preparation of the Company’s condensed consolidated financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of oil and gas reserves, assets and liabilities, and disclosure of contingent assets and liabilities at the date of the balance sheet and the reported amounts of revenue and expenses during the reporting period. Actual results could differ from those estimates. The results of operations for the three and six months ended June 30, 2021,2022 are not necessarily indicative of the results that may be expected for the full year ending December 31, 2021. Further these estimates andor any other factors, including those outsidefuture period.
Significant Accounting Policies
The significant accounting policies followed by the Company are set forth in Note 1 - Summary of the Company's control, such as the impact of lower commodity prices, may impact the Company's business, financial condition, results of operations and cash flows.
Industry Segment and Geographic Information
The Company operates in 1 industry segment, which is the development and production of oil, natural gas, and natural gas liquids (“NGLs”), and all of the Company's operations are conductedSignificant Accounting Policies in the continental United States.
Revenue Recognition
Sales of oil, natural gas,2021 Form 10-K and NGLs are recognized when performance obligations are satisfied atsupplemented by the point control of the product is transferrednotes to the customer. The Company's contracts' pricing provisions are tied to a market index, with certain adjustments based on, among other factors, whether a well delivers to a gathering or transmission line, quality of the oil or natural gas, and prevailing supply and demand conditions. As a result, the price of the oil, natural gas, and NGLs fluctuates to remain competitive with other available oil, natural gas, and NGLs supplies.
As further described in Note 6 - Commitments and Contingencies, one contract with NGL Crude Logistics, LLP (“NGL Crude”, known as the “NGL Crude agreement”) has an additional aspect of variable consideration related to the minimum volume commitments (“MVCs”) as specified in the agreement. On an on-going basis, the Company performs an analysis of expected risk adjusted production applicable to the NGL Crude agreement based on approved production plans to determine if liquidated damages to NGL Crude are probable. As of June 30, 2021, the Company believes that the volumes
5
Table of Contents
delivered to NGL Crude will be in excess of the MVCs required then and for the upcoming approved production plan. As a result of this analysis, to date, no variable consideration related to potential liquidated damages has been considered in the transaction price for the NGL Crude agreement.
Under the oil sales contracts, the Company sells oil production at the wellhead, or other contractually agreed-upon delivery points, and collects an agreed-upon index price, net of pricing differentials. In this scenario, the Company recognizes revenue when control transfers to the purchaser at the wellhead, or other contractually agreed-upon delivery point, at the net contracted price received.
Under the natural gas processing contracts, the Company delivers natural gas to an agreed-upon delivery point. The delivery points are specified within each contract, and the transfer of control varies between the inlet and outlet of the midstream processing facility. The midstream processing entity gathers and processes the natural gas and remits proceeds to the Company for the resulting sales of NGLs and residue gas. For the contracts where the Company maintains control through the outlet of the midstream processing facility, the Company recognizes revenue on a gross basis, with gathering, transportation, and processing fees presented as an expense in the Company's accompanyingunaudited condensed consolidated financial statements of operations and comprehensive income (loss) (“statements of operations”). Alternatively, for those contracts where the Company relinquishes control at the inlet of the midstream processing facility, the Company recognizes natural gas and NGLs revenues based on the contracted amount of the proceeds received from the midstream processing entity and, as a result, the Company recognizes revenue on a net basis.    
Under the product sales contracts, the Company invoices customers once the performance obligations have been satisfied, at which point payment is unconditional. Accordingly, the Company's product sales contracts do not give rise to contract assets or liabilities underincluded in this guidance. At June 30, 2021 and December 31, 2020, the Company's receivables from contracts with customers were $77.5 million and $32.7 million, respectively. Payment is generally received within 30 to 60 days after the date of production.
The Company records revenue in the month production is delivered to the purchaser. However, as stated above, settlement statements for certain natural gas and NGLs sales may not be received for 30 to 60 days after the date production is delivered, and as a result, the Company is required to estimate the amount of production delivered to the purchaser and the price that will be received for the sale of the product. The Company records the differences between its estimates and the actual amounts received for product sales in the month in which payment is received from the purchaser. For the period from January 1, 2021 through June 30, 2021, revenue recognized in the reporting period related to performance obligations satisfied in prior reporting periods was insignificant.
Revenue attributable to each identified revenue stream is disaggregated below (in thousands):
Three Months Ended June 30,Six Months Ended June 30,
2021202020212020
Operating Revenues:
   Crude oil sales$116,091 $28,934 $166,155 $80,080 
   Natural gas sales15,168 4,712 28,300 10,730 
   Natural gas liquids sales24,776 2,546 35,739 5,787 
Oil and gas sales$156,035 $36,192 $230,194 $96,597 
Restricted Cash
The following table provides a reconciliation of cash, cash equivalents, and restricted cash reported within the balance sheets, which sums to the total of such amounts shown in the accompanying condensed consolidated statements of cash flows (“statements of cash flows”) (in thousands):
As of June 30,
20212020
Cash and cash equivalents$24,403 $4,144 
Restricted cash(1)
102 94 
Total cash, cash equivalents, and restricted cash$24,505 $4,238 
__________________________report.
(1) Included in other noncurrent assetsRecently Issued and consists of funds for road maintenance and repairs.
6
Table of Contents
Unproved Property
Unproved oil and gas property costs are evaluated for impairment when there is an indication that the carrying costs may not be fully recoverable. During both the three and six months ended June 30, 2021, the Company incurred $2.2 million in abandonment and impairment of unproved properties compared to $0.3 million and $30.4 million during the three and six months ended June 30, 2020, respectively, due to the reassessment of estimated probable and possible reserve locations based primarily upon economic viability and the expiration of non-core leases.
Accounts Payable and Accrued Expenses
Accounts payable and accrued expenses contain the following (in thousands):
 As of June 30, 2021As of December 31, 2020
Accrued drilling and completion costs$16,738 $453 
Accounts payable trade13,150 1,931 
Accrued general and administrative expense6,046 4,942 
Accrued merger transaction costs2,426 2,587 
Accrued lease operating expense4,298 1,793 
Accrued interest expense3,368 322 
Accrued oil and gas hedging8,820 0 
Accrued production and ad valorem taxes and other28,251 25,397 
Total accounts payable and accrued expenses$83,097 $37,425 
Adopted Accounting Pronouncements Recently Adopted and IssuedStandards
In March 2020, the FASB issued Update No. 2020-04, Reference Rate Reform (Topic 848), which provides temporary optional guidance to companies impacted by the transition away from the LIBOR. The amendment provides certain expedients and exceptions to applying GAAP in order to lessen the potential accounting burden when contracts, hedging relationships, and other transactions that reference LIBOR as a benchmark rate are modified. Further, in January 2021, the FASB issued Update No. 2021-01, Reference Rate Reform (Topic 848), which clarifies the scope of Topic 848 so that derivatives affected by the discounting transition are explicitly eligible for certain optional expedients and exceptions in Topic 848. These amendments are effective upon issuance and expire on December 31, 2022. The Company is currently assessing theWe do not anticipate a material impact of the LIBOR transition on the Company's condensedCompany’s consolidated financial statements.statements or related disclosures.
There are no other accounting standards applicable to the Company that would have a material effect on the Company's condensed consolidatedCompany’s financial statements and disclosures that have been issued but not yet adopted by the Company as of June 30, 2021,2022, and through the filing date of this report.
10
NOTE 3 - ACQUISITIONS & DIVESTITURES
HighPoint Acquisition
On April 1, 2021, Bonanza Creek completed its previously announced acquisition of HighPoint Resources Corporation, a Delaware corporation (“HighPoint”), pursuant to the terms of HighPoint’s prepackaged plan of reorganization under Chapter 11 of the United States Bankruptcy Code (the “Prepackaged Plan”), which was confirmed by the U.S. Bankruptcy Court for the District of Delaware on March 18, 2021 pursuant to a confirmation order, and went effective on April 1, 2021 (the “HighPoint Merger”).
The Prepackaged Plan implements the merger and restructuring transactions in accordance with the Agreement and Plan of Merger, dated as of November 9, 2020 (the “HighPoint Merger Agreement”), by and among Bonanza Creek, HighPoint and Boron Merger Sub, Inc., a wholly-owned subsidiary of Bonanza Creek (“Merger Sub”). Pursuant to the Prepackaged Plan and the HighPoint Merger Agreement, at the effective time of the HighPoint Merger (the “Effective Time”) and the effective date under the Prepackaged Plan, Merger Sub merged with and into HighPoint, with HighPoint continuing as the surviving corporation and wholly-owned subsidiary of Bonanza Creek. At the Effective Time, each eligible share of common stock, par value $0.001 per share, of HighPoint issued and outstanding immediately prior to the Effective Time was automatically converted into the right to receive 0.11464 shares of common stock, par value $0.01 per share, of Bonanza Creek (“Bonanza Creek Common Stock”), with cash paid in lieu of the issuance of any fractional shares. As a result, the Company issued approximately 487,952 shares of Bonanza Creek Common Stock to former HighPoint stockholders.
7
Table of Contents
Concurrently with the HighPoint MergerNOTE 2 - ACQUISITIONS AND DIVESTITURES
All mergers and pursuant to the Prepackaged Plan, and in exchange for the $625 million in aggregate principal amount outstanding of 7.0% Senior Notes due 2022 of HighPoint Operating Corporation (“HighPoint OpCo”) and 8.75% Senior Notes due 2025 of HighPoint OpCo (collectively, the “HighPoint Senior Notes”), Bonanza Creek issued to all holders of HighPoint Senior Notes an aggregate of (i) 9,314,214 shares of Bonanza Creek Common Stock and (ii) $100 million aggregate principal amount of 7.5% Senior Notes due 2026 of Bonanza Creek (“Bonanza Creek Senior Notes”). Please refer to Note 5 - Long-term Debt for further discussion of the Bonanza Creek Senior Notes.
Immediately after the Effective Time, in connection with the HighPoint Merger, Bonanza Creek entered into the Second Amendment, dated April 1, 2021, to the Credit Facility. Please refer to Note 5 - Long-term Debt for further discussion.
The following tables present the HighPoint Merger consideration and purchase price allocation of the assets acquired and the liabilities assumed in the HighPoint Merger:
Merger Consideration (in thousands except per share amount)
Shares of Bonanza Creek Common Stock issued to existing holders of HighPoint Common Stock(1)
488 
Shares of Bonanza Creek Common Stock issued to existing holders of HighPoint Senior Notes9,314 
Total additional shares of Bonanza Creek Common Stock issued as merger consideration9,802 
Closing price per share of Bonanza Creek Common Stock(2)
$38.25 
Merger consideration paid in shares of Bonanza Creek Common Stock$374,933 
Aggregate principal amount of Bonanza Creek Senior Notes100,000 
Total merger consideration$474,933 
_________________________
(1) Based on the number of shares of HighPoint Common Stock issued and outstanding as of April 1, 2021 and the conversion ratio of 0.11464 per share of Bonanza Creek Common Stock.
(2) Based on the closing stock price of Bonanza Creek Common Stock on April 1, 2021.


8
Table of Contents
Purchase Price Allocation (in thousands)
Assets Acquired
Cash and cash equivalents$49,827 
Accounts receivable - oil and gas sales26,343 
Accounts receivable - joint interest and other9,161 
Prepaid expenses and other3,608 
Inventory of oilfield equipment4,688 
Proved properties539,820 
Other property and equipment, net of accumulated depreciation2,769 
Right-of-use assets4,010 
Deferred income tax assets110,513 
Other noncurrent assets797 
Total assets acquired$751,536 
Liabilities Assumed
Accounts payable and accrued expenses$51,088 
Oil and gas revenue distribution payable20,786 
Lease liability744 
Derivative liability13,481 
Current portion of long-term debt154,000 
Lease liability (long-term)3,266 
Ad valorem taxes3,746 
Derivative liability (long-term)5,019 
Asset retirement obligations for oil and gas properties24,473 
Total liabilities assumed276,603 
Net assets acquired$474,933 
As part of the HighPoint Merger, the Company obtained net operating losses of $170.6 million. The HighPoint Merger wasacquisitions 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 arewere based on inputs that are not observable in the market, and therefore represent Level 3 inputs. The fair values of crude oil and natural gas properties and asset retirement obligations were measured using valuation techniques that convert future cash flows to a single discounted amount. Significant inputs to the valuation of proved oil and gas properties include estimates of reserves, future operating and development costs, future commodity prices, estimated future cash flows, and a market-based weighted-average cost of capital rate of approximately 13%.capital. These inputs requirerequired 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. In addition, Converted RSUs subject to performance-based vesting conditions held by certain Extraction executives provided certain accelerated vesting clauses in the event that such individual’s employment is terminated on or within twelve months following November 1, 2021.
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.
11
Table of Contents
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 sales119,585 
Accounts receivable - joint interest and other33,054 
Prepaid expenses and other3,044 
Inventory of oilfield equipment9,291 
Derivative assets5,834 
Proved properties1,876,014 
Unproved properties193,400 
Other property and equipment, net of accumulated depreciation40,068 
Right-of-use assets6,883 
Deferred income tax assets49,194 
Other noncurrent assets4,248 
Total assets acquired$2,446,975 
Liabilities Assumed
Accounts payable and accrued expenses$90,353 
Production taxes payable63,572 
Oil and natural gas revenue distribution payable170,002 
Income tax payable14,000 
Lease liability6,883 
Derivative liability100,474 
Ad valorem taxes87,071 
Asset retirement obligations68,741 
Other noncurrent liabilities1,750 
Total liabilities assumed602,846 
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.
12
Table of Contents
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 sales81,340 
Accounts receivable - joint interest and other9,917 
Prepaid expenses and other2,929 
Inventory of oilfield equipment11,951 
Proved properties1,797,814 
Unproved properties453,321 
Other property and equipment, net of accumulated depreciation7,980 
Right-of-use assets7,934 
Total assets acquired$2,440,691 
Liabilities Assumed
Accounts payable and accrued expenses$134,791 
Production taxes payable52,435 
Oil and natural gas revenue distribution payable83,950 
Lease liability7,934 
Derivative liability338,383 
Credit facility280,000 
Ad valorem taxes66,913 
Deferred income tax liabilities125,086 
Asset retirement obligations88,949 
Total liabilities assumed1,178,441 
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.
13
Table of Contents
Revenue and earnings of the acquiree
The amount of revenue of HighPoint included in our statement of operations during the three and six months ended June 30, 2021 was $74.7 million for both periods as the HighPoint Merger was completed on April 1, 2021. There was no revenue included in our statement of operations during the three and six months ended June 30, 2021 related to the Extraction and Crestone Peak mergers as both mergers were completed after June 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 six months ended June 30, 2021 and for the three and six months ended June 30, 2020,2021, assuming the acquisitionHighPoint, Extraction, and Crestone Peak mergers had been completed as of January 1, 2020. The financial information for the three months ended June 30, 2021 is included in our statement of operations and therefore does not require a pro forma disclosure. The pro forma financial information includes certain non-recurring pro forma adjustments that were directly attributable to the business combination. The pro forma financial information is not necessarily indicative of the results of operations that would have been achieved if the acquisitionmergers had been effective as of these dates,this date, or of future results.results, and includes certain non-recurring pro forma adjustments that were directly attributable to the business combinations (in thousands, except per share amounts).
9
Table of Contents
Three Months Ended June 30, 2021Six Months Ended June 30, 2021
Total revenue$527,794 $1,093,110 
Net income (loss)(101,825)756,271 
Net income (loss) per common share - basic$(1.21)$8.98 
Net income (loss) per common share - diluted$(1.21)$8.94 
Three Months Ended June 30,Six Months Ended June 30,
202020212020
(in thousands, except per share data)
Total revenue$79,492 $302,213 $219,463 
Net loss(78,410)(66,717)(1,023,673)
Net loss per common share:
Basic$(2.56)$(2.18)$(33.55)
Diluted$(2.56)$(2.18)$(33.55)
Extraction MergerBison Acquisition
On May 9, 2021, Bonanza Creek, Raptor Eagle Merger Sub, Inc., a Delaware corporation and a wholly owned subsidiaryMarch 1, 2022, the Company completed the acquisition of Bonanza Creek, and Extractionprivately held DJ Basin operator Bison Oil & Gas Inc.,II, LLC (“Bison”) for merger consideration of approximately $279.7 million (the “Bison Acquisition”). Net assets acquired under the preliminary purchase price allocation were $294.2 million and consequently resulted in a Delaware corporation (“XOG”), entered into an Agreement and Planbargain purchase gain of Merger (the “XOG Merger Agreement”), providing for a merger of equals between Bonanza Creek and XOG (the “XOG Merger”). The XOG Merger is expected to close in the fourth quarter of 2021, contingent upon a number of factors disclosed in the XOG Merger Agreement. Once closed, the Company intends to increase annual dividend payments to approximately $1.60 per share.
Crestone Peak Merger
On June 6, 2021, Bonanza Creek, Raptor Condor Merger Sub 1, Inc., a Delaware corporation and a wholly owned subsidiary of Bonanza Creek (“Merger Sub 1”), Raptor Condor Merger Sub 2, LLC, a Delaware limited liability company and a wholly owned subsidiary of BCEI (“Merger Sub 2”), Crestone Peak Resources LP, a Delaware limited partnership (“CPR”), CPPIB Crestone Peak Resources America Inc., a Delaware corporation (“Crestone Peak”), Crestone Peak Resources Management LP, a Delaware limited partnership (“CPR Management LP”), and, Extraction Oil & Gas, Inc., a Delaware corporation, entered into an Agreement and Plan of Merger (the “Crestone Peak Merger Agreement”).
The Crestone Peak Merger Agreement, among other things, provides for the Company's acquisition of Crestone Peak through (i) the merger of Merger Sub 1 with and into Crestone Peak (the “Merger Sub 1 Merger”), with Crestone Peak continuing its existence as the surviving corporation following the Merger Sub 1 Merger (the “Surviving Corporation”), and (ii) the subsequent merger$14.5 million. Because of the Surviving Corporation with and into Merger Sub 2 (the “Merger Sub 2 Merger” and together with the Merger Sub 1 Merger, the “Crestone Peak Merger”), with Merger Sub 2 continuing as the surviving entity as a wholly owned subsidiary of Bonanza Creek.
The closingimmateriality of the Crestone Peak Bison Acquisition, the related revenue and earnings, supplemental pro forma financial information, and detailed purchase price allocation are not disclosed.
Merger is expressly conditioned on the closing of the previously announced XOG transaction costs
Merger pursuant to the XOG Merger Agreement. The Crestone Peak Merger is expected to close in conjunction with the XOG merger in the fourth quarter of 2021, contingent upon a number of factors disclosed in the Crestone Peak Merger Agreement. Once closed, the Company intends to increase annual dividend payments to approximately $1.85 per share.
Acquisitiontransaction costs of $18.2 million and $21.5 million related to the aforementioned mergers and acquisitions wereare accounted for separately from the assets acquired and liabilities assumed and are included in merger transaction costs in the Company'sstatements of operations. The Company incurred merger transaction costs of $1.4 million and $18.2 million during the three months ended June 30, 2022 and 2021, respectively, and $22.0 million and $21.5 million during the six months ended June 30, 2022 and 2021, respectively. Merger transaction costs include zero and $1.1 million of severance payments for the three months ended June 30, 2022 and 2021, respectively, and $7.6 million and $1.1 million of severance payments for the six months ended June 30, 2022 and 2021, respectively.
NOTE 3 - REVENUE RECOGNITION
Oil, natural gas, and natural gas liquid (“NGL”) sales revenue presented within the accompanying statements of operations is reflective of the revenue generated from contracts with customers. Revenue attributable to each identified revenue stream is disaggregated below (in thousands):
Three Months Ended June 30,Six Months Ended June 30,
2022202120222021
Operating net revenues:
Oil sales$778,258 $116,091 $1,327,760 $166,155 
Natural gas sales205,840 15,168 319,001 28,300 
NGL sales167,266 24,776 322,413 35,739 
Oil, natural gas, and NGL sales$1,151,364 $156,035 $1,969,174 $230,194 
14
Table of Contents
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-Kfor 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 six months ended June 30, 2022 and 2021, revenue recognized in the reporting period related to performance obligations satisfied in prior reporting periods was insignificant. At June 30, 2022 and December 31, 2021, the Company's receivables from contracts with customers were $432.7 million and $362.3 million, respectively.
10
Table of Contents
NOTE 4 - LEASESACCOUNTS PAYABLE AND ACCRUED EXPENSES
The Company's right-of-use assetsAccounts payable and lease liabilities are recognized at their discounted present value onaccrued expenses contain the balance sheet, which include leases related to the asset classes reflectedfollowing as of the dates indicated in the table below (in thousands):
June 30, 2021December 31, 2020
Operating leases
Field equipment(1)
$23,606 $27,537 
Corporate leases4,011 1,481 
Vehicles978 468 
Total right-of-use asset$28,595 $29,486 
Field equipment(1)
$23,606 $27,537 
Corporate leases4,272 1,900 
Vehicles978 468 
Total lease liability$28,856 $29,905 
Finance leases
Right-of-use asset - field equipment(1)
$0 $219 
Lease liability - field equipment(1)
$0 $117 
__________________________
 June 30, 2022December 31, 2021
Accounts payable trade$12,166 $19,623 
Accrued drilling and completion costs132,096 129,430 
Accrued lease operating expense and gathering, transportation, and processing80,834 19,077 
Accrued general and administrative expense13,973 21,163 
Accrued merger transaction costs2,199 1,475 
Accrued oil and NGL hedging44,730 26,601 
Accrued interest expense5,484 6,303 
Accrued settlement10,291 20,791 
Other accrued expenses4,497 1,725 
Total accounts payable and accrued expenses$306,270 $246,188 
(1) Includes compressors, certain gas processing equipment, and other field equipment.

NOTE 5 - LONG-TERM DEBT
The lease amounts disclosed are presented on a gross basis. A portion of these costs may have been or will be billed to other working interest owners, and the Company's net share of these costs, once paid, are included in various line items on the statements of operations or capitalized to oil and gas properties or other property and equipment, as applicable.5.0% Senior Notes
The Company recognizes operating lease expense on a straight-line basis. Finance lease expense is recognized based on the effective interest method for the lease liability and straight-line amortization for the right-of-use asset, resulting in more cost being recognized in earlier lease periods. Short-term and variable lease payments are recognized as incurred. Short-term lease cost represents payments for leases with a lease term of one year or less, excluding leases with a term of one month or less. Short-term leases include drilling rigs and other equipment. Drilling rig contracts are structured based on an allotted number of wells to be drilled consecutively at a daily operating rate. Short-term drilling rig costs include a non-lease labor component, which is treated as a single lease component.

11
Table of Contents
The following table summarizes the components of the Company's gross lease costs incurred during the three and six months ended June 30,On October 13, 2021, and 2020 (in thousands):
Three Months Ended June 30,Six Months Ended June 30,
2021202020212020
Operating lease cost(1)
$3,557 $3,607 $6,894 $7,098 
Finance lease cost:
Amortization of right-of-use assets0 5 3 7 
Interest on lease liabilities0 1 1 2 
Short-term lease cost164 292 211 1,882 
Variable lease cost(2)
95 (135)65 (44)
Sublease income(3)
(91)(89)(183)(178)
Total lease cost$3,725 $3,681 $6,991 $8,767 
____________________________
(1) Includes office rent expense of $0.5 million and $0.3 million for the three months ended June 30, 2021 and 2020, respectively, and $0.8 million and $0.5 million for the six months ended June 30, 2021 and 2020, respectively.
(2) Variable lease cost represents differences between lease obligations and actual costs incurred for certain leases that do not have fixed payments related to both lease and non-lease components. Such incremental costs include lease payment increases or decreases driven by market price fluctuations and leased asset maintenance costs.
(3) The Company has subleased a portion of 1 of its office spaces for the remainder of the office lease term.

The Company does not have any leases with an implicit interest rate that can be readily determined. As a result, the Company used the incremental borrowing rate, based on the Credit Facility benchmark rate, adjusted for facility utilization and lease term, to calculate the respective discount rates. Please refer to Note 5 - Long-term Debt for additional information.
The Company has certain lease agreements that provide for the option to extend, purchase, or terminate early, which was evaluated on each lease to arrive at the proper lease term. There were some leases for which the option to extend or purchase was factored into the resulting lease term. There were no leases where early termination was factored into the resulting lease term. The Company's weighted-average remaining lease terms and discount rates for operating leases as of June 30, 2021 are as follows:
Operating Leases
Weighted-average lease term (years)2.9
Weighted-average discount rate3.91%
Supplemental cash flow information related to leases for the three and six months ended June 30, 2021 and 2020 consisted of the following (in thousands):
Three Months Ended June 30,Six Months Ended June 30,
2021202020212020
Cash paid for amounts included in the measurement of lease liabilities:
Operating cash flows from operating leases$3,340 $3,279 $6,490 $6,412 
Operating cash flows from finance leases0 1 1 2 
Financing cash flows from finance leases0 30 21 40 
Right-of-use assets obtained in exchange for new operating lease obligations$4,010 $1,944 $5,499 $7,388 
Right-of-use assets obtained in exchange for new finance lease obligations0 0 0 219 
12
Table of Contents
As of June 30, 2021, future commitments by year for the Company's operating with a lease term of one year or more are presented in the table below. Such commitments are reflected at undiscounted values and are reconciled to the discounted present value recognized on the balance sheet as follows (in thousands):
Operating Leases
Remainder of 2021$7,179 
202211,306 
20237,074 
20242,995 
2025680 
Thereafter1,328 
Total lease payments30,562 
Less: imputed interest(1,706)
Total lease liability$28,856 
NOTE 5- LONG-TERM DEBT
Senior Notes
In conjunction with the HighPoint Merger, Bonanza Creek issued $100$400.0 million aggregate principal amount of 7.5%5.0% Senior Notes due 2026 (the “5.0% Senior Notes”) pursuant to an indenture (the “Indenture”“5.0% Indenture”), dated April 1, 2021, by and among Bonanza Creek, U.S.Civitas Resources, Wells Fargo Bank, National Association, as trustee, (the “Trustee”), and the subsidiary guarantors party thereto. The Bonanza Creek Senior Notes areCompany used the senior unsecured obligationsnet 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 Bonanza Creek5.0% per annum and the subsidiariesis payable semiannually in arrears on April 15 and October 15 of Bonanza Creek that are guarantors of the Bonanza Creek Senior Notes. each year. Payments commenced on April 15, 2022.
The 5.0% Indenture contains restrictive covenants that limit, among other things, restrictthe 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 Bonanza Creek and each of its restrictedthe Company’s subsidiaries to: (i) incur additional indebtedness and issue preferred stock; (ii)to pay dividends or make other distributions in respect of Bonanza Creek common stock; (iii) make other restricted payments and investments; (iv) create liens; (v) restrict distributions or other payments from Bonanza Creek’s restricted subsidiaries; (v) sell assets, including capital stock of restricted subsidiaries; (vi) merge or consolidate with other entities; andto Civitas Resources; (vi) enter into transactions with affiliates.affiliates; and (vii) sell assets or merge with other companies. These restrictive covenants are subject to a number of important qualificationslimitations and limitations.exceptions. The Company was in compliance with all covenants under the 5.0% Indenture as of June 30, 2022, and through the filing of this report. In addition, certain of these restrictive covenants will be suspendedterminated before the Bonanza Creek5.0% Senior Notes mature if at any time no default or event of default exists under the 5.0% Indenture and the Bonanza Creek5.0% Senior Notes receive an investment gradeinvestment-grade rating from at least two2 ratings agencies. The 5.0% Indenture also contains customary events of default.
The Bonanza Creek
15
Table of Contents
At any time prior to October 15, 2023, the Company may redeem the 5.0% Senior Notes, will bein 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 jointly and severally, on a senior unsecured basis by each restricted subsidiary that guarantees a credit facility (as defined inall of Civitas' existing subsidiaries.
7.5% Senior Notes
In conjunction with the Indenture)HighPoint Merger, the Company issued $100.0 million aggregate principal amount of Bonanza Creek.
Immediately after the Effective Time, HighPoint, HighPoint OpCo, and Fifth Pocket Production, LLC, a Colorado limited liability company (collectively, the “HighPoint guarantors”), Bonanza Creek, and the Trustee entered into a first supplemental indenture7.5% Senior Notes due 2026 (the “First Supplemental Indenture”“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 Indenture, pursuant to which such HighPoint guarantors unconditionally guaranteed all of Bonanza Creek’s obligations under the Bonanza Creekredemption date.
The 7.5% Senior Notes and 5.0% Senior Notes are recorded net of unamortized deferred financing costs within the Indenture.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 June 30, 2022 and December 31, 2021 (in thousands):
As of June 30, 2022
Principal AmountUnamortized Deferred Financing CostsNet Amount
5.0% Senior Notes$400,000 $7,492 $392,508 
As of December 31, 2021
Principal AmountUnamortized Deferred Financing CostsNet Amount
7.5% Senior Notes$100,000 $— $100,000 
5.0% Senior Notes$400,000 $8,290 $391,710 
Credit Facility
In December 2018, theThe Company entered intois 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, (thethat mature on November 1, 2025 (with all subsequent amendments as defined below, the “Credit Facility”). The Credit Facility has a maturity date of December 7, 2023. The April 2021 redetermination as part of the Second Amendment (defined below) resulted in a borrowing base of $500.0 million, with elected commitments set at $400.0 million. The most recent redetermination was concluded on July 20, 2021, resulting in a reaffirmation of the borrowing base at $500.0 million and aggregate elected commitments at $400.0 million. The next redetermination is set to occur in November 2021, unless otherwise redetermined through the closing of the XOG and Crestone Peak mergers.
The Credit Facility is guaranteed by all wholly owned subsidiaries of the Company (each, a “Guarantor” and, together with the Company, the “Credit Parties”), and is secured by first priority security interests on substantially all assets of each Credit Party, subject to customary exceptions.


13
Table of Contents
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. The Credit Parties are
16
Table of Contents
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, (i)(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 (“EBITDAX”permitted net leverage ratio”) of 3.00 to 1 and (ii)(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 1.00.
Under the terms of1. The Company was in compliance with all covenants under the Credit Facility as amended inof June 202030, 2022, and through the filing of this report.
On November 1, 2021, the Company, JPMorgan, and the Lender Syndicate entered into an Amended and Restated Credit Agreement (the “First Amendment”“A&R Credit Agreement”), having an aggregate maximum commitment amount of $2.0 billion. The A&R Credit Agreement, among other things, amended the borrowing base adjustment provisions such that, between borrowing base determinations, downward adjustments related to the incurrence of certain permitted indebtedness will only occur if either (A) such indebtedness exceeds $500.0 million and the Company’s pro-forma leverage ratio is less than or equal to 1.50 to 1, or (B) the Company's pro-forma leverage ratio is greater than 1.50 to 1.
Under the A&R 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.
On December 21, 2021, the Company entered into a First Amendment to the A&R Credit Agreement that stipulates that the minimum hedging covenant with respect to projected oil and gas production will not apply if the Company’s leverage ratio is less than 1.00 to 1 as of the applicable quarterly test date, until the next such test date.
On April 20, 2022, and as part of the regularly scheduled, semi-annual borrowing base redetermination, the Company entered into a Second Amendment to the A&R 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. These increases were primarily driven by the increased value of the Company’s estimated proved reserves at December 31, 2021. The next scheduled borrowing base redetermination date is set to occur in October 2022.
In addition, the Second Amendment to the A&R Credit Agreement resulted in the removal and replacement of LIBOR with the Secured Overnight Financing Rate (“SOFR”) as a mechanism to determine interest for borrowings boremade 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) a LIBOR, subject to a 0% LIBOR floorthe Alternate Base Rate (“ABR”, for ABR Revolving Credit Loans) plus athe applicable margin, of 2.00% to 3.00%, based on the utilization of the Credit Facility (the “Eurodollar Rate”) or (ii) the term-specific SOFR plus the applicable margin. ABR is established as a fluctuating interest rate per annum equal to the greatest of (a) the rate of interest publicly announced by JPMorgan Chase Bank, N.A. as its prime rate, (b) the applicable rate of interest published by the Federal Reserve Bank of New York as the federal funds effective rate,(“NYFRB”) plus 0.5%, or (c) the rate of interest published by the Federal Reserve Bank of New York as the overnight bank funding rate, or (d) a LIBOR offered rate for a one-month interest period,term-specific SOFR plus 1.0%, subject to a 0% LIBOR1.50% floor plus athe applicable margin of 1.00% to 2.00%, based on the utilization of the Credit Facility (the “Reference Rate”).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 Eurodollar RateSOFR shall be payable on the last day of the applicable interest period selected by the Company, which shall be one, two, three, or six months, and interest on borrowings that bear interest at the Reference RateABR shall be payable quarterly in arrears. 
On April 1, 2021, in conjunction withThe following table presents the HighPoint Merger, the Company, together with certainoutstanding balance, total amount of its subsidiaries, entered into the Second Amendment (the “Second Amendment”) toletters of credit outstanding, and available borrowing capacity under the Credit Facility (as amended, restated, supplemented or otherwise modified) to, among other things: (i) increase the aggregate maximum commitment amount from $750.0 million to $1.0 billion; (ii) increase the available borrowing base from $260.0 million to $500.0 million; (iii) increase the Eurodollar Rate margin to 3.00% to 4.00%; (iv) increase the Reference Rate margin to 2.00% to 3.00%; (v) increase (A) the LIBOR floor from 0% to .50% and (B) the alternate base rate floor from 0% to 1.50%; (vi) decrease for any fiscal quarter ending on or after April 1, 2021, the maximum permitted net leverage ratio from 3.50 to 3.0; and (viii) amend certain other covenants and provisions.
The Company was in compliance with all covenants as of June 30, 2021, and through the filing date of this report.dates indicated (in thousands):
As of June 30, 2021 and December 31, 2020, the Company had $99.0 million and 0, respectively, outstanding on the Credit Facility. As of the date of this filing, the outstanding balance was $85.0 million. The Company's Credit Facility approximates fair value as the applicable interest rates are floating.
August 3, 2022June 30, 2022December 31, 2021
Revolving credit facility$— $— $— 
Letters of credit12,393 12,393 21,656 
Available borrowing capacity987,607 987,607 778,344 
Total aggregate elected commitments$1,000,000 $1,000,000 $800,000 
In connection with the Second Amendment,amendments to the Credit Facility, the Company capitalized an incremental $3.7a total of approximately $11.9 million in deferred financing costs. Of the total post-amortization net capitalized deferred financing costs,amounts, (i) $2.5$7.0 million and $0.7$7.5 million are presented within the other noncurrent assets line item on the accompanying balance sheets as of June 30, 20212022 and December 31, 2020,2021, respectively, areand (ii) $3.0 million and $2.7 million is presented within other noncurrent assets and (ii) $1.7 million and $0.4 million, as of June 30, 2021 and December 31, 2020, respectively, are presented withinthe prepaid expenses and other line items initem on the accompanying balance sheets.sheets as of June 30, 2022 and December 31, 2021, respectively.
17
Table of Contents
Interest Expense
For the three months ended June 30, 20212022 and 2020,2021, the Company incurred interest expense of $8.1 million and $3.8 million and $1.4 million, respectively,capitalized zero and capitalized $0.6 million, and $0.4 million during the three months ended June 30, 2021 and 2020, respectively.
For the six months ended June 30, 20212022 and 2020,2021, the Company incurred interest expense of $17.2 million and $4.3 million and $2.6 million, respectively,capitalized zero and capitalized $0.6 million, and $1.4 million during the six months ended June 30, 2021 and 2020, respectively.
14
Table of Contents
NOTE6- COMMITMENTS AND CONTINGENCIES
Legal Proceedings 
From time to time, the Company is involved in various commercial and regulatory claims, litigation, and other legal proceedings that arise in the ordinary course of its business. The Company assesses these claims in an effort to determine the degree of probability and range of possible loss for potential accrual in its condensed consolidated financial statements. In accordance with authoritative accounting guidance, an accrual is recorded for a loss contingency when its occurrence is probable and damages can be reasonably estimated based on the most likely anticipated outcome or the minimum amount within a range of possible outcomes. Because legal proceedings are inherently unpredictable and unfavorable resolutions could occur, assessing contingencies is highly subjective and requires judgments about uncertain future events. When evaluating contingencies, the Company may be unable to provide a meaningful estimate due to a number of factors, including the procedural status of the matter in question, the presence of complex or novel legal theories, and/or the ongoing discovery and development of information important to the matters. The Company regularly reviews contingencies to determine the adequacy of its accruals and related disclosures. NaNNo 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.
Upon closing of the HighPoint Merger, the Company assumed all obligations, whether asserted or unasserted, of HighPoint Resources Corporation. As of the filing date of this report, there were no probable, material pending, or overtly threatened legal actions against the Company that were associated with HighPoint of which it was aware, other than the following:
On June 15, 2020, Sterling Energy Investments LLC (“Sterling”) filedBoulder 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 complaint against HighPoint OpCo, a subsidiarycontract 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 HighPoint Resources Corporation, for breach of contract relatedthese leases in the litigation. This litigation has been resolved as to a Gas Purchase Agreement dated effective November 1, 2017. Sterling alleges that HighPoint OpCo breached the contract by failing to use reasonable commercial efforts to deliver to Sterling at Sterling’s receipt points all quantities of gas not otherwise dedicated to other gas purchase agreements. HighPoint Resources OpCo filed a counterclaim against Sterling for breach of Sterling’s obligations under the Gas Purchase Agreement. The possible damages range from 0 to $5.5 million. At this time,substantive issues, and the Company is unableawaiting final dismissal of the matter by the trial court.
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 determine whethervigorously defend against all claims alleged by Boulder County. If an action is brought by Boulder County, an adverse outcome in any loss is probable and accordingly has not recognized any liability associated with this matter.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 $300,000. HighPoint Resources Corporation$0.3 million. The Company has received Notices of Alleged Violations (“NOAV”) from the Colorado Oil and Gas Conservation Commission (“COGCC”)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 June 30, 2022 and December 31, 2021, the Company has recognizedaccrued approximately $1.8$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. As part of the HighPoint Merger, the Company is now party to 2 firm transportation contracts to provide capacity on natural gas pipeline systems. The contracts require the Company to pay minimum volume transportation charges through July 2021 regardless of the amount of pipeline capacity utilized by the Company. These deficiency payments totaling $4.3 million for the three months ended June 30, 2021 are included in unused commitments expense in the statements of operations. The Company will not utilize the firm capacity on the natural gas pipelines.
Additionally, the Company is party to 1 firm pipeline transportation contract to provide capacitya guaranteed outlet for production on an oil pipeline system. The contract requires the Company to pay minimum volume transportation charges on 8,500 gross barrels per day through April 2022 and 12,500 barrels (“Bbl”) per day thereafter through April 2025, regardless of the amount of pipeline capacity utilized by the Company. The aggregate financial commitment fee over the remaining term was $52.1$41.4 million as of June 30, 2021.2022. The Company expects to utilize most, if not all, of the firm capacity on the oil pipeline system.
18
Table of Contents
Minimum Volume Agreements.Agreement - Oil. The Company is party to a purchase agreement to deliver fixed and determinable quantities of crude oil to NGL Crude. The NGL Crude agreement includes defined volume commitments over a term ending in 2023.oil. Under the terms of the NGL Crude agreement, the Company is required to make periodic deficiency payments for any shortfalls in delivering minimum gross volume commitments, which are set in six-month periods. Thethe minimum gross volume commitment will increase approximately 3% each year for the remainder of the contract, to16,000 Bbls per day over a maximum of approximately 16,000 gross barrels per day.term ending in 2023. The aggregate financial commitment fee over the remaining term was $37.3is $20.0 million as of June 30,
15
Table of Contents
2021. 2022. Upon notifying NGL Crudethe purchaser at least twelve months prior to the expiration date of the NGL Crude agreement, the Company may elect to extend the term of the NGL Crude agreement for up to three additional years. Since the commencement of the NGL Crude agreement and through the remainder of the term of the agreement, theThe 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 $160.2 million as of June 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 $73.8 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 2 different plants over terms that end in August 2025 and July 2026. The Company’s share of these commitments requires an incremental 51.5 and 20.6 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 June 30, 2022. The Company has not, and does not, expect to incur any deficiency payments.
The Company is also party to 1 minimum volume commitment for the delivery of natural gas volumes to a midstream entity for gathering and processing and minimum volume commitments to purchase fresh water from water suppliers. These commitmentsadditional 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 $4.2$11.7 million as of June 30, 2021.2022.
The minimum annual payments under the these agreements for the next five years as of June 30, 20212022 are presented below (in thousands):
Firm Transportation
Minimum Volume(1)
Firm Transportation
Minimum Volume(1)
Remainder of 2021$6,505 $13,170 
202213,064 24,322 
Remainder of 2022Remainder of 2022$7,360 $30,785 
2023202314,600 4,052 202314,600 34,533 
2024202414,640 0 202414,640 25,818 
202520254,800 0 20254,800 22,610 
2026 and thereafter0 0 
20262026— 20,987 
2027 and thereafter2027 and thereafter— 57,200 
TotalTotal$53,609 $41,544 Total$41,400 $191,933 
_______________________________________________________
(1)The above calculation is based on the minimum volume commitment schedule (as defined in the relevant agreements)agreement) and applicable differential fees.
There have been noOther 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 material changes fromthings, 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 commitments disclosedCompany were to fail to complete the wells by the applicable deadline, it would be in breach of the notesagreement and the third-party midstream provider could attempt to assert damages against Civitas and its affiliates. As of the Company's consolidated financial statements included in our 2020 Form 10-K. date of filing, the Company cannot reasonably estimate how much, if any, damages will be paid.
Refer to Note 413 - Leases, for lease commitments.
19
Table of Contents
NOTE 7 - STOCK-BASED COMPENSATION
Long Term Incentive Plans
In April 2017, the Company adopted athe 2017 Long Term Incentive Plan (“2017 LTIP”), as established by the Board, which allowsprovides for the issuance of restricted stock units, (“RSUs”), performance stock units, (“PSUs”), and stock options, and reserved 2,467,430 shares of common stock. Additionally, inIn June 2021, the Company adopted the 2021 Long Term Incentive Plan (“2021 LTIP”), as established by the Board, which reserved an incremental 700,000 shares of common stock in addition 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, and 2021 LTIP, shall beand Extraction Equity Plan are collectively referred to herein as the “LTIP”. See below for further discussion
In November 2021, the Company adopted a non-employee director compensation program (the “Director Compensation Program”), which provides that non-employee directors will receive grants of deferred stock units (“DSUs”). In connection with the adoption of the Director Compensation Program, the Company adopted a First Amendment to the 2021 LTIP that, among other things, allows the Company to determine whether dividend rights granted pursuant to the LTIP should be reinvested, paid currently or paid in accordance with the terms of an associated award.
The Company records compensation expense associated with the issuance of awards granted under the LTIP.LTIP based on the fair value of the awards as of the date of grant within general and administrative expense. The following table outlines the compensation expense recorded by type of award (in thousands):
Three Months Ended June 30,Six Months Ended June 30,
2022202120222021
Restricted and deferred stock units$3,917 $1,746 $9,182 $3,067 
Performance stock units2,218 449 5,043 740 
Total stock-based compensation$6,135 $2,195 $14,225 $3,807 
The Company recordedAs of June 30, 2022, unrecognized compensation expense related to the awards granted under the LTIP as follows (in thousands):
Three Months Ended June 30,Six Months Ended June 30,
2021202020212020
Restricted stock units$1,746 $1,284 $3,067 $2,585 
Performance stock units449 195 740 2 
Stock options0 (5)— 126 
Total stock-based compensation$2,195 $1,474 $3,807 $2,713 
As of June 30, 2021, unrecognized compensation expense will be amortized through the relevant periods as follows (in thousands):
Unrecognized Compensation ExpenseFinal Year of Recognition
Restricted stock units$10,411 2023
Performance stock units5,639 2023
$16,050 
16
Table of Contents
Unrecognized Compensation ExpenseFinal Year of Recognition
Restricted and deferred stock units$23,595 2025
Performance stock units18,951 2024
Total unrecognized stock-based compensation$42,546 
Restricted Stock Units (“RSUs”) and Deferred Stock Units
The LTIP allows for the issuance ofCompany typically grants RSUs to members of the Board of Directors (the “Board”)officers, directors, and employees and DSUs to directors as part of the Company at the discretion of the Board. its LTIP.Each RSU and DSU represents a right to receive 1 share of the Company's common stock to be released from restriction upon completionsettlement of the award at the end of the specified vesting period. The awards typically
RSUs generally vest and settle either over a (i) one-year vesting period, with the entire grant vesting and settling on the anniversary date or (ii) three-year vesting period, with one-third of the total grant vesting and settling on each anniversary date. DSUs generally vest in one-third incrementsquarterly installments over three years. The RSUs are valued ata one-year period following the grant date share pricedate.DSUs are settled in shares of the Company's common stock upon the director’s separation of service from the Board. The Company records compensation expense associated with the issuance of RSUs and are recognized as general and administrative expenseDSUs on a straight-line basis over the vesting period ofbased on the award.
During the six months ended June 30, 2021, the Company granted 175,549 RSUs with a fair value of $6.0 million. the awards as of the date of grant within general and administrative expense. The fair value of RSUs and DSUs is equal to the closing price of the Company’s common stock on the date of the grant.
20
Table of Contents
A summary of the status and activity of non-vested restricted stock unitsRSUs and DSUs for the six months ended June 30, 20212022 is presented below:
Restricted Stock UnitsWeighted-Average Grant-Date Fair Value RSUs and DSUsWeighted-Average Grant-Date Fair Value
Non-vested, beginning of yearNon-vested, beginning of year550,056 $20.30 Non-vested, beginning of year815,062 $42.18 
GrantedGranted175,549 34.21 Granted492,002 50.24 
VestedVested(261,648)20.97 Vested(574,865)42.80 
ForfeitedForfeited(17,926)17.55 Forfeited(30,399)41.15 
Non-vested, end of quarter446,031 $25.49 
Non-vested, end of yearNon-vested, end of year701,800 $47.36 
Cash flows resulting from excess tax benefits areThe fair value of the RSUs and DSUs granted under the LTIP during the six months ended June 30, 2022 was $24.7 million.
Performance Stock Units (“PSUs”)
The Company grants PSUs to be classifiedofficers as part of cash flows from operating activities. Excess tax benefits are realized tax benefits from tax deductions for vested restricted stock in excess of the deferred tax asset attributable to stock compensation costs for such restricted stock. The Company recorded no excess tax benefits for the periods presented.
Performance Stock Units
The LTIP allows for the issuance of PSUs to employees at the sole discretion of the Board.its LTIP. The number of shares of the Company'sCompany’s common stock that may be issued to settle PSUs ranges from 0zero to 2 times the number of PSUs awarded. Thegranted and is determined based on performance achievement against certain criteria over a three-year performance period. PSUs generally vest in their entirety atand settle on the endthird anniversary of the three-year performance period.date of the grant.
Performance achievement is determined based on 1 to 2 criteria. The first criterion is based on either, or a comparisoncombination of, the Company'sCompany’s absolute and relative total shareholder return (“TSR”) forover 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 forover the same performance period. The absolute TSR for the Company and each of the peer companies is determined by dividing (A) (i) the volume-weighted average share price for the last 30 trading days of the performance period, minus (ii) the volume-weighted average share price for the 30 trading days preceding the beginning of the performance period, plus (iii) dividends paid by (B) the volume-weighted average share price for the 30 trading days preceding the beginning of the performance period. The second criterion, whenif 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:
202220212020
TSR100 %100 %67 %
ROCE— %— %33 %
202120202019
TSR100 %67 %50 %
ROCE0 %33 %50 %
Compensation expense associated withAs the 2020 PSUs is recognized as general and administrative expense over the performance period. Because these awards depend on a combination of performance-based and market-based settlement criteria,criterion, compensation expense may be adjusted in future periods as the number of units expected to vest increases or decreases based on the Company'sCompany’s expected ROCE performance. As of June 30, 2021,
Of the Company does not expect any of the ROCE portion of the PSUs granted in 2019 to vest and has accordingly adjusted the related compensation expense.
17
Table of Contents
Thegrant-date fair value, of the PSUs was measured at the grant date. The portion of the PSUs tied to the TSR performance required a stochastic process method using a Brownian Motion simulation. A stochastic process is a mathematically defined equation that can create a series of outcomes over time. These outcomes are not deterministic in nature, which means that by iterating the equations multiple times, different results will be obtained for those iterations. In the case of the Company's TSRs,PSUs tied to TSR performance, the Company could not predict with certainty the path its stock price or the stock prices of its peers would take over the performance period. By using a stochastic simulation, the Company created multiple prospective stock pathways, statistically analyzed these simulations, and ultimately made inferences regarding the most likely path the stock price would take. As such, because future stock prices are stochastic, or probabilistic with some direction in nature, the stochastic method, specifically the Brownian Motion Model, was deemed an appropriate method by which to determine the fair value of the portion of the PSUs tied to the TSR.TSR performance. Significant assumptions used in this simulation include the Company'sCompany’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'sCompany’s peers.
21
During the six months ended June 30, 2021, the Company granted 64,258 PSUs with a fair valueTable of $4.4 million. The PSUs granted in 2018 expired as of December 31, 2020, with zero distribution of shares to the recipients, as neither the TSR nor the ROCE performance criteria were met. Contents
A summary of the status and activity of performance stock unitsnon-vested PSUs for the six months ended June 30, 20212022 is presented below:
Performance Stock Units(1)
Weighted-Average Grant-Date Fair Value
PSUs (1)
Weighted-Average Grant-Date Fair Value
Non-vested, beginning of yearNon-vested, beginning of year185,588 $22.63 Non-vested, beginning of year319,367 $57.58 
GrantedGranted64,258 68.99 Granted199,317 64.23 
VestedVested0 0 Vested(91,523)32.49 
Forfeited0 0 
Non-vested, end of quarter249,846 $34.56 
ExpiredExpired(41,955)22.77 
Non-vested, end of yearNon-vested, end of year385,206 $70.77 
___________________________
(1)The number of awards assumes that the associated performance condition is met at the target amount.amount (multiplier of 1). The final number of shares of the Company'sCompany’s common stock issued may vary depending on the performance multiplier, which ranges from 0zero to 2, depending on the level of satisfaction of the performance condition.
The fair value of the PSUs granted under the LTIP during the six months ended June 30, 2022 was $12.8 million.
The PSUs tied to TSR performance granted in 2019 vested as of December 31, 2021 and were released during the three months ended March 31, 2022 with a 200% distribution of shares to the recipients. The PSUs tied to ROCE performance granted in 2019 expired, with zero distribution of shares to the recipients.
Stock Options
The LTIP allows for the issuance of stock options to the Company's employees at the sole discretion of the Board. Options expire ten years from the grant date unless otherwise determined by the Board. Compensation expense on the stock options is recognized as general and administrative expense over the vesting period of the award.
There were 0Stock options are valued using a Black-Scholes Model where expected volatility is based on an average historical volatility of a peer group selected by management over a period consistent with the expected life assumption on the grant date, the risk-free rate of return is based on the U.S. Treasury constant maturity yield on the grant date with a remaining term equal to the expected term of the awards, and the Company’s expected life of stock options granted duringoption awards is derived from the six months ended June 30, 2021. midpoint of the average vesting time and contractual term of the awards.
A summary of the status and activity of non-vested stock options for the six months ended June 30, 20212022 is presented below:
Stock OptionsWeighted-Average Exercise PriceWeighted-Average Remaining Contractual Term (in years)Aggregate Intrinsic Value (in thousands) Stock OptionsWeighted-
Average
Exercise Price		Weighted-Average Remaining Contractual Term (in years)Aggregate Intrinsic Value (in thousands)
Outstanding, beginning of yearOutstanding, beginning of year72,368 $34.36 Outstanding, beginning of year25,549 $34.36 
Granted0 0 
ExercisedExercised(11,952)34.36 Exercised(6,036)34.36 
ForfeitedForfeited(399)34.36 Forfeited(111)34.36 
Outstanding, end of quarter60,017 $34.36 5.5$763 
Number of options outstanding and exercisable60,017 $34.36 5.5$763 
Outstanding, end of yearOutstanding, end of year19,402 $34.36 4.5$348 
Options outstanding and exercisableOptions outstanding and exercisable19,402 $34.36 4.5$348 
The aggregate intrinsic value of options exercised during the six months ended June 30, 20212022 was $0.1 million.
1822
Table of Contents
NOTE8 - FAIR VALUE MEASUREMENTS
The Company follows authoritative accounting guidance for measuring the fair value measurement authoritative guidance, which defines fair value, establishes a framework for using fair value to measureof assets and liabilities and expands disclosures about fair value measurements. The authoritative accountingin its financial statements. This guidance defines fair value as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date. The statementFurther, this guidance establishes a hierarchy for inputs used in measuring fair value that maximizes the use of observable inputs and minimizes the use of unobservable inputs by requiring that the most observable inputs be used when available.
The fair value hierarchy is broken down into three levels based on the reliability of the inputs as follows:
Level 1: Quoted prices are available in active markets for identical assets or liabilities 
Level 2: Quoted prices in active markets for similar assets and liabilities, quoted prices for identical or similar instruments in markets that are not active, and model-derived valuations whose inputs are observable or whose significant value drivers are observable
Level 3: Significant inputs to the valuation model are unobservable
Financial and non-financial assets and liabilities are to be classified based on the lowest level of input that is significant to the fair value measurement. The Company’s assessment of the significance of a particular input to the fair value measurement requires judgment and may affect the valuation of the fair value of assets and liabilities and their placement within the fair value hierarchy levels.hierarchy.
Derivatives
FairThe Company uses Level 2 inputs to measure the fair value of all derivative instruments areoil, gas, and NGL commodity price derivatives. The fair value of the Company's commodity price derivatives is estimated withusing industry-standard models that considercontemplate various assumptions,inputs including, quotedbut not limited to, the contractual price of the underlying position, current market prices, forward prices for commodities,commodity price curves, volatility factors, time value of money, volatility factors, and current marketthe credit risk of both the Company and contractual pricesits counterparties. We validate our fair value estimate by corroborating the original source of inputs, monitoring changes in valuation methods and assumptions, and reviewing counterparty mark-to-market statements and other supporting documentation. Refer to Note 9 - Derivatives for more information regarding the underlying instruments, as well as other relevant economic measures. All valuations were compared against counterparty statements to verify the reasonableness of the estimate. The Company’s commodity swaps, collars, and puts were validated by observable transactions for the same or similar commodity options using the NYMEX futures index and were designated as Level 2 within the valuation hierarchy. derivative instruments.
The following tables present the Company'sCompany’s financial assets and liabilities that were accounted for at fair value on a recurring basis as of June 30, 2022 and December 31, 2021 and their classification within the fair value hierarchy (in thousands):
 As of June 30, 2021
 Level 1Level 2Level 3
Derivative assets$0 $0 $0 
Derivative liabilities$0 $92,151 $0 
As of June 30, 2022
Level 1Level 2Level 3
Derivative assets$— $— $— 
Derivative liabilities$— $321,825 $— 
 As of December 31, 2020
 Level 1Level 2Level 3
Derivative assets$0 $7,482 $0 
Derivative liabilities$0 $7,732 $0 
As of December 31, 2021
Level 1Level 2Level 3
Derivative assets$— $3,393 $— 
Derivative liabilities$— $239,763 $— 
19Long-Term Debt
Table of Contents
The 5.0% Senior Notes
The Bonanza Creek $100.0 million Senior Notes, issued on April 1, 2021, are recorded at carrying value. There were no debt issuance costs, discounts or premiums associated withcost, net of any unamortized deferred financing costs. As of June 30, 2022, the Bonanza Creek Senior Notes. The estimated fair value of the 7.5% Bonanza Creek5.0% Senior Notes was $100.7 million as of June 30, 2021. The$358.4 million. This fair value of the Bonanza Creek Senior Notes is based on quoted market prices, and as such, is designated as Level 1 within the valuationfair 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.
Proved Oil
23
Table of Contents
Warrants
As discussed in Note 2 - Acquisitions and GasDivestitures, 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 six months ended June 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 oil and gas property costsunproved properties are evaluated for impairmentvalued based on a nonrecurring basisdiscounted cash flow approach utilizing Level 3 inputs, including, amongst other things, reserve quantities and reduced toclassification, pace of drilling plans, future commodity prices, future development and lease operating costs, and discount rates using a market-based weighted average cost of capital determined at the time of the acquisition. When estimating the fair value when there is an indicationof unproved properties, additional risk-weighting adjustments are applied to probable and possible reserves. Net derivative liabilities assumed are valued based on Level 2 inputs similar to the Company's other commodity price derivatives.
Whenever events or circumstances indicate that the carrying costs exceed the sumvalue of the undiscounted cash flows of the underlying oil and gas reserves. Depending on the availability of data,proved properties may not be recoverable, the Company uses Level 3 inputs and either the income valuation technique, which converts future amounts to a single present value amount to measure theand record impairment at fair value of proved properties through an application of risk-adjusted discount rates and price forecasts selected by the Company’s management, or the market valuation approach. The calculation of the risk-adjusted discount rate is a significant management estimate based on the best information available. Management believes that the risk-adjusted discount rate is representative of current market conditions and reflects the following factors: estimates of future cash payments, expectations of possible variations in the amount and/or timing of cash flows, the risk premium, and nonperformance risk. The price forecast is based on the Company's internal budgeting model derived from the NYMEX strip pricing, adjusted for management estimates and basis differentials. Future operating costs are also adjusted as deemed appropriate for these estimates. Proved properties classified as held for sale are valued using a market approach, based on an estimated selling price, as evidenced by the most current bid prices received from third parties. If a relevant estimated selling price is not available, the Company utilizes the income valuation technique discussed above.value. There were 0no proved oil and gas property impairments during the three and six months ended June 30, 20212022 and 2020.2021.
Impairments of Unproved Properties
NOTE9- ASSET RETIREMENT OBLIGATIONS
The Company recognizes anUnproved properties are routinely evaluated for continued capitalization or impairment. On a quarterly basis, management assesses undeveloped leasehold costs for impairment by considering, among other things, remaining lease terms, future drilling plans and capital availability to execute such plans, commodity price outlooks, recent operational results, reservoir performance and geology, and estimated liability for future costs to abandon its oil and gas properties. The fairacreage value of the asset retirement obligation is recorded as a liability when incurred, which is typically at the time the asset is acquired or placed in service. There is a corresponding increase to the carrying value of the asset, which is included in the proved properties line item in the accompanying balance sheets. The Company depletes the amount added to proved properties and recognizes expense in connection with accretion of the discounted liability over the remaining estimated economic lives of the properties.
The Company’s estimated asset retirement obligation liability is based on historical experience in abandoning wells, estimated economic lives, estimated costs to abandonprices received for similar, recent acreage transactions by the wells,Company or other market participants. During the three months ended June 30, 2022 and regulatory requirements. The liability is discounted using2021, the credit-adjusted risk-free rate estimated atCompany incurred abandonment and impairment of unproved properties expense of zero and $2.2 million, respectively. During the timesix months ended June 30, 2022 and 2021, the liability is incurred.
A roll-forwardCompany incurred abandonment and impairment of the Company's asset retirement obligation is as follows (in thousands):
Amount
Beginning balance as of December 31, 2020$28,699 
Liabilities settled(2,902)
Additions24,633 
Accretion expense764 
Ending balance as of June 30, 2021$51,194 
unproved properties expense of $18.0 million and $2.2 million, respectively.
NOTE 109 - DERIVATIVES
The Company periodically enters into commodity derivative contracts to mitigate a portion of its exposure to potentially adverse market changes in commodity prices for its expected future oil, natural gas, and NGL production and the associated impact on cash flows. AllThe Company's commodity derivative contracts consist of swap and collar arrangements as well as roll differential swaps. As of June 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’s derivatives include swaps, collars, and puts for oil and natural gas, and 0ne of theCompany does not designate its commodity derivative instruments qualifycontracts as having hedging relationships.instruments.
In a typical commodity fixed-price swap agreement,arrangement, if the agreed upon published third-party index price (“index price”) is lower than the swap strikefixed contract price at the time of settlement, the Company receives the difference between the index price and the agreed upon swap strikefixed contract price. If the index price is higher than the swap strikefixed contact price at the Company paystime of settlement, the difference. A swaption allows the counterparty, on a specific date, to extend an existing fixed-price swap for a certain period of time or to increase the notional volumes of an existing fixed-price swap.
A basis swap arrangement guarantees a price differential from a specified delivery point to an agreed upon reference point. The Company receives the difference between the price differential and the stated terms, if the price differential is greater
20
Table of Contents
than the stated terms. The Company pays the difference between the index price differential and the stated terms, if the stated terms are greater than the price differential.
Certain NYMEX calendar month average (“CMA”) settlement contracts contain a “CMA Roll Adjustment,” the calculation of which includes futures prices for contracts deliverable in, at the time, two forward months. The physical trade month average is compared to the prompt month futures contracts and weighted to reflect the amount of time during the delivery month that the forward months traded as the prompt month. The weighted adjustment values are added to the basic calendar month average to arrive at the Roll Adjusted settlement price for the month. “Oil roll swaps” fix the value of the roll adjustment. If the futures curve becomes more backwardated after entering the oil roll swap, we will pay the difference between the CMA Roll Adjustment and the oil roll swap price. If the futures curve becomes more in contango, we will receive the difference between the CMA Roll Adjustment and the oil roll swapfixed contract price.
A cashlesstypical collar arrangement effectively establishes a floor and ceiling price on future oilcontracted volumes through the use of a short call and gas production.a long put (“two-way collar”). When the settlementindex price is above the ceiling price at the time of settlement, the Company pays the difference between the settlementindex price and the ceiling price. When the settlementindex price is below the floor price at the time of settlement, the Company receives the difference between the settlementindex price and floor price. InWhen the event that the settlementindex price is between the floor price and ceiling and the floor,price, no payment or receipt occurs.
A minority of our collar arrangements combine a two-way collar with a short put givesthat holds an exercise price below the owner the right to sell the underlying commodity at a setfloor price over the term of the contract. If(“three-way collar”). In these arrangements, when the index settlement price is higher thanbelow the put fixedfloor price at the put will expire worthless. If thetime of settlement, price is lower than the put fixed price, the Company will exercise the put and receivereceives the difference between the settlementindex price and the putfloor 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.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.
21
Table of Contents
As of June 30, 2021,2022, the Company had entered into the following commodity price derivative contracts:
Contract Period
Q3 2022Q4 2022Q1 2023Q2 2023Q3 - Q4 20232024
Oil Derivatives (volumes in Bbl/day and prices in $/Bbls)
Swaps
NYMEX WTI Volumes10,5079,538457448364479
Weighted-Average Contract Price$47.00 $46.84 $45.42 $46.29 $46.77 $53.96 
Two-Way Collars
NYMEX WTI Volumes8,2967,3931,054———
Weighted-Average Ceiling Price$68.43 $69.63 $72.70 $— $— $— 
Weighted-Average Floor Price$40.66 $40.97 $40.00 $— $— $— 
Three-Way Collars
NYMEX WTI Volumes2,2411,7381,7211,4361,237143
Weighted-Average Ceiling Price$58.03 $57.78 $58.75 $57.69 $57.01 $56.25 
Weighted-Average Floor Price$48.59 $48.42 $49.31 $48.10 $48.45 $45.00 
Weighted-Average Sold Put Price$38.59 $38.42 $39.25 $37.70 $38.18 $35.00 
Roll Differential Swaps (1)
NYMEX WTI Volumes2,0002,000————
Weighted-Average Contract Price$0.22 $0.22 $— $— $— $— 
Natural Gas Derivatives (volumes in MMBtu/day and prices in $/million British thermal units (“MMBtu”))
Swaps
NYMEX HH Volumes54,95254,78344,64143,91143,86822,309
Weighted-Average Contract Price$2.76 $2.76 $2.51 $2.51 $2.51 $2.57 
CIG Volumes10,00010,000————
Weighted-Average Contract Price$2.13 $2.13 $— $— $— $— 
Two-Way Collars
NYMEX HH Volumes81,01879,1489,5581,5631,8221,033
Weighted-Average Ceiling Price$3.68 $3.69 $3.23 $2.78 $2.96 $3.05 
Weighted-Average Floor Price$2.59 $2.60 $2.03 $2.21 $2.36 $2.38 
Three-Way Collars
NYMEX HH Volumes136127899505—303
Weighted-Average Ceiling Price$2.74 $2.74 $3.19 $3.33 $— $3.49 
Weighted-Average Floor Price$2.50 $2.50 $2.50 $2.50 $— $2.50 
Weighted-Average Sold Put Price$2.00 $2.00 $2.00 $2.00 $— $2.00 
NGL Derivatives (volumes in Bbls/day and prices in $/Bbl)
Swaps
OPIS Basket Volumes4,0004,000————
Weighted-Average Contract Price$20.22 $20.22 $— $— $— $— 
______________________________
Crude Oil
(NYMEX WTI)		Natural Gas
(NYMEX Henry Hub)		Natural Gas
(CIG Basis)		Natural Gas
(CIG)
Bbls/dayWeighted Avg. Price per BblMMBtu/dayWeighted Avg. Price per MMBtuMMBtu/dayWeighted Avg. Basis Differential to CIG Price per MMBtuMMBtu/dayWeighted Avg. Price per MMBtu
3Q21
Cashless Collar3,000 $30.00/$50.6220,000 $2.25/$2.52— —20,000 $2.15/$2.75
Swap9,500 $54.41— —20,000 $0.4320,000 $2.12
Oil Roll Swap(1)
4,500 $0.16— —— —— —
4Q21
Cashless Collar4,000 $30.63/$50.3420,000 $2.25/$2.52— —20,000 $2.15/$2.75
Swap8,000 $54.49— —20,000 $0.4313,370 $2.13
Oil Roll Swap(1)
4,500 $0.16— —— —— —
1Q22
Cashless Collar6,500 $35.10/$59.44— —— —20,000 $2.15/$2.75
Swap1,000 $50.15— —— —10,000 $2.13
Oil Roll Swap(1)
2,000 $0.22— —— —— —
Swaptions4,000 $55.06— —— —— —
2Q22
Cashless Collar5,000 $36.64/$63.52— —— —20,000 $2.15/$2.75
Swap1,000 $50.15— —— —10,000 $2.13
Oil Roll Swap(1)
2,000 $0.22— —— —— —
Swaptions4,000 $55.06— —— —— —
3Q22
Cashless Collar3,500 $38.76/$66.84— —— —— —
Swap1,000 $50.15— —— —10,000 $2.13
Oil Roll Swap(1)
2,000 $0.22— —— —— —
Swaptions2,000 $55.13— —— —— —
4Q22
Cashless Collar3,000 $39.39/$68.86— —— —— —
Swap1,000 $50.15— —— —10,000 $2.13
Oil Roll Swap(1)
2,000 $0.22— —— —— —
Swaptions2,000 $55.13— —— —— —

(1) The weighted averageweighted-average differential represents the amount of reduction to NYMEX WTI prices for the notional volumes covered by the swap contracts.
22
Table of Contents
As of the filing date of this report, the Company had entered into the following commodity derivative contracts:
Crude Oil
(NYMEX WTI)		Natural Gas
(NYMEX Henry Hub)		Natural Gas
(CIG Basis)		Natural Gas
(CIG)
Bbls/dayWeighted Avg. Price per BblMMBtu/dayWeighted Avg. Price per MMBtuMMBtu/dayWeighted Avg. Basis Differential to CIG Price per MMBtuMMBtu/dayWeighted Avg. Price per MMBtu
3Q21
Cashless Collar3,000 $30.00/$50.6220,000 $2.25/$2.52— —20,000 $2.15/$2.75
Swap9,500 $54.41— —20,000 $0.4320,000 $2.12
Oil Roll Swaps(1)
4,500 $0.16— —— —— —
4Q21
Cashless Collar10,500 $48.81/$67.6320,000 $2.25/$2.52— —20,000 $2.15/$2.75
Swap8,000 $54.49— —20,000 $0.4313,370 $2.13
Oil Roll Swaps(1)
4,500 $0.16— —— —— —
1Q22
Cashless Collar6,500 $35.10/$59.44— —— —20,000 $2.15/$2.75
Swap1,000 $50.15— —— —10,000 $2.13
Oil Roll Swaps(1)
2,000 $0.22— —— —— —
Swaptions4,000 $55.06— —— —— —
2Q22
Cashless Collar5,000 $36.64/$63.52— —— —20,000 $2.15/$2.75
Swap1,000 $50.15— —— —10,000 $2.13
Oil Roll Swaps(1)
2,000 $0.22— —— —— —
Swaptions4,000 $55.06— —— —— —
3Q22
Cashless Collar4,200 $40.64/$67.7420,000 $2.80/$4.20— —— —
Swap1,000 $50.15— —— —10,000 $2.13
Oil Roll Swaps(1)
2,000 $0.22— —— —— —
Swaptions2,000 $55.13— —— —— —
4Q22
Cashless Collar3,700 $41.40/$69.5020,000 $2.80/$4.20— —— —
Swap1,000 $50.15— —— —10,000 $2.13
Oil Roll Swaps(1)
2,000 $0.22— —— —— —
Swaptions2,000 $55.13— —— —— —

(1) The weighted average differential represents the amount of reduction to NYMEX WTI prices for the notional volumes covered by the swap contracts.
23
Table of Contents
Derivative Assets and Liabilities Fair Value
The Company’s commodity price derivatives are measured at fair value and are included in the accompanying balance sheets as derivative assets and liabilities. The following table contains a summary of all the Company’s derivative positions reported on the accompanying balance sheets as well as a reconciliation between the gross assets and liabilities and the potential effects of master netting arrangements on the fair value of the dates indicated in the table belowCompany’s commodity derivative contracts as of June 30, 2022 and December 31, 2021 (in thousands):
 June 30, 2021December 31, 2020
Derivative Assets: 
Commodity contracts – current$0 $7,482 
Commodity contracts – noncurrent0 0 
Derivative Liabilities:  
Commodity contracts – current(80,866)(6,402)
Commodity contracts – noncurrent(11,285)(1,330)
Total derivative assets (liabilities), net$(92,151)$(250)
June 30, 2022December 31, 2021
Derivative Assets: 
Commodity contracts - current$— $3,393 
Commodity contracts - noncurrent— — 
Total derivative assets— 3,393 
Amounts not offset in the accompanying balance sheets— (3,393)
Total derivative assets, net$— $— 
Derivative Liabilities:  
Commodity contracts - current$(278,600)$(219,804)
Commodity contracts - long-term(43,225)(19,959)
Total derivative liabilities(321,825)(239,763)
Amounts not offset in the accompanying balance sheets— 3,393 
Total derivative liabilities, net$(321,825)$(236,370)
The following table summarizes the components of the derivative gain (loss)loss presented on the accompanying statements of operations for the periods below (in thousands):
Three Months Ended June 30,Six months ended June 30, Three Months Ended June 30,Six Months Ended June 30,
20212020202120202022202120222021
Derivative cash settlement gain (loss): 
Derivative cash settlement loss:Derivative cash settlement loss:
Oil contractsOil contracts$(18,794)$22,485 $(21,616)$32,923 Oil contracts$(114,778)$(18,794)$(239,940)$(21,616)
Gas contractsGas contracts(1,405)128 (2,374)944 Gas contracts(54,091)(1,405)(82,875)(2,374)
Total derivative cash settlement gain (loss)(1)
(20,199)22,613 (23,990)33,867 
NGL contractsNGL contracts(12,762)— (25,394)— 
Total derivative cash settlement lossTotal derivative cash settlement loss(181,631)(20,199)(348,209)(23,990)
Change in fair value gain (loss)Change in fair value gain (loss)(53,771)(47,759)(73,399)41,406 Change in fair value gain (loss)108,981 (53,771)(19,934)(73,399)
Total derivative gain (loss)(1)
$(73,970)$(25,146)$(97,389)$75,273 
Total derivative lossTotal derivative loss$(72,650)$(73,970)$(368,143)$(97,389)

(1)
Total derivative gain (loss)
NOTE 10 - ASSET RETIREMENT OBLIGATIONS
The Company recognizes an estimated liability for future costs associated with the abandonment of its oil and total derivative cash settlement gain (loss)gas properties, including facilities requiring decommissioning. A liability for the six months ended June 30, 2021fair value of an asset retirement obligation and 2020corresponding increase to the carrying value of the related long-lived asset are reportedrecorded at the time a well is drilled or acquired, or a facility is constructed. The increase in carrying value is included in the derivative (gain) loss line item and derivative cash settlement gain (loss)proved properties line item in the accompanying statementsbalance sheets. The Company depletes the amount added to proved properties and recognizes expense in connection with the accretion of cash flows, withinthe discounted liability over the remaining estimated economic lives of the respective long-lived assets. Cash paid to settle asset retirement obligations is included in the cash flows from operating activities. activities section of the accompanying statements of cash flows.
The Company’s estimated asset retirement obligation liability is based on historical experience plugging and abandoning wells, estimated economic lives, estimated plugging and abandonment cost, and regulatory requirements. The liability is discounted using the credit-adjusted risk-free rate estimated at the time the liability is incurred or revised.
24
Table of Contents

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 incurred2,072 
Accretion expense8,102 
Liabilities settled(8,385)
Balance as of June 30, 2022$227,104 
Current portion24,000 
Long-term portion$203,104 
NOTE 11- EARNINGS PER SHARE
Earnings per basic and diluted share are calculated under the treasury stock method. Basic net income (loss) per common share is calculated by dividing net income (loss) by the basic weighted-average common shares outstanding for the respective period. Diluted net income (loss) per common share is calculated by dividing net income (loss) by the diluted weighted-average common shares outstanding, which includes the effect of potentially dilutive securities. Potentially dilutive securities 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, one1 share of the Company's common stock. The number of potentially dilutive shares related to unvested RSUs and DSUs is based on the number of shares, if any, that would be issuable at the end of the respective reporting period, assuming that date was the end of the vesting period. The Company issues PSUs, which represent the right to receive, upon settlement of the PSUs, a number of shares of the Company's common stock that ranges from 0zero to 2 times the number of PSUs granted on the award date. The number of potentially dilutive shares related to PSUs is based on the number of shares, if any, that would be issuable at the end of the respective reporting period, assuming that date was the end of the performance period applicable to such PSUs. The Company has also issued stock options and warrants, which both represent the right to purchase the Company's common stock at a specified exercise price. The number of potentially dilutive shares related to the stock options and warrants is based on the number of shares, if any, that would be exercisable at the end of the respective reporting period, assuming thatthe 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.
24
TableThe following table sets forth the calculations of Contents
The Company uses the treasury stock method to calculate earningsbasic and diluted net income (loss) per common share as shown in the following table (in thousands, except per share amounts):
Three Months Ended June 30,Six Months Ended June 30,Three Months Ended June 30,Six Months Ended June 30,
20212020202120202022202120222021
Net income (loss)Net income (loss)$(25,319)$(38,902)$(25,438)$39,649 Net income (loss)$468,821 $(25,319)$560,460 $(25,438)
Basic net income (loss) per common shareBasic net income (loss) per common share$(0.83)$(1.87)$(0.99)$1.91 Basic net income (loss) per common share$5.52 $(0.83)$6.60 $(0.99)
Diluted net income (loss) per common shareDiluted net income (loss) per common share$(0.83)$(1.87)$(0.99)$1.91 Diluted net income (loss) per common share$5.48 $(0.83)$6.56 $(0.99)
Weighted-average shares outstanding - basicWeighted-average shares outstanding - basic30,655 20,776 25,774 20,713 Weighted-average shares outstanding - basic84,993 30,655 84,917 25,774 
Add: dilutive effect of contingent stock awardsAdd: dilutive effect of contingent stock awards0 0 0 46 Add: dilutive effect of contingent stock awards561 — 536 — 
Weighted-average shares outstanding - dilutedWeighted-average shares outstanding - diluted30,655 20,776 25,774 20,759 Weighted-average shares outstanding - diluted85,554 30,655 85,453 25,774 
There were 747,67859,161 and 715,639747,678 shares that were anti-dilutive for the three months ended June 30, 20212022 and 2020, respectively,2021, respectively. There were 30,822 and 777,564 and 407,996shares that were anti-dilutive for the six months ended June 30, 20212022 and 2020. The Company was in a net loss position for the three months ended June 30, 2021, and 2020 as well as the six months ended June 30, 2021, which made all potentially dilutive shares anti-dilutive. respectively.
The exercise price of the Company's stock warrants werewas in excess of the Company's stock price during the three and six months ended June 30, 2020;2022; therefore, they were excluded from the earnings per share calculation. The Company's warrants expired on April 30, 2020.
25
Table of Contents
NOTE 12 - INCOME TAXES
Deferred tax assets and liabilities are measured by applying the provisions of enacted tax laws to determine the amount of taxes payable or refundable currently or in future years related to cumulative temporary differences between the tax basis of assets and liabilities and amounts reported in the Company'saccompanying 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 MergerExtraction MergerCrestone 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. TheAs a result of the HighPoint Merger, the Company has cumulative book income for the prior three years and is forecasting future book income, which resulted in the fullrecorded a valuation allowance being removedof $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 June 30, 2022 was $107.9 million, and the net deferred tax asset as of December 31, 2020.2021 was $22.3 million. Additionally, income tax payable under current liabilities as of June 30, 2022 was $50.4 million. The Company will continue to monitor facts and circumstances in the reassessment of the likelihood that the deferred tax assets will be realized.
Federal income tax expense differs from the amount that would be provided by applying the statutory United States federal income tax rate of 21% to income before income taxes primarily due to the effect of state income taxes, changes in valuation allowances,equity-based compensation, and other permanent differences.differences including bargain purchase gain. During the three and six months ended June 30, 2022 and 2021, the Company recorded income tax expense of $152.5 million and income tax benefit of $10.4 million, compared to 0 income tax benefit duringrespectively. During the three and six months ended June 30, 2020.2022 and 2021, the Company recorded income tax expense of $175.8 million and income tax benefit of $10.4 million, respectively.
AsThe Company had no unrecognized tax benefits as of June 30, 20212022 and December 31, 2020, the Company had 0 unrecognized tax benefits.2021. The Company's management does not believe that there are any new items or changes in facts or judgments that would impact the Company's tax position taken thus far in 2021.


2022.
2526
Table of Contents
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):
June 30, 2022December 31, 2021
Operating Leases
Field equipment(1)
$22,608 $29,312 
Corporate leases8,024 9,484 
Vehicles855 1,089 
Total right-of-use asset$31,487 $39,885 
Field equipment(1)
$22,608 $29,312 
Corporate leases8,565 9,870 
Vehicles855 1,089 
Total lease liability$32,028 $40,271 
____________________________
(1) Includes compressors, certain natural gas processing equipment, and other field equipment.

The Company incurred gross short-term lease costs of $11.3 million and $0.2 million for the three months ended June 30, 2022 and 2021, respectively. The Company incurred gross short-term lease costs of $20.4 million and $0.2 million for the six months ended June 30, 2022 and 2021, respectively. A portion of these costs may have been or will be billed to other working interest owners, and the Company's net share of these costs, once paid, are capitalized to property and equipment or recognized as expense.
Future commitments by year for the Company's leases with a lease term of one year or more as of June 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$10,210 
202313,523 
20245,414 
20251,742 
20261,207 
Thereafter1,587 
Total lease payments33,683 
Less: imputed interest(1,655)
Total lease liability$32,028 

NOTE 14 - SUBSEQUENT EVENTS
On July 5, 2022, the Company entered into and closed on Purchase and Sale Agreements to acquire non-operating interests in certain of the Company's operated wells for cash consideration of $81.6 million, subject to customary purchase price adjustments.
27
Table of Contents
Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations.

The following discussion and analysis of our financial condition and results of operations should be read in conjunction with “Management’s Discussion and Analysis of Financial Condition and Results of Operations” contained in our Annual Report on2021 Form 10-K for the year ended December 31, 2020,, as well as the unaudited condensed consolidated financial statements and notes thereto included in this Quarterly Report on Form 10-Q.
Executive Summary
We are an independent Denver-based exploration and production company focused on the acquisition, development, and extractionproduction of oil and associated liquids-rich natural gas in the United States. Our oil and liquids-weighted assets and operations are concentratedRocky Mountain region, primarily in the rural portions of the Wattenberg Field in Colorado. Our development and extraction activities are primarily directed at the horizontal development of the Niobrara and Codell formationsDJ Basin of Colorado. We believe our acreage in the Denver-Julesburg (“DJ”) Basin.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 through dividends and debt reduction by responsibly developing our oil and natural gas resources. We seek to balance production and company growth with maintaining a conservative balance sheet. Key aspects of our strategy include well-balanced asset mergers and acquisitions, multi-well pad development across our leasehold, enhanced completions through continuous design evaluation, utilization of scaled infrastructure, continuous safety improvement, strict adherence to health and safety regulations, environmental stewardship, disciplined approach to acquisitions and environmental stewardship.divestitures and capital allocation, and prudent risk management.
Financial and Operating Results
Our financial and operational results include:
•Crude oil equivalent sales volumes increased 70%314% for the three months ended June 30, 20212022 when compared to the same period in 2020during 2021 primarily due to the HighPoint Merger;Extraction and Crestone Peak mergers as well as the Bison Acquisition;
•Lease operatingGeneral and administrative expense increasedper barrel of oil equivalent (“Boe”) decreased by 15% per Boe41% for the three months ended June 30, 20212022 when compared to the same period in 2020;during 2021 due to the synergies achieved through the Extraction and Crestone Peak mergers as well as the Bison Acquisition;
•General and administrativeLease operating expense per Boe decreased by 15% per Boe11% for the three months ended June 30, 20212022 when compared to the same period in 2020;
•Borrowings under our Credit Facility were reduced by $56.0 million to $99.0 million during the three months ended June 30, 2021 from the $155.0 million borrowed at the closing of the HighPoint Merger to pay down the HighPoint credit facility;2021;
•Total liquidity of $325.4 millionwas $1.4 billion at June 30, 2021,2022, consisting of cash on hand plus funds available under our Credit Facility.Facility, after giving effect to an aggregate of $12.4 million of undrawn letters of credit. Please refer to Liquidity and Capital Resources below for additional discussion;
•Cash dividenddividends of $10.8$116.2 million, or $0.35$1.3625 per share, declared and paid during the three months ended June 30, 2021;2022;
•Cash flows provided by operating activities for the six months ended June 30, 20212022 were $79.6 million,$1.3 billion, as compared to cash flows provided by operating activities of $68.2$79.6 million during the six months ended June 30, 2020.2021. Please refer to Liquidity and Capital Resources below for additional discussion; and
•Capital expenditures, inclusive of accruals, of $73.6were $473.1 million during the six months ended June 30, 2021.2022, of which $39.8 million represents land and midstream capital expenditures.

26
Table of Contents
Rocky Mountain InfrastructureMidstream Assets
The Company's midstream assets provide reliable gathering, treating, and storage for the Company’s operated production facilities, maintained under its Rocky Mountain Infrastructure, LLC (“RMI”) subsidiary, provide many operational benefitswhile reducing facility site footprints, leading to the Companymore cost-efficient operations and provide cost economies of a centralized system. The RMI facilities reduce gathering system pressures at the wellhead, thereby improving hydrocarbon recovery.reduced emissions and surface disturbance per Boe produced. Additionally, with eleven interconnects to four different natural gas processors, RMIthis infrastructure helps ensure that the Company's production is not constrained by any single midstream service provider. Furthermore, in 2019, the Company installed a new oil gathering line to Riverside Terminal (on the Grand Mesa Pipeline), which resulted in a corresponding $1.25 to $1.50 per barrel reduction to our oil differentials for barrels transported on such gathering line. Additionally, the Company commenced construction of an additional oil interconnect in late June 2021, thus providing additional outlets to provide flow assurance and minimize differentials. The total value of reduced oil differentials during the six months ended June 30, 2021 and 2020 was approximately $2.1 million and $2.9 million, respectively. Finally, the RMI system reduces facility site footprints, leading to more cost-efficient operations and reduced emissions and surface disturbance. 
The net book value of the Company's RMImidstream assets was $196.1$303.9 million as of June 30, 2021.2022.
28
Table of Contents
Current Events and Outlook
The worldwide outbreak ofOil and natural gas prices continue to be impacted by the efforts to contain COVID-19, the uncertainty regarding the impactcontinued pace of COVID-19,economic recovery, and various governmental actions takenchanges to mitigate the impactOPEC+ production levels. In addition, Russia’s invasion of COVID-19, resulted in an unprecedented decline in demand for oil and natural gas. At the same time, the decision by Saudi Arabia in March 2020Ukraine has led to drastically reduceregional instability, Although Russian export prices and increase oil production further increased the excess supplyvolumes of oil and gas have been only modestly impacted so far, uncertainty regarding potential future impacts of sanctions and buyer aversion to Russian hydrocarbons presents significant risk to future supply and demand balances. The foregoing destabilizing factors have caused dramatic fluctuations in global financial markets and uncertainty about world-wide oil supply and demand, which in turn has increased the volatility of oil, natural gas, throughout 2020. However,and NGL prices. WTI oil prices have recovered to pre-pandemic levels, averaging approximately $101 per Bbl during the first quarterhalf of 2021, expectations surrounding2022. With the current shortage of other sources of energy, and the economic growth associated with what appears to be a global emergence from the pandemic, the demand for and price of oil has increased. Although this demand outlook is expected to underpin oil prices, in light of uncertainty associated with recovering oil demand, future monetary policy, and natural gas stimulated a risegovernmental policies aimed at transitions toward lower carbon energy, we cannot predict any future volatility in oil and natural gas prices.
The COVID-19 outbreak and its development into a pandemic in March 2020 also required that we take precautionary measures intended to help minimize the risk to our business, employees, customers, suppliers, and the communities in which we operate. Our operational employees are currently still able to work on site. However, we have taken various precautionary measures with respect to our operational employees such as requiring them to verify they have not experienced any symptoms consistent with COVID-19, or been in close contact with someone showing such symptoms, before reporting to the work site, quarantining any operational employees who have shown signslevels of COVID-19 (regardless of whether such employee has been confirmed to be infected), and imposing social distancing requirements on work sites, all in accordance with the guidelines released by the Centers for Disease Control and Prevention. We have not yet experienced any material operational disruptions (including disruptions from our suppliers and service providers) as a result of a COVID-19 outbreak.
The Company's stand-alone first quarter 2021 capital budget of $35 million to $40 million and combined second through fourth quarter 2021 capital budget (reflecting the closing of the HighPoint Merger on April 1, 2021) of $115 million to $130 million includes completing 45 gross (39.9 net) drilled, uncompleted wells, and picking up a drilling rig in the fourth quarter of 2021, with completions of those newly drilled wells to begin in 2022. Actual capital expenditures could vary significantly based on, among other things, market conditions, commodity prices drilling and completion costs, and well results.or demand for crude oil.
On April 1, 2021, we completed the previously announced acquisition of HighPoint. Whileacquired HighPoint, and on November 1, 2021, we have already achieved significant synergies across several areas of themerged with Extraction and Crestone Peak. Additionally, on March 1, 2022, we acquired Bison. The Company there is an expected delay in realizing certain synergies and benefits due to the time and effort required to renegotiate and wait out certain contracts and integrate the formerly stand-alone companies. Consequently, the financial and operating results of the combined companies for the three and six months ended June 30, 2021 reflect a slightly higher cost metric that we anticipate will decline during the latter half of 2021. Additionally, while the significant curtailment of the respective drilling and completion programs during 2020, in response to the drop in commodity prices, resulted in an overall decline in combined companies' sales volumes period over period, we expect sales volumes will recover considerably through 2021 completion activity as well as the return of a drilling rig in the fourth quarter of 2021.
The Companybelieves it has successfully integrated the operations, production, and accounting databases derived from the HighPoint Merger.each of these mergers and acquisitions.
The Company's original 2022 capital budget included drilling and completion activities of $825 million to $950 million and $70 million to $90 million in land, midstream, and other capital activity that will support our acreage positions and overall infrastructure. We believehave since updated 2022 guidance to refine our drilling and completion capital budget to $890 million to $940 million which contemplates running an average of 3 operated rigs and 3 operated crews that the Company has the appropriate level of skillswill drill approximately 190 and personnelcomplete approximately 160 gross operated wells. Additionally, our land, midstream, and other capital activity budget was updated to successfully integrate the XOG and Crestone Peak mergers. The go-forward Company will incorporate the best practices and processes from each organization.$80 million to $100 million.

2729
Table of Contents
Results of Operations
The following table summarizes our product revenues, sales volumes, and average sales prices for the periods indicated:
Three Months Ended June 30,Three Months Ended June 30,
20212020ChangePercent Change 20222021ChangePercent Change
Revenues (in thousands):Revenues (in thousands):  Revenues (in thousands): 
Crude oil sales(1)
Crude oil sales(1)
$115,923 $28,559 $87,364 306 %
Crude oil sales(1)
$778,218 $115,923 $662,295 571 %
Natural gas sales(2)
Natural gas sales(2)
14,778 3,931 10,847 276 %
Natural gas sales(2)
205,298 14,778 190,520 1,289 %
Natural gas liquids sales24,777 2,545 22,232 874 %
NGL salesNGL sales167,266 24,777 142,489 575 %
Product revenueProduct revenue$155,478 $35,035 $120,443 344 %Product revenue$1,150,782 $155,478 $995,304 640 %
Sales Volumes:Sales Volumes:Sales Volumes:
Crude oil (MBbls)Crude oil (MBbls)1,905.2 1,274.1 631.1 50 %Crude oil (MBbls)7,308.4 1,905.2 5,403.2 284 %
Natural gas (MMcf)Natural gas (MMcf)6,405.6 3,298.7 3,106.9 94 %Natural gas (MMcf)28,903.5 6,405.6 22,497.9 351 %
Natural gas liquids (MBbls)878.6 438.1 440.5 101 %
NGL (MBbls)NGL (MBbls)3,819.6 878.6 2,941.0 335 %
Crude oil equivalent (MBoe)(3)
Crude oil equivalent (MBoe)(3)
3,851.4 2,262.0 1,589.4 70 %
Crude oil equivalent (MBoe)(3)
15,945.3 3,851.4 12,093.9 314 %
Average Sales Prices (before derivatives):  
Average Sales Prices (before derivatives)(4):
Average Sales Prices (before derivatives)(4):
 
Crude oil (per Bbl)Crude oil (per Bbl)$60.85 $22.42 $38.43 171 %Crude oil (per Bbl)$106.48 $60.85 $45.63 75 %
Natural gas (per Mcf)Natural gas (per Mcf)$2.31 $1.19 $1.12 94 %Natural gas (per Mcf)$7.10 $2.31 $4.79 207 %
Natural gas liquids (per Bbl)$28.20 $5.81 $22.39 385 %
NGL (per Bbl)NGL (per Bbl)$43.79 $28.20 $15.59 55 %
Crude oil equivalent (per Boe)(3)
Crude oil equivalent (per Boe)(3)
$40.37 $15.49 $24.88 161 %
Crude oil equivalent (per Boe)(3)
$72.17 $40.37 $31.80 79 %
Average Sales Prices (after derivatives)(4):
Average Sales Prices (after derivatives)(4):
Average Sales Prices (after derivatives)(4):
Crude oil (per Bbl)Crude oil (per Bbl)$50.98 $40.06 $10.92 27 %Crude oil (per Bbl)$90.78 $50.98 $39.80 78 %
Natural gas (per Mcf)Natural gas (per Mcf)$2.09 $1.23 $0.86 70 %Natural gas (per Mcf)$5.23 $2.09 $3.14 150 %
Natural gas liquids (per Bbl)$28.20 $5.81 $22.39 385 %
NGL (per Bbl)NGL (per Bbl)$40.45 $28.20 $12.25 43 %
Crude oil equivalent (per Boe)(3)
Crude oil equivalent (per Boe)(3)
$35.12 $25.49 $9.63 38 %
Crude oil equivalent (per Boe)(3)
$60.78 $35.12 $25.66 73 %
_____________________________
(1)Crude oil sales excludes $0.2$0.1 million and $0.4$0.2 million of oil transportation revenues from third parties, which do not have associated sales volumes, for the three months ended June 30, 20212022 and 2020,2021, respectively.
(2)Natural gas sales excludes $0.4$0.5 million and $0.8$0.4 million of gas gathering revenues from third parties, which do not have associated sales volumes, for the three months ended June 30, 20212022 and 2020,2021, respectively.
(3)Determined using the ratio of 6 Mcfthousand cubic feet (“Mcf”) of natural gas to 1 Bbl of crude oil.
(4)Derivatives economically hedge the price we receive for crude oil, natural gas, and NGL. For the three months ended June 30, 2022, the derivative cash settlement loss for oil, natural gas.gas, and NGLs was $114.8 million, $54.1 million, $12.8 million, respectively. For the three months ended June 30, 2021, the derivative cash settlement loss for oil and natural gas contracts was $18.8 million and $1.4 million, respectively. For the three months ended June 30, 2020, the derivative cash settlement gain for oil and natural gas contracts was $22.5 million and $0.1 million, respectively. Please refer to Note 109 - Derivatives ofunder Part I, Item 1 of this report for additional disclosures.
Product revenues increased by 344%640% to $1.2 billion for the three months ended June 30, 2022 compared to $155.5 million for the three months ended June 30, 2021 compared2021. The increase was largely due to $35.0 million for the three months ended June 30, 2020. The drivers of thea 314% increase in revenue are the 161%,sales volumes and a $31.80, or $24.88 per Boe,79%, increase in oil equivalent pricing, andexcluding the 70% increase in sales volumes.impact of derivatives. The increase in sales volumes is primarily due to the HighPoint MergerExtraction and Crestone Peak mergers that closed on AprilNovember 1, 2021.2021, and the Bison Acquisition that closed on March 1, 2022. Additionally, we turned 30126 gross wells to sales during the twelve-month period ending June 30, 2021.2022.
2830
Table of Contents
The following table summarizes our operating expenses for the periods indicated:indicated (in thousands, except per Boe amounts):
Three Months Ended June 30,Three Months Ended June 30,
20212020ChangePercent Change 20222021ChangePercent Change
Expenses (in thousands):  
Operating Expenses:Operating Expenses: 
Lease operating expenseLease operating expense$11,358 $5,795 $5,563 96 %Lease operating expense$41,877 $11,358 $30,519 269 %
Midstream operating expenseMidstream operating expense4,246 3,354 892 27 %Midstream operating expense7,469 4,246 3,223 76 %
Gathering, transportation, and processingGathering, transportation, and processing13,721 3,711 10,010 270 %Gathering, transportation, and processing79,519 13,721 65,798 480 %
Severance and ad valorem taxesSeverance and ad valorem taxes9,813 3,478 6,335 182 %Severance and ad valorem taxes85,870 9,813 76,057 775 %
ExplorationExploration3,547 112 3,435 3,067 %Exploration1,553 3,547 (1,994)(56)%
Depreciation, depletion, and amortizationDepreciation, depletion, and amortization35,006 22,283 12,723 57 %Depreciation, depletion, and amortization204,519 35,006 169,513 484 %
Abandonment and impairment of unproved propertiesAbandonment and impairment of unproved properties2,215 309 1,906 617 %Abandonment and impairment of unproved properties— 2,215 (2,215)(100)%
Unused commitmentsUnused commitments4,328 — 4,328 100 %Unused commitments1,731 4,328 (2,597)(60)%
Bad debt expenseBad debt expense4 — 4 100 %
Merger transaction costsMerger transaction costs18,246 21 18,225 86,786 %Merger transaction costs1,418 18,246 (16,828)(92)%
General and administrative expenseGeneral and administrative expense12,144 8,385 3,759 45 %General and administrative expense29,666 12,144 17,522 144 %
Operating Expenses$114,624 $47,448 $67,176 142 %
Operating expensesOperating expenses$453,626 $114,624 $339,002 296 %
Selected Costs ($ per Boe):Selected Costs ($ per Boe):  Selected Costs ($ per Boe): 
Lease operating expenseLease operating expense$2.95 $2.56 $0.39 15 %Lease operating expense$2.63 $2.95 $(0.32)(11)%
Midstream operating expenseMidstream operating expense1.10 1.48 (0.38)(26)%Midstream operating expense0.47 1.10 (0.63)(57)%
Gathering, transportation, and processingGathering, transportation, and processing3.56 1.64 1.92 117 %Gathering, transportation, and processing4.99 3.56 1.43 40 %
Severance and ad valorem taxesSeverance and ad valorem taxes2.55 1.54 1.01 66 %Severance and ad valorem taxes5.39 2.55 2.84 111 %
ExplorationExploration0.92 0.05 0.87 1,740 %Exploration0.10 0.92 (0.82)(89)%
Depreciation, depletion, and amortizationDepreciation, depletion, and amortization9.09 9.85 (0.76)(8)%Depreciation, depletion, and amortization12.83 9.09 3.74 41 %
Abandonment and impairment of unproved propertiesAbandonment and impairment of unproved properties0.58 0.14 0.44 314 %Abandonment and impairment of unproved properties— 0.58 (0.58)(100)%
Unused commitmentsUnused commitments1.12 — 1.12 100 %Unused commitments0.11 1.12 (1.01)(90)%
Bad debt expenseBad debt expense— — — — %
Merger transaction costsMerger transaction costs4.74 0.01 4.73 100 %Merger transaction costs0.09 4.74 (4.65)(98)%
General and administrative expenseGeneral and administrative expense3.15 3.71 (0.56)(15)%General and administrative expense1.86 3.15 (1.29)(41)%
Operating Expenses$29.76 $20.98 $8.78 42 %
Operating expensesOperating expenses$28.47 $29.76 $(1.29)(4)%
Lease operating expense. Our lease operating expense increased by $5.6$30.5 million, or 96%269%, to $41.9 million for the three months ended June 30, 2022 from $11.4 million for the three months ended June 30, 2021, from $5.8 million for the three months ended June 30, 2020, and 15%decreased 11% on an equivalent basis per Boe. Lease operating expense increased on an aggregate basis as a result of the HighPoint Merger, where there areExtraction and Crestone Peak mergers as well as the Bison Acquisition. Lease operating expense per Boe decreased as a result of the synergies to still be realized withinachieved through the vehicle and compression fleet rentals, contract automation, and water disposal costs.aforementioned mergers.
Midstream operating expense. Our midstream operating expense increased $3.2 million, or 76%, to $7.5 million for the three months ended June 30, 2022 from $4.2 million for the three months ended June 30, 2021, compared to $3.4 million for the three months ended June 30, 2020, and decreased 26%57% on aan equivalent basis per BoeBoe. Midstream operating expense increased on an aggregate basis during the comparable periods. The overall increase is due to the acquisition of certain midstream assets as part ofthrough the HighPointCrestone Peak Merger. Additionally,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.
31
Table of Contents
Gathering, transportation, and processing. Gathering, transportation, and processing expense increased by $10.0$65.8 million, or 480%, to $79.5 million for the three months ended June 30, 2022 from $13.7 million for the three months ended June 30, 2021, from $3.7 million for the three months ended June 30, 2020. Natural gas and NGLs salesincreased 40% on an equivalent basis per Boe. Sales volumes have a direct correlation to gathering, transportation, and processing expense and natural gas and NGLs sales volumes increased 97%314% during the comparable periods. Additionally, ourwe are party to a number of value-based percentage of proceeds sales contract is now our largestcontracts, 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 contract postvolumes outlet and thereby incurred increased gathering, transportation, and processing expense during the HighPoint Merger.three months ended June 30, 2022 relative to oil differentials (that would otherwise be recorded as a direct reduction of revenue) in order to receive a net improvement on in margins.
Severance and ad valorem taxes.  Our severance and ad valorem taxes increased $76.1 million, or 775%, to $85.9 million for the three months ended June 30, 2022 from $9.8 million for the three months ended June 30, 2021, from $3.5 million for the three months ended June 30, 2020.and increased 111% on an equivalent basis per Boe. Severance and ad valorem taxes primarily correlate to revenues, and revenueswhich increased by 344% during the three months ended June 30, 2021 compared to the three months ended June 30, 2020. The HighPoint Merger has decreased the Company's overall severance and ad valorem tax rates, due to HighPoint having a substantial amount of wells in lower taxing districts.
29
Table of Contents
Exploration.  Our exploration expense increased to $3.5 million640% for the three months ended June 30, 2021, from $0.1 million for2022 when compared to the three months ended June 30, 2020 primarily duesame 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 a one-time purchase of seismicthe aggregate increase in severance and core data.ad valorem taxes.
Depreciation, depletion, and amortization.  Our depreciation, depletion, and amortization expense increased 57%$169.5 million, or 484%, to $204.5 million for the three months ended June 30, 2022 from $35.0 million for the three months ended June 30, 2021, from $22.3 million for the three months ended June 30, 2020, and decreased 8%increased 41% on aan equivalent basis per Boe basis during the comparable periods.Boe. The increase in depreciation, depletion, and amortization expense duringis the comparable periods is due toresult of (i) a $629.2 million$4.5 billion increase in the depletable property base primarily due to the HighPoint Merger. The decrease onExtraction and Crestone Peak mergers as well as the Bison Acquisition and (ii) a per Boe basis is due to a decrease314% increase in production between the depletion rate.comparable periods.
Abandonment and impairment of unproved properties.During the three months ended June 30, 2022 and 2021, we incurred zero and 2020, the Company incurred $2.2 million and $0.3 million, respectively, in abandonment and impairment of unproved properties primarily due to, during the three months ended June 30, 2021, 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 three months ended June 30, 20212022, we incurred $1.7 million in unused commitments primarily due to certain deficiency payments incurred under a minimum volume crude oil and 2020,a minimum volume water commitment. During the three months ended June 30, 2021, we incurred $4.3 million and zero, respectively, in unused commitments. As partcommitments primarily due to the assumption of the HighPoint Merger, we assumed 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, require the pipeline to provide transportation capacity and requirewhich expired on July 31, 2021, required us to pay transportation charges regardless of the amount of pipeline capacity utilized. The agreements expire July 31, 2021.
Merger transaction costs. During the three months ended June 30, 2022, we incurred $1.4 million in legal, advisor, and other costs associated with the Extraction and Crestone Peak mergers as well as the Bison Acquisition. During the three months ended June 30, 2021, we incurred $18.2 million in legal, advisor, and other costs associated with the HighPoint Merger.
General and administrative expense. Our merger transaction costsgeneral and administrative expense increased by $18.2$17.6 million, or 144%, to $29.7 million for the three months ended June 30, 2022 from $12.1 million for the three months ended June 30, 2021, compared to the three months ended June 30, 2020 largely due to the HighPoint Merger and, to a lesser degree, the anticipated XOG and Crestone mergers.
General and administrative. Our general and administrative expense for the three months ended June 30, 2021 increased to $12.1 million compared to $8.4 million for three months ended June 30, 2020, and decreased by 15%41% on aan equivalent basis per Boe basis.Boe. The primary drivers of the aggregate increase relate to an increase in salaries, benefits, and stock compensation expense due toassociated with the HighPoint Merger. Additionally, certain one-time nonrecurring fees were incurred as it relates to the HighPoint Merger as further discussed in Note 3 - Acquisitions & Divestitures of Part I, Item 1 of this report.Extraction and Crestone Peak mergers. General and administrative expense per Boe decreased due to oil equivalent sales volumes being 70%314% higher during the three months ended June 30, 20212022 as compared to the same period in 2020.2021.
Derivative gain (loss).loss.  Our derivative loss for the three months ended June 30, 20212022 was $72.7 million as compared to a loss of $74.0 million for the three months ended June 30, 2021. Our derivative loss is due to settlements and fair market value adjustments caused by market prices being higher than our contracted hedge prices. Our derivative loss of $25.1 million for the three months ended June 30, 2020 is due to fair market value adjustments caused by market prices recovering from prior period levels, partially offset by settlement gains caused by market prices being lower than our contracted hedge prices. Please refer to Note 109 - Derivatives ofunder Part I, Item 1 of this report for additional discussion.
32
Table of Contents
Interest expense. Our interest expense for the three months ended June 30, 2022 and 2021 and 2020 was $3.2$8.1 million and $1.0$3.2 million, respectively. Average debt outstanding for the three months ended June 30, 2022 and 2021 and 2020 was $123.2$443.4 million and $63.7$123.2 million, respectively. The components of interest expense for the periods presented are as follows (in thousands):
Three Months Ended June 30,
20212020
Senior Notes$1,875 $— 
Credit Facility1,160 557 
Commitment fees on available borrowing base under the Credit Facility329 270 
Amortization of deferred financing costs433 557 
Capitalized interest(556)(400)
Total interest expense, net$3,241 $984 

Three Months Ended June 30,
20222021
Senior Notes$5,646 $1,875 
Credit Facility116 1,160 
Commitment fees under the Credit Facility1,179 329 
Letter of credit fees under the Credit Facility73 — 
Amortization of deferred financing costs1,102 433 
Capitalized interest— (556)
Total interest expense$8,116 $3,241 
3033
Table of Contents
The following table summarizes our product revenues, sales volumes, and average sales prices for the periods indicated:
Six Months Ended June 30,
 20212020ChangePercent Change
Revenues (in thousands):  
Crude oil sales(1)
$165,723 $79,148 $86,575 109 %
Natural gas sales(2)
27,064 8,893 18,171 204 %
Natural gas liquids sales35,740 5,786 29,954 518 %
Product revenue$228,527 $93,827 $134,700 144 %
Sales Volumes:
Crude oil (MBbls)2,847.9 2,503.6 344.3 14 %
Natural gas (MMcf)9,619.5 6,861.3 2,758.2 40 %
Natural gas liquids (MBbls)1,276.7 875.0 401.7 46 %
Crude oil equivalent (MBoe)(3)
5,727.9 4,522.1 1,205.8 27 %
Average Sales Prices (before derivatives):  
Crude oil (per Bbl)$58.19 $31.61 $26.58 84 %
Natural gas (per Mcf)$2.81 $1.30 $1.51 116 %
Natural gas liquids (per Bbl)$27.99 $6.61 $21.38 323 %
Crude oil equivalent (per Boe)(3)
$39.90 $20.75 $19.15 92 %
Average Sales Prices (after derivatives)(4):
Crude oil (per Bbl)$50.60 $44.76 $5.84 13 %
Natural gas (per Mcf)$2.57 $1.43 $1.14 80 %
Natural gas liquids (per Bbl)$27.99 $6.61 $21.38 323 %
Crude oil equivalent (per Boe)(3)
$35.71 $28.24 $7.47 26 %
Six Months Ended June 30,
 20222021ChangePercent Change
Revenues (in thousands): 
Crude oil sales(1)
$1,327,184 $165,723 $1,161,461 701 %
Natural gas sales(2)
317,728 27,064 290,664 1,074 %
NGL sales322,413 35,740 286,673 802 %
Product revenue$1,967,325 $228,527 $1,738,798 761 %
Sales Volumes:
Crude oil (MBbls)13,431.9 2,847.9 10,584.0 372 %
Natural gas (MMcf)55,689.9 9,619.5 46,070.4 479 %
NGL (MBbls)7,542.3 1,276.7 6,265.6 491 %
Crude oil equivalent (MBoe)(3)
30,255.9 5,727.9 24,528.0 428 %
Average Sales Prices (before derivatives)(4):
 
Crude oil (per Bbl)$98.81 $58.19 $40.62 70 %
Natural gas (per Mcf)$5.71 $2.81 $2.90 103 %
NGL(per Bbl)$42.75 $27.99 $14.76 53 %
Crude oil equivalent (per Boe)(3)
$65.02 $39.90 $25.12 63 %
Average Sales Prices (after derivatives)(4):
Crude oil (per Bbl)$80.94 $50.60 $30.34 60 %
Natural gas (per Mcf)$4.22 $2.57 $1.65 64 %
NGL (per Bbl)$39.38 $27.99 $11.39 41 %
Crude oil equivalent (per Boe)(3)
$53.51 $35.71 $17.80 50 %
_____________________________
(1)Crude oil sales excludes $0.5$0.6 million and $1.0$0.5 million of oil transportation revenues from third parties, which do not have associated sales volumes, for the six months ended June 30, 20212022 and 2020,2021, respectively.
(2)Natural gas sales excludes $1.2$1.3 million and $1.8$1.2 million of gas gathering revenues from third parties, which do not have associated sales volumes, for the six months ended June 30, 20212022 and 2020,2021, respectively.
(3)Determined using the ratio of 6 Mcf of natural gas to 1 Bbl of crude oil.
(4)Derivatives economically hedge the price we receive for crude oil, natural gas, and NGL. For the six months ended June 30, 2022, the derivative cash settlement loss for oil, natural gas.gas, and NGLs was $239.9 million, $82.9 million, $25.4 million, respectively. For the six months ended June 30, 2021, the derivative cash settlement loss for oil and natural gas contracts was $21.6 million and $2.4 million, respectively. For the six months ended June 30, 2020, the derivative cash settlement gain for oil and natural gas contracts was $32.9 million and $0.9 million, respectively. Please refer to Note 109 - Derivatives ofunder Part I, Item 1 of this report for additional disclosures.
Product revenues increased by 144%761% to $1,967.3 million for the six months ended June 30, 2022 compared to $228.5 million for the six months ended June 30, 2021 compared2021. The increase was largely due to $93.8 million for the six months ended June 30, 2020. The primary drivers of thea 428% increase in revenue are the 92%,sales volumes and a $25.12, or $19.15 per Boe,63%, increase in oil equivalent pricing, andexcluding the 27% increase in sales volumes.impact of derivatives. The increase in sales volumes is due to turning 30the 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 126 gross wells to sales during the twelve-month period ending June 30, 2021 as well as the HighPoint Merger that closed on April 1, 2021.2022.
3134
Table of Contents
The following table summarizes our operating expenses for the periods indicated:indicated (in thousands, except per Boe amounts):
Six Months Ended June 30,Six Months Ended June 30,
20212020ChangePercent Change 20222021ChangePercent Change
Expenses (in thousands):  
Operating Expenses:Operating Expenses: 
Lease operating expenseLease operating expense$17,089 $11,494 $5,595 49 %Lease operating expense$77,896 $17,089 $60,807 356 %
Midstream operating expenseMidstream operating expense8,151 7,368 783 11 %Midstream operating expense13,181 8,151 5,030 62 %
Gathering, transportation, and processingGathering, transportation, and processing18,688 7,192 11,496 160 %Gathering, transportation, and processing129,922 18,688 111,234 595 %
Severance and ad valorem taxesSeverance and ad valorem taxes14,417 8,651 5,766 67 %Severance and ad valorem taxes149,174 14,417 134,757 935 %
ExplorationExploration3,643 485 3,158 651 %Exploration2,081 3,643 (1,562)(43)%
Depreciation, depletion, and amortizationDepreciation, depletion, and amortization53,829 43,867 9,962 23 %Depreciation, depletion, and amortization389,379 53,829 335,550 623 %
Abandonment and impairment of unproved propertiesAbandonment and impairment of unproved properties2,215 30,366 (28,151)(93)%Abandonment and impairment of unproved properties17,975 2,215 15,760 712 %
Unused commitmentsUnused commitments4,328 — 4,328 100 %Unused commitments2,507 4,328 (1,821)(42)%
Bad debt expenseBad debt expense— 576 (576)(100)%Bad debt expense4 — 4 100 %
Merger transaction costsMerger transaction costs21,541 21 21,520 102,476 %Merger transaction costs21,952 21,541 411 2 %
General and administrative expenseGeneral and administrative expense21,395 17,814 3,581 20 %General and administrative expense65,386 21,395 43,991 206 %
Operating Expenses$165,296 $127,834 $37,462 29 %
Operating expensesOperating expenses$869,457 $165,296 $704,161 426 %
Selected Costs ($ per Boe):Selected Costs ($ per Boe):  Selected Costs ($ per Boe): 
Lease operating expenseLease operating expense$2.98 $2.54 $0.44 17 %Lease operating expense$2.57 $2.98 $(0.41)(14)%
Midstream operating expenseMidstream operating expense1.42 1.63 (0.21)(13)%Midstream operating expense0.44 1.42 (0.98)(69)%
Gathering, transportation, and processingGathering, transportation, and processing3.26 1.59 1.67 105 %Gathering, transportation, and processing4.29 3.26 1.03 32 %
Severance and ad valorem taxesSeverance and ad valorem taxes2.52 1.91 0.61 32 %Severance and ad valorem taxes4.93 2.52 2.41 96 %
ExplorationExploration0.64 0.11 0.53 482 %Exploration0.07 0.64 (0.57)(89)%
Depreciation, depletion, and amortizationDepreciation, depletion, and amortization9.40 9.70 (0.30)(3)%Depreciation, depletion, and amortization12.87 9.40 3.47 37 %
Abandonment and impairment of unproved propertiesAbandonment and impairment of unproved properties0.39 6.72 (6.33)(94)%Abandonment and impairment of unproved properties0.59 0.39 0.20 51 %
Unused commitmentsUnused commitments0.76 — 0.76 100 %Unused commitments0.08 0.76 (0.68)(89)%
Bad debt expenseBad debt expense— 0.13 (0.13)(100)%Bad debt expense— — — — %
Merger transaction costsMerger transaction costs3.76 — 3.76 100 %Merger transaction costs0.73 3.76 (3.03)(81)%
General and administrative expenseGeneral and administrative expense3.74 3.94 (0.20)(5)%General and administrative expense2.16 3.74 (1.58)(42)%
Operating Expenses$28.87 $28.27 $0.60 2 %
Operating expensesOperating expenses$28.73 $28.87 $(0.14)— %
Lease operating expense. Our lease operating expense increased 49%$60.8 million, or 356%, to $77.9 million for the six months ended June 30, 2022 from $17.1 million for the six months ended June 30, 2021, and 2020 and increased 17%decreased 14% on an equivalent basis per Boe. Aggregate leaseLease operating expense increased on an aggregate basis as a result of the HighPoint, Merger.Extraction, and Crestone Peak mergers as well as the Bison Acquisition. Lease operating expense increasedper Boe decreased as a result of the HighPoint Merger, where there are synergies to still be realized withinachieved through the vehicle and compression fleet rentals, contract automation, and water disposal costs.aforementioned mergers.
Midstream operating expense. Our midstream operating expense remained relatively consistent atincreased $5.0 million, or 62%, to $13.2 million for the six months ended June 30, 2022 from $8.2 million for the six months ended June 30, 2021, compared to $7.4 million for the six months ended June 30, 2020, and decreased 13%69% on aan equivalent basis per BoeBoe. Midstream operating expense increased on an aggregate basis during the comparable periods. The overall increase is due to the acquisition of certain midstream assets as part ofthrough the HighPoint Merger. Additionally,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.
35
Table of Contents
Gathering, transportation, and processing. Gathering, transportation, and processing expense increased by $11.5$111.2 million, or 160%595%, to $129.9 million for the six months ended June 30, 2022 from $18.7 million for the six months ended June 30, 2021, from $7.2 million for the six months ended June 30, 2020. Generally, natural gas and NGLs salesincreased 32% on an equivalent basis per Boe. Sales volumes have a direct correlation to gathering, transportation, and processing expense. Natural gasexpense and NGLs sales volumes increased 43%428% during the comparable periods. Additionally, ourwe are party to a number of value-based percentage of proceeds sales contract is now our largestcontracts, 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 contract postvolumes outlet and thereby incurred increased gathering, transportation, and processing expense during the HighPoint Merger.
32
Tablesix months ended June 30, 2022 relative to oil differentials (that would otherwise be recorded as a direct reduction of Contentsrevenue) in order to receive a net improvement on in margins.
Severance and ad valorem taxes.  Our severance and ad valorem taxes increased 67%$134.8 million, or 935%, to $149.2 million for the six months ended June 30, 2022 from $14.4 million for the six months ended June 30, 2021, from $8.7 million for the six months ended June 30, 2020.and increased 96% on an equivalent basis per Boe. Severance and ad valorem taxes primarily correlate to revenues, and revenueswhich increased by 144% during the six months ended June 30, 2021 compared to the six months ended June 30, 2020. The HighPoint Merger has decreased the Company's overall severance and ad valorem tax rates due to HighPoint having a substantial amount of wells in lower taxing districts.
Exploration.  Our exploration expense increased to $3.6 million761% for the six months ended June 30, 2021, from $0.5 million for2022 when compared to the six months ended June 30, 2020 primarily duesame 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 a one-time purchase of seismicthe aggregate increase in severance and core data.ad valorem taxes.
Depreciation, depletion, and amortization.  Our depreciation, depletion, and amortization expense increased 23%$335.6 million, or 623%, to $389.4 million for the six months ended June 30, 2022 from $53.8 million for the six months ended June 30, 2021, from $43.9 million for the six months ended June 30, 2020, and decreased 3%increased 37% on aan equivalent basis per Boe basis during the comparable periods.Boe. The increase in depreciation, depletion, and amortization expense duringis the comparable periods is due toresult of (i) a $629.2 million$4.5 billion increase in the depletable property base primarily due to the HighPoint Merger. The decrease onExtraction and Crestone Peak mergers as well as the Bison Acquisition and (ii) a per Boe basis is due to a decrease428% increase in production between the depletion rate.comparable periods.
Abandonment and impairment of unproved properties.During the six months ended June 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 six months ended June 30, 2021, and 2020, the Companywe incurred $2.2 million and $30.4 million, respectively, in abandonment and impairment of unproved properties primarily 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 six months ended June 30, 20212022, we incurred $2.5 million in unused commitments primarily due to certain deficiency payments incurred under a minimum volume crude oil and 2020,a minimum volume water commitment. During the six months ended June 30, 2021, we incurred $4.3 million and zero, respectively, in unused commitments. As partcommitments primarily due to the assumption of the HighPoint Merger, we assumed 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, require the pipeline to provide transportation capacity and requirewhich expired on July 31, 2021, required us to pay transportation charges regardless of the amount of pipeline capacity utilized. The agreements expire July 31, 2021.
Merger transaction costs. Our mergerDuring the six months ended June 30, 2022 and 2021, we incurred $22.0 million and $21.5 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 $1.1 million of severance payments for the six months ended June 30, 2022 and 2021, respectively.
General and administrative expense. Our general and administrative expense increased by $21.5$44.0 million, or 206%, to $65.4 million for the six months ended June 30, 2022 from $21.4 million for the six months ended June 30, 2021, compared to the six months ended June 30, 2020 largely due to the HighPoint Merger and, to a lesser degree, due to the anticipated XOG and Crestone mergers.
General and administrative. Our general and administrative expense for the six months ended June 30, 2021 increased to $21.4 million, from $17.8 million for the six months ended June 30, 2020, and decreased 5%42% on aan equivalent basis per Boe basis.Boe. The primary drivers of the aggregate increase relate to an increase in salaries, benefits, and stock compensation expense due toassociated with the HighPoint, Merger. Additionally, certain one-time nonrecurring fees were incurred as it relates to the HighPoint Merger as further discussed in Note 3 - Acquisitions & Divestitures of Part I, Item 1 of this report.Extraction, and Crestone Peak mergers. General and administrative expense per Boe decreased due to oil equivalent sales volumes being 27%428% higher during the six months ended June 30, 2022 as compared to the same period in the later period as a result of the HighPoint Merger.2021.
Derivative gain (loss).loss.  Our derivative loss for the six months ended June 30, 20212022 was $368.1 million as compared to a loss of $97.4 million for the six months ended June 30, 2021. Our derivative loss is due to settlements and fair market value adjustments caused by market prices being higher than our contracted hedge prices. Our derivative gain of $75.3 million for the six months ended June 30, 2020 is due to settlements and fair market value adjustments caused by market prices being lower than our contracted hedge prices. Please refer to Note 109 - Derivatives ofunder Part I, Item 1 of this report for additional discussion.
36
Table of Contents
Interest expense. Our interest expense for the six months ended June 30, 2022 and 2021 and 2020 was $3.7$17.2 million and $1.2$3.7 million, respectively. Average debt outstanding for the six months ended June 30, 2022 and 2021 and 2020 was $61.9$471.5 million and $74.3$61.9 million, respectively. The components of interest expense for the periods presented are as follows (in thousands):
Six Months Ended June 30,Six Months Ended June 30,
2021202020222021
Senior NotesSenior Notes$1,875 $— Senior Notes$12,521 $1,875 
Credit FacilityCredit Facility1,160 1,367 Credit Facility116 1,160 
Commitment fees on available borrowing base under the Credit Facility655 521 
Commitment fees under the Credit FacilityCommitment fees under the Credit Facility2,161 655 
Letter of credit fees under the Credit FacilityLetter of credit fees under the Credit Facility204 — 
Amortization of deferred financing costsAmortization of deferred financing costs526 680 Amortization of deferred financing costs2,180 526 
Capitalized interestCapitalized interest(556)(1,367)Capitalized interest— (556)
Total interest expense, net$3,660 $1,201 
Total interest expenseTotal interest expense$17,182 $3,660 

33
Table of Contents
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 capitalequity and/or debt markets.capital markets transactions. Our cash flows from operating activities are subject to significant volatility due to changes in commodity prices, as well as variations in our production. The prices for these commodities are driven by a number of factors beyond our control, including global and regional product supply and demand, weather, product distribution, refining and processing capacity, regulatory constraints, and other supply chain dynamics, among other factors. To mitigate some
Although we cannot provide any assurance, we believe cash flows from operating activities and availability under our Credit Facility should be sufficient to meet our cash requirements inclusive of, but not limited to, normal operating needs, debt service obligations, planned capital expenditures and commitments for at least the pricing risk, as of June 30, 2021, we have hedged approximately 12,250 Bbls per daynext twelve months and, based on current expectations, for the remainder of 2021, representing almost 60% of our oil sales volume during the three months ended June 30, 2021.long term.
As of June 30, 2021,2022, our liquidity was $325.4 million,$1.4 billion, consisting of $24.4 million of cash on hand of $439.3 million and $301.0 million$1.0 billion of available borrowing capacity on theour Credit Facility.Facility, after giving effect to an aggregate of $12.4 million of undrawn letters of credit. Please refer to Note 5 - Long-Term Debt under Part I, Item 1 of this report for additional discussion.
Our weighted-average interest rate on borrowings from the Credit Facility was 3.6% for the three months ended June 30, 2021.2022. As of June 30, 20212022 and as of the date of this filing, we had $99.0 million and $85.0 million, respectively,zero outstanding on our Credit Facility.
On April 1, 2021, in conjunction with the HighPoint Merger, the Company, together with certain of its subsidiaries,20, 2022, we entered into the Second Amendment to the A&R Credit Facility.Facility to increase our borrowing base from $1.0 billion to $1.7 billion and the aggregate elected commitment amount from $800.0 million to $1.0 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 35 - Acquisitions and DivestituresLong-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):
Six Months Ended June 30,Six Months Ended June 30,
20212020 20222021
Net cash provided by operating activitiesNet cash provided by operating activities$79,559 $68,229 Net cash provided by operating activities$1,254,768 $79,559 
Net cash used in investing activitiesNet cash used in investing activities(8,029)(52,019)Net cash used in investing activities(733,491)(8,029)
Net cash used in financing activitiesNet cash used in financing activities(71,870)(23,067)Net cash used in financing activities(336,480)(71,870)
Cash, cash equivalents, and restricted cashCash, cash equivalents, and restricted cash24,505 4,238 Cash, cash equivalents, and restricted cash439,353 24,505 
Acquisition of oil and gas propertiesAcquisition of oil and gas properties(549)(549)Acquisition of oil and gas properties(303,602)(549)
Exploration and development of oil and gas propertiesExploration and development of oil and gas properties(57,269)(51,054)Exploration and development of oil and gas properties(467,186)(57,269)
Cash flows provided by operating activities
Our cash flows forFor the six months ended June 30, 2022 and 2021, and 2020 includethe 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.
37
Table of Contents
Cash flows provided by (used in) investing activities
Net cash used in investing activities
Expenditures for developmentthe six months ended June 30, 2022 was primarily driven by $303.6 million of acquisitions of oil and natural gas properties, are the primary usepartially offset by cash acquired of our capital resources. The Company$44.3 million. Additionally, we spent $57.3$467.2 million and $51.1$57.3 million on the exploration and development of oil and gas properties during the six months ended June 30, 2022 and 2021, and 2020, respectively. Partially offsetting these cash outflows for the six months ended June 30, 2021 is the $49.8 million of cash acquired through the HPR Merger.
Cash flows provided byused in financing activities
Net cash used in financing activities for the six months ended June 30, 2022 and 2021 and 2020 was $71.9$336.5 million and $23.1$71.9 million, respectively. The change was primarily due to increased dividends paid of $209.0 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 $12.9 million, partially offset by a $33.0 million increasedecrease in net payments on ourthe Credit Facility between the comparable periods as well as the $10.8 million dividend that was declared and paid in June 2021.of $55.0 million.
34
Table of Contents
Non-GAAP Financial Measures
Adjusted EBITDAX represents earnings before interest, income taxes, depreciation, depletion, and amortization, exploration expense, and other non-cash and non-recurring charges. Adjusted EBITDAX excludes certain items that we believe affect the comparability of operating results and can exclude items that are generally non-recurring in nature or whose timing and/or amount cannot be reasonably estimated. Adjusted EBITDAX is a non-GAAP measure that we present because we believe it provides useful additional information to investors and analysts, as a performance measure, for analysis of our ability to internally generate funds for exploration, development, and acquisitions, and to service debt. We are also subject to financial covenants under our Credit Facility based on adjusted EBITDAX ratios as further describedratios. See Note 5 - Long-Term DebtLiquidity and Capital Resources in Part I, Item I of this document.above 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, income from operations, net cash provided by operating activities, or other profitability or liquidity measures prepared under GAAP. Because adjusted EBITDAX excludes some, but not all items that affect net income (loss) and may vary among companies, the adjusted EBITDAX amounts presented may not be comparable to similar metrics of other companies.

The following table presents a reconciliation of the GAAP financial measure of net income to the non-GAAP financial measure of Adjustedadjusted EBITDAX (in thousands):
Three Months Ended June 30,Six Months Ended June 30,
2021202020212020
Net income (loss)$(25,319)$(38,902)$(25,438)$39,649 
Exploration3,547 112 3,643 485 
Depreciation, depletion, and amortization35,006 22,283 53,829 43,867 
Abandonment and impairment of unproved properties2,215 309 2,215 30,366 
Unused commitments4,328 — 4,328 — 
Stock-based compensation (1)
2,195 1,474 3,807 2,713 
Non-recurring general and administrative expense (1)
1,294 784 1,294 1,197 
Merger transaction costs18,246 21 21,541 21 
Loss on property transactions, net— 1,398 — 1,398 
Interest expense, net3,241 984 3,660 1,201 
Derivative (gain) loss73,970 25,146 97,389 (75,273)
Derivative cash settlements gain (loss)(20,199)22,613 (23,990)33,867 
Income tax benefit(10,392)— (10,436)— 
Adjusted EBITDAX$88,132 $36,222 $131,842 $79,491 
_____________________________
(1) Included as a portion of general and administrative expense in the accompanying statements of operations.
(2) Included as a portion of severance and ad valorem taxes in the accompanying statements of operations.
Three Months Ended June 30,Six Months Ended June 30,
2022202120222021
Net income (loss)$468,821 $(25,319)$560,460 $(25,438)
Exploration1,553 3,547 2,081 3,643 
Depreciation, depletion, and amortization204,519 35,006 389,379 53,829 
Abandonment and impairment of unproved properties— 2,215 17,975 2,215 
Stock-based compensation(1)
6,135 2,195 14,225 3,807 
Non-recurring general and administrative expense(1)
3,449 1,294 6,335 1,294 
Merger transaction costs1,418 18,246 21,952 21,541 
Unused commitments1,731 4,328 2,507 4,328 
Gain on property transactions, net— — (16,797)— 
Interest expense8,116 3,241 17,182 3,660 
Derivative loss72,650 73,970 368,143 97,389 
Derivative cash settlements loss(181,631)(20,199)(348,209)(23,990)
Income tax (benefit) expense152,464 (10,392)175,825 (10,436)
Adjusted EBITDAX$739,225 $88,132 $1,211,058 $131,842 
_______________________________
(1) Included as a portion of general and administrative expense in the accompanying statements of operations.

New Accounting Pronouncements 
Please refer to Note 2 —1 - Summary of Significant Accounting Policies, Basis of Presentationunder Part I, Item 1 of this report and Note 2 - Basis of Presentation in the 2021 Form 10-Kfor any recently issued or adopted accounting standards.
38

Table of Contents
Critical Accounting Policies and Estimates
Information regarding our critical accounting policies and estimates is contained in Part II, Item 7 of our 20202021 Form 10-K.10-K. During the three months ended June 30, 2022, there were no significant changes in the application of critical accounting policies.

Material Commitments
There have been no significant changes from our 20202021 Form 10-K in our obligations and commitments, other than what is disclosed within Note 46 - LeasesCommitments and Contingencies and Note 613 - Commitments and ContingenciesLeases under Part I, Item 1 of this report.

35
Table of Contents
Cautionary Note Regarding Forward-Looking Statements
This Quarterly Report on Form 10-Q contains various statements, including those that express belief, expectation, or intention, as well as those that are not statements of historic fact, that are forward-looking statements within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities and Exchange Act of 1934, as amended (the “Exchange Act”). When used in this Quarterly Report on Form 10-Q, the words “could,” “believe,” “anticipate,” “intend,” “estimate,” “expect,” “may,” “continue,” “predict,” “potential,” “project,” “plan,” “will,” and similar expressions are intended to identify forward-looking statements, although not all forward-looking statements contain such identifying words. These forward-looking statements are based on management's current belief, based on currently available information, as to the outcome and timing of future events.
Forward-looking statements include statements related to, among other things:
•the Company's business strategies;
•reserves estimates;
•estimated sales volumes;
•amount and allocation of forecasted capital expenditures and plans for funding capital expenditures and operating expenses;
•ability to modify future capital expenditures;
•anticipated costs;
•compliance with debt covenants;
•ability to fund and satisfy obligations related to ongoing operations;
•compliance with government regulations, including environmental, health, and safety regulations and liabilities thereunder;
•adequacy of gathering systems and continuous improvement of such gathering systems;
•impact from the lack of available gathering systems and processing facilities in certain areas;
•impact of any pandemic or other public health epidemic, including the ongoing COVID-19 pandemic;
•natural gas, oil, and natural gas liquid prices and factors affecting the volatility of such prices;
•impact of lower commodity prices;
•sufficiency of impairments;
•the ability to use derivative instruments to manage commodity price risk and ability to use such instruments in the future;
•our drilling inventory and drilling intentions;
•impact of potentially disruptive technologies;
•our estimated revenue gains and losses;
•the timing and success of specific projects;
•our implementation of standard and long reach laterals;
•our use of multi-well pads to develop the Niobrara and Codell formations;
•intention to continue to optimize enhanced completion techniques and well design changes;
•stated working interest percentages;
•management and technical team;
36
Table of Contents
•outcomes and effects of litigation, claims, and disputes;
•primary sources of future production growth;
•full delineation of the Niobrara B, C, and Codell benches in our legacy, French Lake, and northern acreage;
•our ability to replace oil and natural gas reserves;
•our ability to convert proved undeveloped reserves to producing properties within five years of their initial proved booking;
•impact of recently issued accounting pronouncements;
•impact of the loss a single customer or any purchaser of our products;
•timing and ability to meet certain volume commitments related to purchase and transportation agreements;
•the impact of customary royalty interests, overriding royalty interests, obligations incident to operating agreements, liens for current taxes, and other industry-related constraints;
•our financial position;
•our cash flow and liquidity;
•the adequacy of our insurance;
•the expected timetable for completing the XOG Merger and the Crestone Peak Merger, the results, effects, benefits and synergies of the mergers, future opportunities for the combined company, other plans and expectations with respect to the mergers, and the anticipated impact of the mergers on the combined company’s results of operations, financial position, growth opportunities and competitive position; and
•other statements concerning our 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, 2020 and in Part II, Item 1A of this report;
•further declines or volatility in the prices we receive for our oil, natural gas liquids, and natural gas;
•general economic conditions, whether internationally, nationally or in the regional and local market areas in which we do business;
•the effects of disruption of our operations or excess supply of oil and natural gas due to the COVID-19 pandemic and the actions by certain oil and natural gas producing countries;
•the scope, duration and severity of the COVID-19 pandemic, including any recurrence, as well as the timing of the economic recovery following the pandemic;
•ability of our customers to meet their obligations to us;
•our access to capital;
•our ability to generate sufficient cash flow from operations, borrowings, or other sources to enable us to fully develop our undeveloped acreage positions;
37
Table of Contents
•the presence or recoverability of estimated oil and natural gas reserves and the actual future sales volume rates and associated costs;
•uncertainties associated with estimates of proved oil and gas reserves;
•the possibility that the industry may be subject to future local, state, and federal regulatory or legislative actions (including additional taxes and changes in environmental regulation);
•environmental risks;
•seasonal weather conditions;
•lease stipulations;
•drilling and operating risks, including the risks associated with the employment of horizontal drilling and completion techniques;
•our ability to acquire adequate supplies of water for drilling and completion operations;
•availability of oilfield equipment, services, and personnel;
•exploration and development risks;
•operational interruption of centralized gas and oil processing facilities;
•competition in the oil and natural gas industry;
•management’s ability to execute our plans to meet our goals;
•our ability to attract and retain key members of our senior management and key technical employees;
•our ability to maintain effective internal controls;
•access to adequate gathering systems and pipeline take-away capacity;
•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;
•continued hostilities in the Middle East, South America, and other sustained military campaigns or acts of terrorism or sabotage; and
•other economic, competitive, governmental, legislative, regulatory, geopolitical, and technological factors that may negatively impact our businesses, operations, or pricing.
All forward-looking statements speak only as of the date of this report. We disclaim any obligation to update or revise these statements unless required by law, and you should not place undue reliance on these forward-looking statements. Although we believe that our plans, intentions, and expectations reflected in or suggested by the forward-looking statements we make in this report are reasonable, we can give no assurance that these plans, intentions, or expectations will be achieved. We disclose important factors that could cause our actual results to differ materially from our expectations under Part II, Item 1A. Risk Factors and Part I, Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations and elsewhere in this report. These cautionary statements qualify all forward-looking statements attributable to us or persons acting on our behalf. 
38
Table of Contents
Item 3. Quantitative and Qualitative Disclosures About Market Risk.
Oil, and 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 natural gas.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, and natural gas, and NGL prices include the level of global demand for oil, and natural gas, and NGL, the global supply of oil, and natural gas, the establishment of and compliance with production quotas by oil exporting countries, weather conditions which determine the demand for natural gas, the price and availability of alternative fuels, local and global politics, and overall economic conditions. It is impossible to predict future oil, and natural gas, and NGL prices with any degree of certainty. Sustained weakness in oil, and 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 natural gas liquidsNGL using NYMEX futures or over-the-counter derivative financial instruments. The types of derivative instruments that we use include swaps, collars, and puts.
Upon settlement of the contract(s),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 commodity price changes.changes in the physical market.
Presently, our derivative contracts have been executed with eight10 counterparties, all of which are members of our Credit Facility syndicate. We enter into contracts with counterparties whom we believe are well capitalized. However, if our counterparties fail to perform their obligations under the contracts, we could suffer financial loss.
Please refer to the Note 109 - Derivativesin under Part I, Item 1 of this report for summary derivative activity tables.
Interest Rates
As of bothAt June 30, 20212022 and on the filing date of this report, we had $99.0 million and $85.0 million, respectively, outstanding undera zero balance on our Credit Facility. Borrowings under our Credit Facility bear interest at a fluctuating rate that is tied to an adjustedAlternate Base Rate or LIBOR,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 flow.flows. As of June 30, 2021,2022 and through the filing date of this report, the Company was in compliance with all financial and non-financial covenants inunder the Credit Facility.
Counterparty and Customer Credit Risk
In connection with our derivatives activity, we have exposure to financial institutions in the form of derivative transactions. EightPresently, our derivative contracts have been executed with 10 counterparties, all of which are members of our Credit Facility syndicate aresyndicate. All counterparties on our derivative instruments currently in place and currently have investment grade credit ratings.
39
Table of Contents
We are also subject to credit risk due to concentration of our oil, and 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, and 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.
39
Table of Contents
A portion of our production may also be interrupted, or shut in, from time to time for numerous other reasons, including as a result of accidents, weather, or field labor issues or strikes, or we might voluntarily curtail production in response to market conditions. If a substantial amount of our production is interrupted at the same time, it could adversely affect our cash flow.
Currently, there are no pipeline systems that service wells in our French Lake area of the Wattenberg Field. If neither we nor a third-party constructs the required pipeline system, we may not be able to fully test or develop our resources in French Lake.
There have not been material changes to the interest rate risk analysis or oil and gas price sensitivity analysis disclosed in our Annual Report on Form 10-K for the year ended December 31, 2020.

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 June 30, 2021.2022. The term “disclosure controls and procedures,” as defined in Rules 13a-15(e) and 15d-15(e) under the Exchange Act, means controls and other procedures of a company that are designed to ensure that information required to be disclosed by a company in the reports that it files or submits under the Exchange Act is recorded, processed, summarized, and reported, within the time periods specified in SEC rules and forms. Disclosure controls and procedures include, without limitation, controls and procedures designed to ensure that information required to be disclosed by a company in the reports that it files or submits under the Exchange Act is accumulated and communicated to the company’s management, including its principal executive and principal financial officers and internal audit function, as appropriate, to allow timely decisions regarding required disclosure. Based on the evaluation of our disclosure controls and procedures as of June 30, 2021,2022, our principal executive officer and principal financial officer concluded that, as of such date, our disclosure controls and procedures were effective at the reasonable assurance level. 
Management recognizes that any controls and procedures, no matter how well designed and operated, can provide only reasonable assurance of achieving their objectives, and management necessarily applies its judgment in evaluating the cost-benefit relationship of possible controls and procedures. To assist management, we have established an internal audit function to verify and monitor our internal controls and procedures. The Company’s internal control system is supported by written policies and procedures, contains self-monitoring mechanisms, and is audited by the internal audit function. Appropriate actions are taken by management to correct deficiencies as they are identified.
Changes in Internal Control over Financial Reporting 
There were no changes in our internal control over financial reporting identified in management’s evaluation pursuant to Rules 13a-15(d) or 15d-15(d) of the Exchange Act during the quarter ended June 30, 20212022 that materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

PART II. OTHER INFORMATION
PART II-OTHER INFORMATION
Item 1. Legal Proceedings.
Information regarding our legal proceedings can be found in Note 6 - Commitments and Contingencies ofunder Part I, Item 1 of this reportreport.

.
40
Table of Contents
Item 1A. Risk Factors.
Our business faces many risks. Any of the risk factors discussed in this report or our other SEC filings could have a material impact on our business, financial position, or results of operations. Additional risks and uncertainties not presently known to us or that we currently believe to be immaterial may also impair our business operation. For a discussion of our potential risks and uncertainties, see the risk factors in Part I, Item 1A in our Annual Report on2021 Form 10-K for the year ended December 31, 2020,, together with other information in this report and other reports and materials we file with the SEC. We have identified these risk factors as important factors that could cause our actual results to differ materially from those contained in any written or oral forward-looking statements made by us or on our behalf.
Risks Relating to the XOG Merger and the Crestone Peak Merger
The XOG Merger and the Crestone Peak Merger are subject to a number of regulatory approvals and conditions to the obligations of the parties, which may delay the XOG Merger, the Crestone Peak Merger or both, result in additional expenditures of money and resources, or reduce the anticipated benefits or result in termination of the XOG Merger Agreement, the Crestone Peak Merger Agreement, or both.
The completion of the XOG Merger and the Crestone Peak Merger are subject to antitrust review in the United States. The waiting period under the Hart-Scott-Rodino Antitrust Improvements Act of 1976, as amended, expired for the XOG Merger on June 21, 2021 and for the Crestone Peak Merger on July 26, 2021. Nevertheless, the DOJ or the FTC, or any state, could take such action under the antitrust laws as it deems necessary or desirable in the public interest, including seeking to enjoin the completion of the XOG Merger, the Crestone Peak Merger or both. Private parties may also seek to take legal action under the antitrust laws under certain circumstances.
Our obligations and the obligations of XOG and Crestone Peak to consummate the XOG Merger and the Crestone Peak Merger, respectively, are subject to the satisfaction (or waiver by all parties, to the extent permissible under applicable laws) of a number of conditions described in the XOG Merger Agreement and the Crestone Peak Merger Agreement, including the approval of the XOG Merger by our and the XOG stockholders and the approval of the Crestone Peak Merger by our stockholders. Many of the conditions to completion of the XOG Merger and the Crestone Peak Merger are not within our control and we cannot predict when, or if, these conditions will be satisfied. If any of these conditions are not satisfied or waived prior to the outside date, as such term is defined in the XOG and Crestone Peak Merger Agreements, it is possible that the XOG Merger Agreement, the Crestone Peak Merger Agreement or both may be terminated.
Although the parties have agreed to use reasonable best efforts, subject to certain limitations, to complete the XOG Merger and the Crestone Peak Merger as promptly as practicable, these and other conditions may fail to be satisfied. In addition, completion of each merger may take longer, and could cost more, than we expect. The requirements for obtaining the required clearances and approvals could delay the completion of the XOG Merger, the Crestone Peak Merger or both for a significant period of time or prevent them from occurring. Any delay in completing the XOG Merger or the Crestone Peak Merger may adversely affect the cost savings and other benefits that we expect to achieve if the XOG Merger and the Crestone Peak Merger and the integration of businesses are completed within the expected timeframe.
Each of the XOG Merger Agreement and the Crestone Peak Merger Agreement subject us to restrictions on our business activities prior to closing the XOG Merger and the Crestone Peak Merger, respectively.
Each of the XOG Merger Agreement and the Crestone Peak Merger Agreement subject us to restrictions on our business activities prior to closing the XOG Merger and the Crestone Peak Merger, respectively. Each of the XOG Merger Agreement and the Crestone Peak Merger Agreement obligate us to generally conduct our businesses in the ordinary course until the closing and to use our reasonable best efforts to (i) preserve substantially intact our present business organization, goodwill and assets, (ii) keep available the services of our current officers and employees and (iii) preserve our existing relationships with governmental entities and significant customers, suppliers, licensors, licensees, distributors, lessors and others having significant business dealings with us. These restrictions could prevent us from pursuing certain business opportunities that arise prior to the closing and are outside the ordinary course of business.
41
Table of Contents
We may not realize anticipated benefits and synergies expected from acquisitions, including the XOG Merger and the Crestone Peak Merger.
We seek to complete acquisitions in order to strengthen our position and to create the opportunity to realize certain benefits, including, among other things, potential cost savings. Achieving the benefits of acquisitions depends in part on successfully consolidating functions and integrating operations and procedures in a timely and efficient manner, as well as being able to realize the anticipated growth opportunities and synergies from combining the acquired businesses and operations. We may fail to realize the anticipated benefits and synergies expected from acquisitions, which could adversely affect our business, financial condition and operating results.Acquisitions could also result in difficulties in being able to hire, train or retain qualified personnel to manage and operate such properties.
With respect to the XOG Merger and the Crestone Peak Merger, we believe that the addition of XOG and Crestone Peak will complement our strategy by providing operational and financial scale, increasing free cash flow, and enhancing our corporate rate of return. However, achieving these goals requires, among other things, realization of the targeted cost synergies expected from the merger, and there can be no assurance that we will be able to successfully integrate XOG's and Crestone Peak’s assets or otherwise realize the expected benefits of the transaction. This growth and the anticipated benefits of the XOG Merger and the Crestone Peak Merger may not be realized fully or at all, or may take longer to realize than expected. Difficulties in integrating XOG and Crestone Peak may result in the combined company performing differently than expected, or in operational challenges or failures to realize anticipated efficiencies. Potential difficulties in realizing the anticipated benefits of the XOG Merger and the Crestone Peak Merger include:
•disruptions of relationships with customers, distributors, suppliers, vendors, landlords, joint venture partners and other business partners as a result of uncertainty associated with the XOG Merger and the Crestone Peak Merger;
•difficulties integrating our business with the business of XOG and Crestone Peak in a manner that permits us to achieve the full revenue and cost savings anticipated from the transaction;
•complexities associated with managing a larger and more complex business, including difficulty addressing possible inconsistencies in, standards, controls or operational philosophies and the challenge of integrating complex systems, technology, networks and other assets of each of the companies in a seamless manner that minimizes any adverse impact on customers, suppliers, employees and other constituencies;
•difficulties realizing anticipated operating synergies;
•difficulties integrating personnel, vendors and business partners;
•loss of key employees of XOG or Crestone Peak who are critical to our future operations due to uncertainty about their roles within our company following the XOG Merger and the Crestone Peak Merger or other concerns regarding the XOG Merger and the Crestone Peak Merger;
•potential unknown liabilities and unforeseen expenses;
•performance shortfalls at one or more of the companies as a result of the diversion of management’s attention to integration efforts; and
•disruption of, or the loss of momentum in, each company’s ongoing business.
We have also incurred, and expect to continue to incur, a number of costs associated with completing the XOG Merger and the Crestone Peak Merger and combining the businesses of XOG, Crestone Peak and Bonanza Creek. The elimination of duplicative costs, as well as the realization of other efficiencies related to the integration of the two companies, may not initially offset integration-related costs or achieve a net benefit in the near term, or at all. Matters relating to the mergers (including integration planning) require substantial commitments of time and resources by our management, which may result in the distraction of management from ongoing business operations and pursuing other opportunities that could have been beneficial to us.
Our future success will depend, in part, on our ability to manage our expanded business by, among other things, integrating the assets, operations and personnel of XOG, Crestone Peak and Bonanza Creek in an efficient and timely manner; consolidating systems and management controls; and successfully integrating relationships with customers, vendors and business partners. Failure to successfully manage the combined company may have an adverse effect on our business, reputation, financial condition and results of operations.
42
Table of Contents
The XOG Merger and the Crestone Peak Merger will trigger a limitation on the utilization of our historic U.S. net operating loss carryforwards (“NOLs”), XOG’s NOLs and Crestone Peak’s NOLs.
Our ability to utilize NOLs (including NOLs of XOG and Crestone Peak) to reduce future taxable income following the XOG Merger and the Crestone Peak Merger depends on many factors, including our future income, which cannot be assured. Section 382 of the Code generally imposes an annual limitation upon the occurrence of an “ownership change” resulting from issuances of a company’s stock or the sale or exchange of such company’s stock by certain stockholders if, as a result, there is an aggregate change of more than 50% in the beneficial ownership of such company’s stock by such stockholders within a rolling three-year period. The limitation with respect to such loss carryforwards generally would be equal to (i) the fair market value of the company’s equity immediately prior to the ownership change multiplied by (ii) a percentage approximately equivalent to the yield on long-term tax-exempt bonds during the month in which the ownership change occurs. Based on the information currently available, we believe that the transactions in connection with the XOG Merger and the Crestone Peak Merger, if consummated, will result in an ownership change with respect to us, XOG, and Crestone Peak, which would trigger a limitation (calculated as described above) on our ability to utilize any historic NOLs following the XOG Merger and the Crestone Peak Merger. XOG’s NOLs are already limited under Section 382 of the Code as a result of an ownership change that occurred in connection with XOG’s Chapter 11 cases.
The market price for our common stock following the XOG Merger and the Crestone Peak Merger may be affected by factors different from those that historically have affected or currently affect our common stock.
Our financial position following the XOG Merger and the Crestone Peak Merger may differ from our financial position before the XOG Merger and the Crestone Peak Merger, and the results of operations of the combined company may be affected by factors that are different from those currently affecting the results of our operations. Accordingly, the market price and performance of our common stock is likely to be different from the performance of our common stock in the absence of the XOG Merger and the Crestone Peak Merger.
Our stockholders, XOG stockholders and Crestone Peak stockholders, in each case as of immediately prior to the mergers, will have reduced ownership in the combined company.
We anticipate issuing 30,936,254 shares of Common Stock to XOG stockholders pursuant to the XOG Merger Agreement and 22,500,000 shares of Common Stock to Crestone Peak stockholders pursuant to the Crestone Peak Merger Agreement. The issuance of these new shares could have the effect of depressing the market price of our Common Stock, through dilution of earnings per share or otherwise. Any dilution of, or delay of any accretion to, our earnings per share could cause the price of our Common Stock to decline or increase at a reduced rate.
Following the completion of the XOG Merger, assuming the Crestone Peak Merger is not consummated, it is anticipated that persons who were stockholders of Bonanza Creek and XOG immediately prior to the XOG Merger will own approximately 50% and 50% of the combined company, respectively. Following the completion of the Crestone Peak Merger, it is anticipated that persons who were stockholders of Bonanza Creek, XOG and Crestone Peak immediately prior to the Crestone Peak Merger will own approximately 37%, 37% and 26% of the combined company, respectively. As a result, our current stockholders, XOG’s current stockholders and Crestone Peak’s stockholders will have less influence on the policies of the combined company than they currently have on our policies and the polices of Extraction and Crestone Peak, respectively.
The Kimmeridge Fund will become a significant holder of our Common Stock following completion of the XOG Merger.
Upon completion of the XOG Merger, assuming there is no decrease in the Kimmeridge Fund’s holdings of XOG common stock prior to completion of the XOG Merger, the Kimmeridge Fund would be expected to own approximately 19% of our Common Stock, representing approximately 19% of our combined voting power (That percentage would be reduced to approximately 14% if the Crestone Peak Merger closes.). In addition, upon completion of the XOG Merger, Mr. Benjamin Dell, independent chairman of the XOG board and a Managing Director of the Kimmeridge Fund, will serve as chairman of the board of directors of the combined company. As a result, we believe that the Kimmeridge Fund may or will have some ability to influence our management and affairs. Further, the existence of a new significant stockholder may have the effect of deterring hostile takeovers, delaying or preventing changes in control or changes in management, or limiting the ability of our other stockholders to approve transactions that they may view as being in their best interests or in our best interests.
In the event that the Kimmeridge Fund becomes and continues to be the owner of a significant amount of our Common Stock, the prospect that it may be able to influence matters requiring stockholder approval may continue. In any of these matters, the interests of the Kimmeridge Fund and of our other stockholders may differ or conflict. Moreover, in the event that the Kimmeridge Fund becomes and continues to be the owner of a significant concentration of our Common Stock, such an ownership stake may also adversely affect the trading price of our Common Stock to the extent investors perceive a disadvantage in owning stock of a company with a significant stockholder.
43
Table of Contents
CPPIB Crestone Peak Resources Canada Inc., a Canadian corporation (the “Crestone Peak Stockholder”) will become a significant holder of our Common Stock following completion of the Crestone Peak Merger.
Upon completion of the Crestone Peak Merger, assuming there is no decrease in the Crestone Peak Stockholder’s holdings of Crestone Peak common stock prior to completion of the Crestone Peak Merger, the Crestone Peak Stockholder would be expected to own approximately 25% of our Common Stock, representing approximately 25% of our combined voting power. As a result, we believe that the Crestone Peak Stockholder may have some ability to influence our management and affairs. Further, the existence of a new significant stockholder may have the effect of deterring hostile takeovers, delaying or preventing changes in control or changes in management, or limiting the ability of our other stockholders to approve transactions that they may view as being in their best interests or in our best interests.
In the event that the Crestone Peak Stockholder becomes and continues to be the owner of a significant amount of our Common Stock, the prospect that it may be able to influence matters requiring stockholder approval may continue. In any of these matters, the interests of the Crestone Peak Stockholder may differ or conflict from those of our other stockholders. Moreover, in the event that the Crestone Peak Stockholder becomes and continues to be the owner of a significant concentration of our Common Stock, such an ownership stake may also adversely affect the trading price of our Common Stock to the extent investors perceive a disadvantage in owning stock of a company with a significant stockholder.


44
Table of Contents
Risks Relating to the HighPoint Merger

We may not achieve the anticipated benefits of the HighPoint Merger.
The success of the HighPoint Merger will depend, in part, on our ability to realize the anticipated benefits and cost savings from combining our and HighPoint’s businesses, and there can be no assurance that we will be able to realize the anticipated benefits of the HighPoint Merger. The combined company may perform differently than expected, face operational challenges, or fail to realize anticipated expense-related efficiencies. Potential difficulties that may be encountered in the integration process include, among others:

•complexities associated with managing a larger, more complex, integrated business;
•not realizing anticipated operating synergies;
•potential unknown liabilities and unforeseen expenses associated with the HighPoint Merger; and
•managing expanded environmental and other regulatory compliance obligations related to HighPoint's facilities and operations.

Our results may suffer if we do not effectively manage our expanded operations following the HighPoint Merger.
Following completion of the HighPoint Merger, the size of our business has increased significantly. Our future success will depend, in part, on our ability to manage this expanded business, which poses numerous risks and uncertainties, including the need to integrate the operations and business of HighPoint into our existing business in an efficient and timely manner, to combine systems and management controls and to integrate relationships with various business partners. Failure to successfully manage the combined company may have an adverse effect on our financial condition, results of operations or cash flows.

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

The market price of our common stock will continue to fluctuate, and may decline if the benefits of the HighPoint Merger do not meet the expectations of financial analysts.
The market price of our common stock may fluctuate significantly, including if we do not achieve the anticipated benefits of the HighPoint Merger as rapidly, or to the extent anticipated by, financial analysts or if the effect of the HighPoint Merger on our financial results is not consistent with the expectations of financial analysts.
45
Table of Contents

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 June 30, 2021.2022.
Issuer Purchases of Equity Securities.Issuer purchases of equity securities. The following table contains information about acquisitionsour acquisition of our equity securities during the three month periodmonths ended June 30, 2021:2022.
Total Number of SharesMaximum Number of
Total NumberPurchased as Part ofShares that May Be
of SharesAverage PricePublicly Announced Purchased Under Plans
Purchased(1)
Paid per SharePlans or Programsor Programs
April 1, 2021 - April 30, 202138,556 $34.53 — — 
May 1, 2021 - May 31, 202122,673 $38.26 — — 
June 1, 2021 - June 30, 20219,101 $46.87 — — 
Total70,330 $36.32 — — 
_____________________________
Total Number of SharesMaximum Number of
Total NumberPurchased as Part ofShares that May Be
of SharesAverage PricePublicly AnnouncedPurchased Under Plans
Purchased(1)
Paid per SharePlans or Programsor Programs
April 1, 2022 - April 30, 202220,408 $59.37 — — 
May 1, 2022 - May 31, 202214,912 $64.23 — — 
June 1, 2022 - June 30, 20225,326 $71.28 — — 
Total40,646 $61.18 — — 
_________________________
(1)RepresentsRepresent shares that employees surrendered back to us that equaled in value the amount of taxes requiredneeded for payroll tax withholding obligations upon the vesting of equity awards under the LTIP.restricted stock awards. These repurchases were not part of a publicly announced plan or program to repurchase shares of our common stock, nor do we have a publicly announced plan or program to repurchase shares of our common stock.
OurDividend Policy. On May 3, 2021, we announced the initiation of an annual cash dividend in the amount of $1.40 per share of our common stock payable quarterly, which began on July 14, 2021. Beginning with the fourth quarter of 2021, the annual cash dividend was increased to $1.85 per share of our common stock.
In March 2022, the Board approved the initiation of a quarterly variable cash dividend, equal to 50% of free cash flow after the fixed cash dividend for the preceding twelve-month period and pro forma for all acquisition and divestiture activity, assuming pro forma compliance with certain leverage targets. The Company’s inaugural quarterly variable cash dividend was declared at $0.75 per share and paid in combination with the fixed cash dividend on March 30, 2022 to shareholders of record on March 18, 2022, resulting a total quarterly dividend of $1.2125 per share. In May 2022, the Company declared another variable dividend $0.90 per share and paid in combination with the fixed dividend on June 29, 2022 to shareholders of record as of June 15, 2022, resulting in a total quarterly dividend of $1.3625 per share.
The decision to pay any future dividends is solely within the discretion of, and subject to approval by, the Board. The Board's’ determination with respect to any such dividends, including the record date, the payment date, and the actual amount of the dividend, will depend upon our profitability and financial condition, contractual restrictions, restrictions imposed by applicable law, and other factors that the Board deems relevant at the time of such determination. Additionally, covenants contained in our Credit Facility contains restrictive thresholds onand the indentures governing our senior notes restrict the payment of dividends.cash dividends on our common stock, as discussed further in Note 5 - Long-Term Debt under Part I, Item 1 of this report.

Item 3.  Defaults Upon Senior Securities.
None.

Item 4. Mine Safety Disclosures.
Not applicable.

Item 5. Other Information.
None.
41


46
Table of Contents
Item 6. Exhibits.
Exhibit No.
Number
Description of Exhibit
2.1
2.2
2.3
2.32.4
2.42.5
3.1
3.2
4.13.3
3.4
10.1*
10.2*
10.3*
10.4
4.210.5*
4.310.6*
10.110.7*
10.8†
10.210.9†
4742
Table of Contents
32.1**31.1†
31.2†
32.1†
32.2**32.2†
101.INS*101.INS†XBRL Instance Document
101.SCH†
101.SCH*XBRL Taxonomy Extension Schema
101.CAL*101.CAL†XBRL Taxonomy Extension Calculation Linkbase
101.DEF†
101.DEF*XBRL Taxonomy Extension Definition Linkbase
101.LAB†
101.LAB*XBRL Taxonomy Extension Label Linkbase
101.PRE*101.PRE†XBRL Taxonomy Extension Presentation Linkbase
104Cover Page Interactive Data File (formatted as Inline XBRL)
__________________________________________
*Filed with this report
**Furnished with this report
†Management Contract or Compensatory Plan or AgreementXBRL and contained in Exhibit 101)
_________________________
*            Management Contract or Compensatory Plan or Arrangement
†            Filed or furnished herewith
48
43
Table of Contents
SIGNATURES
Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.
   BONANZA CREEK ENERGY,CIVITAS RESOURCES, INC.
    
Date:August 9, 20213, 2022    By:/s/ Eric T. GreagerChris Doyle
    Eric T. GreagerChris Doyle
    President and Chief Executive Officer
(principal (principal executive officer)
     
   By:/s/ Brant DeMuthMarianella Foschi
    Brant DeMuthMarianella Foschi
    Executive Vice President and Chief Financial Officer
(principal (principal financial officer)
By:/s/ Sandi K. Garbiso
 Sandi K. Garbiso
 Vice President and Chief Accounting Officer
(chief and Treasurer (chief accounting officer)

4944