CIVITAS RESOURCES, INC. - Quarter Report: 2022 June (Form 10-Q)
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, 2022
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
Civitas Resources, Inc.
(Exact name of registrant as specified in its charter)
| Delaware | 61-1630631 | |||||||
| (State or other jurisdiction of incorporation or organization) | (I.R.S. Employer Identification No.) | |||||||
| 555 17th Street, | Suite 3700 | |||||||||||||
| Denver, | Colorado | 80202 | ||||||||||||
| (Address of principal executive offices) | (Zip Code) | |||||||||||||
(303) 293-9100
(Registrant’s telephone number, including area code)
| Securities registered pursuant to Section 12(b) of the Act: | ||||||||
| Title of each class | Trading Symbol | Name of exchange on which registered | ||||||
| Common Stock, par value $0.01 per share | CIVI | New York Stock Exchange | ||||||
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. ☒ Yes ☐ No
Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit such files). ☒ Yes ☐ No
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, smaller reporting company, or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer”, “smaller reporting company,” and “emerging growth company” in Rule 12b-2 of the Exchange Act.
| Large Accelerated Filer | ☒ | Accelerated Filer | ☐ | ||||||||||||||
| Non-accelerated Filer | ☐ | Smaller reporting company | ☐ | ||||||||||||||
| Emerging growth company | ☐ | ||||||||||||||||
If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. ☐
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). ☐ Yes ☒ No
As of August 1, 2022, the registrant had 85,031,963 shares of common stock outstanding.
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CIVITAS RESOURCES, INC.
FORM 10-Q
FOR THE QUARTER ENDED JUNE 30, 2022
TABLE OF CONTENTS
| PAGE | ||||||||||||||
Condensed Consolidated Balance Sheets as of June 30, 2022 and December 31, 2021 | ||||||||||||||
Condensed Consolidated Statements of Operations and Comprehensive Income (Loss) for the Three and Six Months Ended June 30, 2022 and 2021 | ||||||||||||||
Condensed Consolidated Statements of Stockholders' Equity for the Three and Six Months Ended June 30, 2022 and 2021 | ||||||||||||||
Condensed Consolidated Statements of Cash Flows for the Six Months Ended June 30, 2022 and 2021 | ||||||||||||||
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Information Regarding Forward-Looking Statements
This Quarterly Report on Form 10-Q contains various statements, including those that express belief, expectation or intention, as well as those that are not statements of historic fact, that are forward-looking statements within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities and Exchange Act of 1934, as amended (the “Exchange Act”). When used in this Quarterly Report on Form 10-Q, the words “could,” “believe,” “anticipate,” “intend,” “estimate,” “expect,” “may,” “continue,” “predict,” “potential,” “project,” “plan,” “will,” and similar expressions are intended to identify forward-looking statements, although not all forward-looking statements contain such identifying words. These forward-looking statements are based on management's current belief, based on currently available information, as to the outcome and timing of future events.
Forward-looking statements include statements related to, among other things:
•the Company’s business strategies;
•reserves estimates;
•estimated sales volumes;
•the amount and allocation of forecasted capital expenditures and plans for funding capital expenditures and operating expenses;
•our ability to modify future capital expenditures;
•anticipated costs;
•compliance with debt covenants;
•our ability to fund and satisfy obligations related to ongoing operations;
•compliance with government regulations, including environmental, health, and safety regulations and liabilities thereunder;
•the adequacy of gathering systems and continuous improvement of such gathering systems;
•the impact from the lack of available gathering systems and processing facilities in certain areas;
•the impact of any pandemic or other public health epidemic, including the ongoing COVID-19 pandemic;
•oil, natural gas, and natural gas liquid prices and factors affecting the volatility of such prices;
•the impact of lower commodity prices;
•sufficiency of impairments;
•the ability to use derivative instruments to manage commodity price risk and ability to use such instruments in the future;
•our drilling inventory and drilling intentions;
•the impact of potentially disruptive technologies;
•our estimated revenue gains and losses;
•the timing and success of specific projects;
•our implementation of standard and long reach laterals;
•our intention to continue to optimize enhanced completion techniques and well design changes;
•stated working interest percentages;
•our management and technical team;
•outcomes and effects of litigation, claims, and disputes;
•primary sources of future production growth;
•our ability to replace oil and natural gas reserves;
•our ability to convert proved undeveloped reserves to producing properties within five years of their initial proved booking;
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•our ability to pay future cash dividends on our common stock;
•the impact of the loss a single customer or any purchaser of our products;
•the timing and ability to meet certain volume commitments related to purchase and transportation agreements;
•the impact of customary royalty interests, overriding royalty interests, obligations incident to operating agreements, liens for current taxes, and other industry-related constraints;
•our anticipated financial position, including our cash flow and liquidity;
•the adequacy of our insurance;
•the results, effects, benefits, and synergies of our recent mergers and acquisitions, future opportunities for the combined companies, other plans and expectations with respect to these transactions, and the anticipated impact of these transactions on the combined company’s results of operations, financial position, growth opportunities, and competitive position; and
•other statements concerning our anticipated operations, economic performance, and financial condition.
We have based these forward-looking statements on certain assumptions and analyses we have made in light of our experience and our perception of historical trends, current conditions, and expected future developments as well as other factors we believe are appropriate under the circumstances. They can be affected by inaccurate assumptions or by known or unknown risks and uncertainties. Many such factors will be important in determining actual future results. The actual results or developments anticipated by these forward-looking statements are subject to a number of risks and uncertainties, many of which are beyond our control, and may not be realized or, even if substantially realized, may not have the expected consequences. Actual results could differ materially from those expressed or implied in the forward-looking statements.
Factors that could cause actual results to differ materially include, but are not limited to, the following:
•the risk factors discussed in Part I, Item 1A of our Annual Report on Form 10-K for the year ended December 31, 2021 and in Part II, Item 1A of this report;
•declines or volatility in the prices we receive for our oil, natural gas, and natural gas liquids;
•general economic conditions, whether internationally, nationally or in the regional and local market areas in which we do business;
•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;
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•operational interruption of centralized oil and natural gas processing facilities;
•competition in the oil and natural gas industry;
•management’s ability to execute our plans to meet our goals;
•our ability to attract and retain key members of our senior management and key technical employees;
•our ability to maintain effective internal controls;
•access to adequate gathering systems and pipeline take-away capacity;
•our ability to secure adequate processing capacity for natural gas we produce, to secure adequate transportation for oil, natural gas, and natural gas liquids we produce, and to sell the oil, natural gas, and natural gas liquids at market prices;
•costs and other risks associated with perfecting title for mineral rights in some of our properties;
•political conditions in or affecting other producing countries, including conflicts in or relating to the Middle East, South America, and Russia (including the current events involving Russia and Ukraine), and other sustained military campaigns or acts of terrorism or sabotage; and
•other economic, competitive, governmental, legislative, regulatory, geopolitical, and technological factors that may negatively impact our businesses, operations, or pricing.
All forward-looking statements speak only as of the filing date of this report. We disclaim any obligation to update or revise these statements unless required by law, and you should not place undue reliance on these forward-looking statements. Although we believe that our plans, intentions, and expectations reflected in or suggested by the forward-looking statements we make in this report are reasonable, we can give no assurance that these plans, intentions, or expectations will be achieved. We disclose important factors that could cause our actual results to differ materially from our expectations under “Item 1A. Risk Factors” and other sections of our Annual Report on Form 10-K for the fiscal year ended December 31, 2021, as updated by subsequent reports we file with the SEC (including this report). These cautionary statements qualify all forward-looking statements attributable to us or persons acting on our behalf.
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PART I. FINANCIAL INFORMATION
Item 1. Financial Statements.
CIVITAS RESOURCES, INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATED BALANCE SHEETS (UNAUDITED)
(in thousands, except per share amounts)
The accompanying notes are an integral part of these condensed consolidated financial statements.
| June 30, 2022 | December 31, 2021 | ||||||||||
| ASSETS | |||||||||||
| Current assets: | |||||||||||
| Cash and cash equivalents | $ | 439,251 | $ | 254,454 | |||||||
| Accounts receivable, net: | |||||||||||
| Oil, natural gas, and NGL sales | 432,694 | 362,262 | |||||||||
| Joint interest and other | 95,253 | 66,390 | |||||||||
| Prepaid expenses and other | 31,064 | 21,052 | |||||||||
| Inventory of oilfield equipment | 21,195 | 12,386 | |||||||||
| Derivative assets | — | 3,393 | |||||||||
| Total current assets | 1,019,457 | 719,937 | |||||||||
Property and equipment (successful efforts method): | |||||||||||
| Proved properties | 6,132,620 | 5,457,213 | |||||||||
| Less: accumulated depreciation, depletion, and amortization | (803,774) | (430,201) | |||||||||
| Total proved properties, net | 5,328,846 | 5,027,012 | |||||||||
| Unproved properties | 666,821 | 688,895 | |||||||||
| Wells in progress | 303,071 | 177,296 | |||||||||
Other property and equipment, net of accumulated depreciation of $6,072 in 2022 and $4,742 in 2021 | 50,243 | 51,639 | |||||||||
| Total property and equipment, net | 6,348,981 | 5,944,842 | |||||||||
| Right-of-use assets | 31,487 | 39,885 | |||||||||
| Deferred income tax assets | — | 22,284 | |||||||||
| Other noncurrent assets | 14,505 | 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 payable | 303,182 | 144,408 | |||||||||
| Oil and natural gas revenue distribution payable | 494,091 | 466,233 | |||||||||
| Lease liability | 17,452 | 18,873 | |||||||||
| Derivative liability | 278,600 | 219,804 | |||||||||
| Income tax payable | 50,385 | — | |||||||||
| Asset retirement obligations | 24,000 | 24,000 | |||||||||
| Total current liabilities | 1,473,980 | 1,119,506 | |||||||||
| Long-term liabilities: | |||||||||||
| Senior notes | 392,508 | 491,710 | |||||||||
| Lease liability | 14,576 | 21,398 | |||||||||
| Ad valorem taxes | 186,603 | 232,147 | |||||||||
| Derivative liability | 43,225 | 19,959 | |||||||||
| Deferred income tax liabilities | 107,884 | — | |||||||||
| Asset retirement obligations | 203,104 | 201,315 | |||||||||
| Total liabilities | 2,421,880 | 2,086,035 | |||||||||
| Commitments and contingencies (Note 6) | |||||||||||
| Stockholders’ equity: | |||||||||||
Preferred stock, $.01 par value, 25,000,000 shares authorized, none outstanding | — | — | |||||||||
Common stock, $.01 par value, 225,000,000 shares authorized, 85,031,963 and 84,572,846 issued and outstanding as of June 30, 2022 and December 31, 2021, respectively | 4,917 | 4,912 | |||||||||
| Additional paid-in capital | 4,197,790 | 4,199,108 | |||||||||
| Retained earnings | 789,843 | 450,978 | |||||||||
| Total stockholders’ equity | 4,992,550 | 4,654,998 | |||||||||
| Total liabilities and stockholders’ equity | $ | 7,414,430 | $ | 6,741,033 | |||||||
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CIVITAS RESOURCES, INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS AND COMPREHENSIVE INCOME (LOSS) (UNAUDITED)
(in thousands, except per share amounts)
| Three Months Ended June 30, | Six Months Ended June 30, | |||||||||||||||||||||||||
| 2022 | 2021 | 2022 | 2021 | |||||||||||||||||||||||
| Operating net revenues: | ||||||||||||||||||||||||||
| Oil, natural gas, and NGL sales | $ | 1,151,364 | $ | 156,035 | $ | 1,969,174 | $ | 230,194 | ||||||||||||||||||
| Operating expenses: | ||||||||||||||||||||||||||
| Lease operating expense | 41,877 | 11,358 | 77,896 | 17,089 | ||||||||||||||||||||||
| Midstream operating expense | 7,469 | 4,246 | 13,181 | 8,151 | ||||||||||||||||||||||
| Gathering, transportation, and processing | 79,519 | 13,721 | 129,922 | 18,688 | ||||||||||||||||||||||
| Severance and ad valorem taxes | 85,870 | 9,813 | 149,174 | 14,417 | ||||||||||||||||||||||
| Exploration | 1,553 | 3,547 | 2,081 | 3,643 | ||||||||||||||||||||||
| Depreciation, depletion, and amortization | 204,519 | 35,006 | 389,379 | 53,829 | ||||||||||||||||||||||
| Abandonment and impairment of unproved properties | — | 2,215 | 17,975 | 2,215 | ||||||||||||||||||||||
| Unused commitments | 1,731 | 4,328 | 2,507 | 4,328 | ||||||||||||||||||||||
| Bad debt expense | 4 | — | 4 | — | ||||||||||||||||||||||
| Merger transaction costs | 1,418 | 18,246 | 21,952 | 21,541 | ||||||||||||||||||||||
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 expenses | 453,626 | 114,624 | 869,457 | 165,296 | ||||||||||||||||||||||
| Other income (expense): | ||||||||||||||||||||||||||
| Derivative loss | (72,650) | (73,970) | (368,143) | (97,389) | ||||||||||||||||||||||
| Interest expense | (8,116) | (3,241) | (17,182) | (3,660) | ||||||||||||||||||||||
| Gain on property transactions, net | — | — | 16,797 | — | ||||||||||||||||||||||
| Other income | 4,313 | 89 | 5,096 | 277 | ||||||||||||||||||||||
| Total other expense | (76,453) | (77,122) | (363,432) | (100,772) | ||||||||||||||||||||||
| Income (loss) from operations before income taxes | 621,285 | (35,711) | 736,285 | (35,874) | ||||||||||||||||||||||
| Income tax benefit (expense) | (152,464) | 10,392 | (175,825) | 10,436 | ||||||||||||||||||||||
| Net income (loss) | $ | 468,821 | $ | (25,319) | $ | 560,460 | $ | (25,438) | ||||||||||||||||||
| Comprehensive income (loss) | $ | 468,821 | $ | (25,319) | $ | 560,460 | $ | (25,438) | ||||||||||||||||||
| Net income (loss) per common share: | ||||||||||||||||||||||||||
| Basic | $ | 5.52 | $ | (0.83) | $ | 6.60 | $ | (0.99) | ||||||||||||||||||
| Diluted | $ | 5.48 | $ | (0.83) | $ | 6.56 | $ | (0.99) | ||||||||||||||||||
| Weighted-average common shares outstanding | ||||||||||||||||||||||||||
| Basic | 84,993 | 30,655 | 84,917 | 25,774 | ||||||||||||||||||||||
| Diluted | 85,554 | 30,655 | 85,453 | 25,774 | ||||||||||||||||||||||
The accompanying notes are an integral part of these condensed consolidated financial statements.
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CIVITAS RESOURCES, INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ EQUITY (UNAUDITED)
(in thousands, except per share amounts)
| Additional | |||||||||||||||||||||||||||||
| Common Stock | Paid-In | Retained | |||||||||||||||||||||||||||
| Shares | Amount | Capital | Earnings | Total | |||||||||||||||||||||||||
Balances, December 31, 2021 | 84,572,846 | $ | 4,912 | $ | 4,199,108 | $ | 450,978 | $ | 4,654,998 | ||||||||||||||||||||
| Restricted common stock issued | 579,229 | 6 | — | — | 6 | ||||||||||||||||||||||||
| Stock used for tax withholdings | (215,811) | (2) | (12,932) | — | (12,934) | ||||||||||||||||||||||||
| Exercise of stock options | 5,294 | — | 178 | — | 178 | ||||||||||||||||||||||||
| Stock-based compensation | — | — | 8,090 | — | 8,090 | ||||||||||||||||||||||||
Cash dividends, $1.2125 per share | — | — | — | (104,444) | (104,444) | ||||||||||||||||||||||||
| Net income | — | — | — | 91,639 | 91,639 | ||||||||||||||||||||||||
| Balances, March 31, 2022 | 84,941,558 | 4,916 | 4,194,444 | 438,173 | 4,637,533 | ||||||||||||||||||||||||
| Restricted common stock issued | 130,309 | 1 | — | — | 1 | ||||||||||||||||||||||||
| Stock used for tax withholdings | (40,646) | — | (2,813) | — | (2,813) | ||||||||||||||||||||||||
| Exercise of stock options | 742 | — | 24 | — | 24 | ||||||||||||||||||||||||
| Stock-based compensation | — | — | 6,135 | — | 6,135 | ||||||||||||||||||||||||
Cash dividends, $1.3625 per share | — | — | — | (117,151) | (117,151) | ||||||||||||||||||||||||
| Net income | — | — | — | 468,821 | 468,821 | ||||||||||||||||||||||||
Balances, June 30, 2022 | 85,031,963 | $ | 4,917 | $ | 4,197,790 | $ | 789,843 | $ | 4,992,550 | ||||||||||||||||||||
Balances, December 31, 2020 | 20,839,227 | $ | 4,282 | $ | 707,209 | $ | 333,761 | $ | 1,045,252 | ||||||||||||||||||||
| Restricted common stock issued | 109 | — | — | — | — | ||||||||||||||||||||||||
| Stock used for tax withholdings | (38) | — | — | — | — | ||||||||||||||||||||||||
| Exercise of stock options | 429 | — | 15 | — | 15 | ||||||||||||||||||||||||
| Stock-based compensation | — | — | 1,612 | — | 1,612 | ||||||||||||||||||||||||
| Net loss | — | — | — | (119) | (119) | ||||||||||||||||||||||||
| Balances, March 31, 2021 | 20,839,727 | 4,282 | 708,836 | 333,642 | 1,046,760 | ||||||||||||||||||||||||
| Issuance pursuant to acquisition | 9,802,166 | 98 | 374,835 | — | 374,933 | ||||||||||||||||||||||||
| Restricted common stock issued | 261,539 | — | — | — | — | ||||||||||||||||||||||||
| Stock used for tax withholdings | (70,330) | (2) | (2,814) | — | (2,816) | ||||||||||||||||||||||||
| Exercise of stock options | 11,523 | — | 394 | — | 394 | ||||||||||||||||||||||||
| Stock-based compensation | — | — | 2,195 | — | 2,195 | ||||||||||||||||||||||||
Dividends declared, $0.3500 per share | — | — | — | (11,033) | (11,033) | ||||||||||||||||||||||||
| Net loss | — | — | — | (25,319) | (25,319) | ||||||||||||||||||||||||
Balances, June 30, 2021 | 30,844,625 | $ | 4,378 | $ | 1,083,446 | $ | 297,290 | $ | 1,385,114 | ||||||||||||||||||||
The accompanying notes are an integral part of these condensed consolidated financial statements.
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CIVITAS RESOURCES, INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (UNAUDITED)
(in thousands)
| Six Months Ended June 30, | |||||||||||
| 2022 | 2021 | ||||||||||
| 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 amortization | 389,379 | 53,829 | |||||||||
| Deferred income tax expense (benefit) | 125,440 | (10,228) | |||||||||
| Abandonment and impairment of unproved properties | 17,975 | 2,215 | |||||||||
| Stock-based compensation | 14,225 | 3,807 | |||||||||
| Amortization of deferred financing costs | 2,180 | 526 | |||||||||
| Derivative loss | 368,143 | 97,389 | |||||||||
| Derivative cash settlements loss | (348,209) | (23,990) | |||||||||
| Gain on property transactions, net | (16,797) | — | |||||||||
| Other | 155 | (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 liabilities | 192,839 | (3,428) | |||||||||
| Settlement of asset retirement obligations | (11,667) | (2,902) | |||||||||
| Net cash provided by operating activities | 1,254,768 | 79,559 | |||||||||
| Cash flows from investing activities: | |||||||||||
| Acquisition of oil and natural gas properties | (303,602) | (549) | |||||||||
| Cash acquired | 44,310 | 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 equipment | 66 | (38) | |||||||||
| Other | 117 | — | |||||||||
| Net cash used in investing activities | (733,491) | (8,029) | |||||||||
| Cash flows from financing activities: | |||||||||||
| Proceeds from credit facility | 100,000 | 155,000 | |||||||||
| Payments to credit facility | (100,000) | (210,000) | |||||||||
| Redemption of senior notes | (100,000) | — | |||||||||
| Proceeds from exercise of stock options | 202 | 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 cash | 184,797 | (340) | |||||||||
| Cash, cash equivalents, and restricted cash: | |||||||||||
| Beginning of period | 254,556 | 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.
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CIVITAS RESOURCES, INC. AND SUBSIDIARIES
NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED)
NOTE 1 - SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
Description of Operations
When we use the terms “Civitas,” the “Company,” “we,” “us,” or “our,” we are referring to Civitas Resources, Inc. and its consolidated subsidiaries unless the context otherwise requires. Effective November 1, 2021, Bonanza Creek Energy, Inc. changed its name to Civitas Resources, Inc. Civitas is an independent Denver-based exploration and production company focused on the acquisition, development, and production of oil and associated liquids-rich natural gas in the Rocky Mountain region, primarily in the Wattenberg Field of the Denver-Julesburg Basin (“DJ Basin”).
Basis of Presentation
The accompanying unaudited condensed consolidated financial statements include the accounts of the Company and have been prepared in accordance with accounting principles generally accepted in the United States (“GAAP”) for interim financial information, the instructions to Quarterly Report on Form 10-Q, and Regulation S-X. Accordingly, pursuant to such rules and regulations, certain notes and other financial information included in audited financial statements have been condensed or omitted. In the opinion of management, all adjustments, consisting of normal recurring adjustments considered necessary for a fair presentation of interim financial information, have been included. All significant intercompany balances and transactions have been eliminated in consolidation.
The December 31, 2021 unaudited condensed consolidated balance sheet data has been derived from the audited consolidated financial statements contained in our Annual Report on Form 10-K for the year ended December 31, 2021 (“2021 Form 10-K”), but does not include all disclosures, including notes required by GAAP. As such, this quarterly report should be read in conjunction with the audited consolidated financial statements and related notes included in our 2021 Form 10-K. In connection with the preparation of the unaudited condensed consolidated financial statements, the Company evaluated subsequent events after the balance sheet date of June 30, 2022, through the filing date of this report. The results of operations for the three and six months ended June 30, 2022 are not necessarily indicative of the results that may be expected for the full year or any other future period.
Significant Accounting Policies
The significant accounting policies followed by the Company are set forth in Note 1 - Summary of Significant Accounting Policies in the 2021 Form 10-K and are supplemented by the notes to the unaudited condensed consolidated financial statements included in this report.
Recently Issued and Adopted Accounting Standards
In March 2020, the FASB issued Update No. 2020-04, Reference Rate Reform (Topic 848), which provides temporary optional guidance to companies impacted by the transition away from the LIBOR. The amendment provides certain expedients and exceptions to applying GAAP in order to lessen the potential accounting burden when contracts, hedging relationships, and other transactions that reference LIBOR as a benchmark rate are modified. Further, in January 2021, the FASB issued Update No. 2021-01, Reference Rate Reform (Topic 848), which clarifies the scope of Topic 848 so that derivatives affected by the discounting transition are explicitly eligible for certain optional expedients and exceptions in Topic 848. These amendments are effective upon issuance and expire on December 31, 2022. We do not anticipate a material impact on the Company’s consolidated financial statements or related disclosures.
There are no other accounting standards applicable to the Company that would have a material effect on the Company’s financial statements and disclosures that have been issued but not yet adopted by the Company as of June 30, 2022, and through the filing date of this report.
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NOTE 2 - ACQUISITIONS AND DIVESTITURES
All mergers and acquisitions disclosed were accounted for under the acquisition method of accounting for business combinations. Accordingly, we conducted assessments of the net assets acquired and recognized amounts for identifiable assets acquired and liabilities assumed at their estimated acquisition date fair values, while transaction and integration costs associated with the acquisition were expensed as incurred. The fair value measurements of assets acquired and liabilities assumed were based on inputs that are not observable in the market, and therefore represent Level 3 inputs. The fair values of crude oil and natural gas properties and asset retirement obligations were measured using valuation techniques that convert future cash flows to a single discounted amount. Significant inputs to the valuation of proved oil properties include estimates of reserves, future operating and development costs, future commodity prices, estimated future cash flows, and a market-based weighted-average cost of capital. These inputs required significant judgments and estimates by management at the time of the valuation.
HighPoint Merger
On April 1, 2021, Civitas acquired HighPoint Resources Corporation (“HighPoint”), pursuant to the terms of HighPoint’s prepackaged plan of reorganization under Chapter 11 of the United States Bankruptcy Code (the “Prepackaged Plan”), which was confirmed by the U.S. Bankruptcy Court for the District of Delaware (the “HighPoint Merger”). Each eligible share of common stock of HighPoint issued and outstanding was automatically converted into the right to receive 0.11464 shares of common stock of Civitas (“Civitas Common Stock”). As a result, Civitas issued 487,952 shares of Civitas Common Stock to former HighPoint stockholders.
Concurrently with the HighPoint Merger and pursuant to the Prepackaged Plan, in exchange for the aggregate principal amount outstanding of HighPoint Operating Corporation's senior notes, Civitas issued an aggregate of (i) 9,314,214 shares of Civitas Common Stock and (ii) $100.0 million aggregate principal amount of 7.5% Senior Notes due 2026 (“7.5% Senior Notes”). Please refer to Note 5 - Long-Term Debt for further discussion of the 7.5% Senior Notes.
Total merger consideration transferred under the HighPoint Merger was $474.9 million.
Extraction Merger
On November 1, 2021, Civitas completed its merger with Extraction Oil & Gas, Inc. (“Extraction”), pursuant to the terms of the related Agreement and Plan of Merger (the “Extraction Merger Agreement”) (the “Extraction Merger”). Pursuant to the Extraction Merger Agreement, each share of common stock of Extraction (the “Extraction Common Stock”) issued and outstanding was converted into the right to receive 1.1711 shares of Civitas Common Stock for each share of Extraction Common Stock (the “Extraction Exchange Ratio”).
Additionally, each unvested award of restricted stock units issued pursuant to Extraction’s 2021 Long Term Incentive Plan (the “Extraction Equity Plan”) was assumed by Civitas and converted into a number of restricted stock units with respect to shares of Civitas Common Stock (such restricted stock unit, a “Converted RSU”) using the Extraction Exchange Ratio. Each Converted RSU continued to be governed by the same terms and conditions that were applicable immediately prior to the Extraction Merger closing date. 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.
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Total merger consideration transferred under the Extraction Merger was $1.8 billion. The following table presents the preliminary purchase price allocation of the assets acquired and the liabilities assumed in the Extraction Merger:
| Preliminary Purchase Price Allocation (in thousands) | ||||||||
| Assets Acquired | ||||||||
| Cash and cash equivalents | $ | 106,360 | ||||||
| Accounts receivable - oil and natural gas sales | 119,585 | |||||||
| Accounts receivable - joint interest and other | 33,054 | |||||||
| Prepaid expenses and other | 3,044 | |||||||
| Inventory of oilfield equipment | 9,291 | |||||||
| Derivative assets | 5,834 | |||||||
| Proved properties | 1,876,014 | |||||||
| Unproved properties | 193,400 | |||||||
| Other property and equipment, net of accumulated depreciation | 40,068 | |||||||
| Right-of-use assets | 6,883 | |||||||
| Deferred income tax assets | 49,194 | |||||||
| Other noncurrent assets | 4,248 | |||||||
| Total assets acquired | $ | 2,446,975 | ||||||
| Liabilities Assumed | ||||||||
| Accounts payable and accrued expenses | $ | 90,353 | ||||||
| Production taxes payable | 63,572 | |||||||
| Oil and natural gas revenue distribution payable | 170,002 | |||||||
| Income tax payable | 14,000 | |||||||
| Lease liability | 6,883 | |||||||
| Derivative liability | 100,474 | |||||||
| Ad valorem taxes | 87,071 | |||||||
| Asset retirement obligations | 68,741 | |||||||
| Other noncurrent liabilities | 1,750 | |||||||
| Total liabilities assumed | 602,846 | |||||||
| Net assets acquired | $ | 1,844,129 | ||||||
The valuation of proved properties for the Extraction Merger applied a market-based weighted-average cost of capital rate of approximately 10%. The purchase price allocation is preliminary, and Civitas is continuing to assess the fair values of certain of the assets acquired and liabilities assumed in the Extraction Merger as adjustments may be made to these measurements in subsequent periods (up to one year from the acquisition date). In particular, assets and liabilities subject to potential adjustment, in amounts that could be material to the pro forma financial statements, include, but are not limited to, proved properties, unproved properties, and accounts payable and accrued expenses related to our continued assessment over the application of lease contracts and related deductions. We cannot reasonably estimate the impact of such conclusions as there is still a high level of uncertainty regarding the potential outcomes of the assessment.
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Crestone Peak Merger
On November 1, 2021, Civitas completed its merger with CPPIB Crestone Peak Resources America Inc. (“Crestone Peak”), pursuant to the terms of the related Agreement and Plan of Merger (the “Crestone Merger Agreement”) (the “Crestone Peak Merger”). Pursuant to the Crestone Merger Agreement, the shares of Crestone Peak common stock were converted into the right to collectively receive 22.5 million shares of Civitas Common Stock, representing total merger consideration of $1.3 billion.
The following table presents the preliminary purchase price allocation of the assets acquired and the liabilities assumed in the Crestone Peak Merger:
| Preliminary Purchase Price Allocation (in thousands) | ||||||||
| Assets Acquired | ||||||||
| Cash and cash equivalents | $ | 67,505 | ||||||
| Accounts receivable - oil and natural gas sales | 81,340 | |||||||
| Accounts receivable - joint interest and other | 9,917 | |||||||
| Prepaid expenses and other | 2,929 | |||||||
| Inventory of oilfield equipment | 11,951 | |||||||
| Proved properties | 1,797,814 | |||||||
| Unproved properties | 453,321 | |||||||
| Other property and equipment, net of accumulated depreciation | 7,980 | |||||||
| Right-of-use assets | 7,934 | |||||||
| Total assets acquired | $ | 2,440,691 | ||||||
| Liabilities Assumed | ||||||||
| Accounts payable and accrued expenses | $ | 134,791 | ||||||
| Production taxes payable | 52,435 | |||||||
| Oil and natural gas revenue distribution payable | 83,950 | |||||||
| Lease liability | 7,934 | |||||||
| Derivative liability | 338,383 | |||||||
| Credit facility | 280,000 | |||||||
| Ad valorem taxes | 66,913 | |||||||
| Deferred income tax liabilities | 125,086 | |||||||
| Asset retirement obligations | 88,949 | |||||||
| Total liabilities assumed | 1,178,441 | |||||||
| Net assets acquired | $ | 1,262,250 | ||||||
The valuation of proved properties for the Crestone Peak Merger applied a market-based weighted-average cost of capital rate of approximately 10%. The purchase price allocation is preliminary, and Civitas is continuing to assess the fair values of certain of the assets acquired and liabilities assumed in the Crestone Peak Merger as adjustments may be made to these measurements in subsequent periods (up to one year from the acquisition date). In particular, assets and liabilities subject to potential adjustment, in amounts that could be material to the pro forma financial statements, include, but are not limited to, proved properties, unproved properties, and accounts payable and accrued expenses related to our continued assessment over the application of lease contracts and related deductions. We cannot reasonably estimate the impact of such conclusions as there is still a high level of uncertainty regarding the potential outcomes of the assessment.
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Revenue and earnings of the acquiree
The amount of revenue of HighPoint included in our statement of operations during the three and 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 three and six months ended June 30, 2021, assuming the HighPoint, Extraction, and Crestone Peak mergers had been completed as of January 1, 2020. The pro forma financial information is not necessarily indicative of the results of operations that would have been achieved if the mergers had been effective as of this date, or of future results, and includes certain non-recurring pro forma adjustments that were directly attributable to the business combinations (in thousands, except per share amounts).
| Three Months Ended June 30, 2021 | Six 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 | |||||||||||||
Bison Acquisition
On March 1, 2022, the Company completed the acquisition of privately held DJ Basin operator Bison Oil & Gas II, LLC (“Bison”) for merger consideration of approximately $279.7 million (the “Bison Acquisition”). Net assets acquired under the preliminary purchase price allocation were $294.2 million and consequently resulted in a bargain purchase gain of $14.5 million. Because of the immateriality of the Bison Acquisition, the related revenue and earnings, supplemental pro forma financial information, and detailed purchase price allocation are not disclosed.
Merger transaction costs
Merger transaction costs related to the aforementioned mergers and acquisitions are accounted for separately from the assets acquired and liabilities assumed and are included in merger transaction costs in the statements of operations. The Company incurred merger transaction costs of $1.4 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, | ||||||||||||||||||||||
| 2022 | 2021 | 2022 | 2021 | ||||||||||||||||||||
| Operating net revenues: | |||||||||||||||||||||||
| Oil sales | $ | 778,258 | $ | 116,091 | $ | 1,327,760 | $ | 166,155 | |||||||||||||||
| Natural gas sales | 205,840 | 15,168 | 319,001 | 28,300 | |||||||||||||||||||
| NGL sales | 167,266 | 24,776 | 322,413 | 35,739 | |||||||||||||||||||
| Oil, natural gas, and NGL sales | $ | 1,151,364 | $ | 156,035 | $ | 1,969,174 | $ | 230,194 | |||||||||||||||
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The Company recognizes revenue from the sale of produced oil, natural gas, and NGL at the point in time when control of produced oil, natural gas, or NGL volumes transfer to the purchaser, which may differ depending on the applicable contractual terms. The Company considers the transfer of control to have occurred when the purchaser has the ability to direct the use of, and obtain substantially all of the remaining benefits from, the oil, natural gas, or NGL production. Transfer of control dictates the presentation of gathering, transportation, and processing expenses within the accompanying statements of operations. Gathering, transportation, and processing expenses incurred by the Company prior to the transfer of control are recorded gross within the gathering, transportation, and processing line item on the accompanying statements of operations. Conversely, gathering, transportation, and processing expenses incurred by the Company subsequent to the transfer of control are recorded net within the oil, natural gas, and NGL sales line item on the accompanying statements of operations. Please refer to Note 1 - Summary of Significant Accounting Policies in the 2021 Form 10-K for more information regarding the types of contracts under which oil, gas, and NGL sales revenue is generated.
The Company records revenue in the month production is delivered and control is transferred to the purchaser. However, settlement statements and payment may not be received for 30 to 60 days after the date production is delivered and control is transferred. Until such time settlement statements and payment are received, the Company records a revenue accrual based on, amongst other factors, an estimate of the volumes delivered at estimated prices as determined by the applicable contractual terms. The Company records the differences between its estimates and the actual amounts received for product sales in the month in which payment is received from the purchaser. For the three and 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.
NOTE 4 - ACCOUNTS PAYABLE AND ACCRUED EXPENSES
Accounts payable and accrued expenses contain the following as of the dates indicated (in thousands):
| June 30, 2022 | December 31, 2021 | ||||||||||
| Accounts payable trade | $ | 12,166 | $ | 19,623 | |||||||
| Accrued drilling and completion costs | 132,096 | 129,430 | |||||||||
| Accrued lease operating expense and gathering, transportation, and processing | 80,834 | 19,077 | |||||||||
| Accrued general and administrative expense | 13,973 | 21,163 | |||||||||
| Accrued merger transaction costs | 2,199 | 1,475 | |||||||||
| Accrued oil and NGL hedging | 44,730 | 26,601 | |||||||||
| Accrued interest expense | 5,484 | 6,303 | |||||||||
| Accrued settlement | 10,291 | 20,791 | |||||||||
| Other accrued expenses | 4,497 | 1,725 | |||||||||
| Total accounts payable and accrued expenses | $ | 306,270 | $ | 246,188 | |||||||
NOTE 5 - LONG-TERM DEBT
5.0% Senior Notes
On October 13, 2021, the Company issued $400.0 million aggregate principal amount of 5.0% Senior Notes due 2026 (the “5.0% Senior Notes”) pursuant to an indenture (the “5.0% Indenture”), among Civitas Resources, Wells Fargo Bank, National Association, as trustee, and the guarantors party thereto. The Company used the net proceeds and cash on hand to repay all borrowings under the Credit Facility (as defined below), all borrowings outstanding under the Crestone Peak credit facility, and for general corporate purposes. Interest accrues at the rate of 5.0% per annum and is payable semiannually in arrears on April 15 and October 15 of each year. Payments commenced on April 15, 2022.
The 5.0% Indenture contains covenants that limit, among other things, the Company’s ability to: (i) incur or guarantee additional indebtedness; (ii) create liens securing indebtedness; (iii) pay dividends on or redeem or repurchase stock or subordinated debt; (iv) make specified types of investments and acquisitions; (v) enter into or permit to exist contractual limits on the ability of the Company’s subsidiaries to pay dividends to Civitas Resources; (vi) enter into transactions with affiliates; and (vii) sell assets or merge with other companies. These covenants are subject to a number of important limitations and exceptions. The Company was in compliance with all covenants under the 5.0% Indenture as of June 30, 2022, and through the filing of this report. In addition, certain of these covenants will be terminated before the 5.0% Senior Notes mature if at any time no default or event of default exists under the 5.0% Indenture and the 5.0% Senior Notes receive an investment-grade rating from at least two ratings agencies. The 5.0% Indenture also contains customary events of default.
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At any time prior to October 15, 2023, the Company may redeem the 5.0% Senior Notes, in whole or in part, at a redemption price equal to the sum of (i) the principal amount thereof, plus (ii) the “make-whole” premium at the redemption date, plus (iii) accrued and unpaid interest, if any. On or after October 15, 2023, the Company may redeem all or part of the 5.0% Senior Notes at redemption prices (expressed as percentages of the principal amount redeemed) equal to (i) 102.5% for the twelve-month period beginning on October 15, 2023; (ii) 101.25% for the twelve-month period beginning on October 15, 2024; and (iii) 100.0% for the twelve-month period beginning October 15, 2025 and at any time thereafter, plus accrued and unpaid interest, if any.
The Company may redeem up to 35% of the aggregate principal amount of the 5.0% Senior Notes at any time prior to October 15, 2023 with an amount not to exceed the net cash proceeds from certain equity offerings at a redemption price equal to 105.0% of the principal amount of the 5.0% Senior Notes redeemed, plus accrued and unpaid interest, if any, provided, however, that (i) at least 65.0% of the aggregate principal amount of the 5.0% Senior Notes originally issued on the issue date (but excluding 5.0% Senior Notes held by the Company) remains outstanding immediately after the occurrence of such redemption (unless all such 5.0% Senior Notes are redeemed substantially concurrently) and (ii) the redemption occurs within 180 days after the date of the closing of such equity offering.
The 5.0% Senior Notes are fully and unconditionally guaranteed on a senior unsecured basis by all of Civitas' existing subsidiaries.
7.5% Senior Notes
In conjunction with the HighPoint Merger, the Company issued $100.0 million aggregate principal amount of 7.5% Senior Notes due 2026 (the “7.5% Senior Notes”) pursuant to an indenture, dated April 1, 2021 , by and among Civitas Resources, U.S. Bank National Association, as trustee, and the guarantors party thereto. Interest accrued at the rate of 7.5% per annum and was payable semiannually in arrears on April 30 and October 31 of each year.
On May 1, 2022, the Company redeemed all of the issued and outstanding 7.5% Senior Notes at 100.0% of their aggregate principal amount, plus accrued and unpaid interest thereon to the redemption date.
The 7.5% Senior Notes and 5.0% Senior Notes are recorded net of unamortized deferred financing costs within the Senior notes line item on the accompanying balance sheets. There were no discounts or premiums associated with either issuance. The tables below present the related carrying values as of June 30, 2022 and December 31, 2021 (in thousands):
As of June 30, 2022 | |||||||||||||||||
| Principal Amount | Unamortized Deferred Financing Costs | Net Amount | |||||||||||||||
5.0% Senior Notes | $ | 400,000 | $ | 7,492 | $ | 392,508 | |||||||||||
As of December 31, 2021 | |||||||||||||||||
| Principal Amount | Unamortized Deferred Financing Costs | Net Amount | |||||||||||||||
7.5% Senior Notes | $ | 100,000 | $ | — | $ | 100,000 | |||||||||||
5.0% Senior Notes | $ | 400,000 | $ | 8,290 | $ | 391,710 | |||||||||||
Credit Facility
The Company is party to a reserve-based revolving facility, as the borrower, with JPMorgan Chase Bank, N.A. (“JPMorgan”), as the administrative agent, and a syndicate of financial institutions (the “Lender Syndicate”), as lenders, that mature on November 1, 2025 (with all subsequent amendments as defined below, the “Credit Facility”).
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.
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In addition, the Company is subject to certain financial covenants under the Credit Facility, as tested on the last day of each fiscal quarter, including, without limitation, (a) a maximum ratio of the Company's consolidated indebtedness (subject to certain exclusions) to earnings before interest, income taxes, depreciation, depletion, and amortization, exploration expense, and other non-cash charges (“permitted net leverage ratio”) of 3.00 to 1 and (b) a current ratio, as defined in the agreement, inclusive of the unused commitments then available to be borrowed, to not be less than 1.00 to 1. The Company was in compliance with all covenants under the Credit Facility as of June 30, 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 “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 made under the Credit Facility using a term-specific SOFR. As a result, borrowings under the Credit Facility bear interest at a per annum rate equal to, at the option of the Company, either (i) the Alternate Base Rate (“ABR”, for ABR Revolving Credit Loans) plus the applicable margin, or (ii) the term-specific SOFR plus the applicable margin. ABR is established as a rate per annum equal to the greatest of (a) the rate of interest publicly announced by JPMorgan as its prime rate, (b) the applicable rate of interest published by the Federal Reserve Bank of New York (“NYFRB”) plus 0.5%, or (c) the term-specific SOFR plus 1.0%, subject to a 1.50% floor plus the applicable margin of 1.00% to 2.00%, based on the utilization of the Credit Facility. Term-specific SOFR is based on one-, three-, or six-month terms as selected by the Company and is subject to a 0.50% floor plus the applicable margin of 2.00% to 3.00%, based on the utilization of the Credit Facility. Interest on borrowings that bear interest at the SOFR shall be payable on the last day of the applicable interest period selected by the Company, and interest on borrowings that bear interest at the ABR shall be payable quarterly in arrears.
The following table presents the outstanding balance, total amount of letters of credit outstanding, and available borrowing capacity under the Credit Facility as of the dates indicated (in thousands):
| August 3, 2022 | June 30, 2022 | December 31, 2021 | |||||||||||||||
Revolving credit facility | $ | — | $ | — | $ | — | |||||||||||
| Letters of credit | 12,393 | 12,393 | 21,656 | ||||||||||||||
| Available borrowing capacity | 987,607 | 987,607 | 778,344 | ||||||||||||||
Total aggregate elected commitments | $ | 1,000,000 | $ | 1,000,000 | $ | 800,000 | |||||||||||
In connection with the amendments to the Credit Facility, the Company capitalized a total of approximately $11.9 million in deferred financing costs. Of the total post-amortization net capitalized amounts, (i) $7.0 million and $7.5 million are presented within the other noncurrent assets line item on the accompanying balance sheets as of June 30, 2022 and December 31, 2021, respectively, and (ii) $3.0 million and $2.7 million is presented within the prepaid expenses and other line item on the accompanying balance sheets as of June 30, 2022 and December 31, 2021, respectively.
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Interest Expense
For the three months ended June 30, 2022 and 2021, the Company incurred interest expense of $8.1 million and $3.8 million and capitalized zero and $0.6 million, respectively.
For the six months ended June 30, 2022 and 2021, the Company incurred interest expense of $17.2 million and $4.3 million and capitalized zero and $0.6 million, respectively.
NOTE 6 - COMMITMENTS AND CONTINGENCIES
Legal Proceedings
From time to time, the Company is involved in various commercial and regulatory claims, litigation, and other legal proceedings that arise in the ordinary course of its business. The Company assesses these claims in an effort to determine the degree of probability and range of possible loss for potential accrual in its consolidated financial statements. In accordance with authoritative accounting guidance, an accrual is recorded for a loss contingency when its occurrence is probable and damages can be reasonably estimated based on the most likely anticipated outcome or the minimum amount within a range of possible outcomes. Because legal proceedings are inherently unpredictable and unfavorable resolutions could occur, assessing contingencies is highly subjective and requires judgments about uncertain future events. When evaluating contingencies, the Company may be unable to provide a meaningful estimate due to a number of factors, including the procedural status of the matter in question, the presence of complex or novel legal theories, and/or the ongoing discovery and development of information important to the matters. The Company regularly reviews contingencies to determine the adequacy of its accruals and related disclosures. No claims have been made, nor is the Company aware of any material uninsured liability which the Company may have, as it relates to any environmental cleanup, restoration, or the violation of any rules or regulations.
Upon closing of the HighPoint, Extraction, and Crestone Peak mergers and Bison Acquisition, the Company assumed all obligations, whether asserted or unasserted, of HighPoint, Extraction, Crestone Peak, and Bison. As of the filing date of this report, there were no probable, material pending, or overtly threatened legal actions against the Company of which it was aware, other than the following:
Boulder County. In prior periods, there was ongoing litigation between Boulder County and Extraction which has been previously disclosed as having the potential to prevent oil and gas operations for the development of minerals contained within Boulder County, Colorado. Boulder County had initiated suit in District Court for Boulder County that was primarily a contract case, where the relevant contracts were the conservation easement over the Blue Paintbrush location, Extraction’s Surface Use Agreement for the Blue Paintbrush location, and the leases that Boulder owns within the Blue Paintbrush drilling and spacing unit. Boulder sought invalidation of these leases in the litigation. This litigation has been resolved as to all substantive issues, and the Company is awaiting final dismissal of the matter by the trial court.
In May, 2022, the Company became aware that Boulder County is alleging new legal theories and requesting termination of the leases previously at issue in the Blue Paintbrush litigation. No formal action has been initiated, but the Company intends to vigorously defend against all claims alleged by Boulder County. If an action is brought by Boulder County, an adverse outcome in any such litigation could result in the Company failing to meet its development objectives in Blue Paintbrush.
Enforcement. Disclosure of certain environmental matters is required when a governmental authority is a party to the proceedings and the proceedings involve potential monetary sanctions that the Company believes could exceed $0.3 million. The Company has received Notices of Alleged Violations (“NOAV”) from the COGCC alleging violations of various Colorado statutes and COGCC regulations governing oil and gas operations. The Company has further received notices from the Colorado Air Pollution Control Division. The Company continues to engage in discussions regarding resolution of the alleged violations. As of June 30, 2022 and December 31, 2021, the Company has accrued approximately $1.0 million associated with the NOAVs and Colorado Air Pollution Control Division notices, as they are probable and reasonably estimable.
Commitments
Firm Transportation Agreements. The Company is party to one firm pipeline transportation contract to provide a guaranteed outlet for production on an oil pipeline system. The contract requires the Company to pay minimum volume transportation charges on 12,500 barrels (“Bbl”) per day through April 2025, regardless of the amount of pipeline capacity utilized by the Company. The aggregate financial commitment fee over the remaining term was $41.4 million as of June 30, 2022. The Company expects to utilize most, if not all, of the firm capacity on the oil pipeline system.
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Minimum Volume Agreement - Oil. The Company is party to a purchase agreement to deliver fixed and determinable quantities of crude oil. Under the terms of the agreement, the Company is required to make periodic deficiency payments for any shortfalls in delivering the minimum gross volume commitment of 16,000 Bbls per day over a term ending in 2023. The aggregate financial commitment fee over the remaining term is $20.0 million as of June 30, 2022. Upon notifying the purchaser at least twelve months prior to the expiration date of the agreement, the Company may elect to extend the term of the agreement for up to additional years. The Company has not, and does not, expect to incur any deficiency payments.
Minimum Volume Agreement - Gas and Other. The Company is party to a long-term gas gathering and processing agreement (the “Gathering Agreement”) with a third-party midstream provider over a term ending in 2029 with an annual minimum volume commitment of 13.0 billion cubic feet of natural gas. The Gathering Agreement also includes a commitment to sell take-in-kind NGLs from other processing agreements of 7,500 Bbls a day through 2026 with the ability to roll forward up to a 10% shortfall in a given month to the subsequent month. The aggregate financial commitment over the remaining term is $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 two different plants over terms that end in August 2025 and July 2026. The Company’s share of these commitments requires an incremental 51.5 and 20.6 million cubic feet of natural gas (“MMcf”) per day, respectively, over a baseline volume of 65 MMcf per day for a period of seven years following the in-service dates of the plants. The Company may be required to pay a shortfall fee for any incremental volume deficiencies under these commitments. These contractual obligations can be reduced by the Company’s proportionate share of the collective volumes delivered to the plants by other incremental third-party volumes available to the midstream provider that are in excess of the total commitments. Because of the third-party producer reduction provision, we believe that the aggregate financial commitment fee over the remaining term is zero as of June 30, 2022. The Company has not, and does not, expect to incur any deficiency payments.
The Company is also party to additional individually immaterial agreements that require the Company to pay a fee associated with the minimum volumes regardless of the amount delivered. The aggregate financial commitment fee over the remaining term for these contracts was $11.7 million as of June 30, 2022.
The minimum annual payments under the these agreements for the next five years as of June 30, 2022 are presented below (in thousands):
| Firm Transportation | Minimum Volume(1) | |||||||||||||
Remainder of 2022 | $ | 7,360 | $ | 30,785 | ||||||||||
| 2023 | 14,600 | 34,533 | ||||||||||||
| 2024 | 14,640 | 25,818 | ||||||||||||
| 2025 | 4,800 | 22,610 | ||||||||||||
| 2026 | — | 20,987 | ||||||||||||
| 2027 and thereafter | — | 57,200 | ||||||||||||
| Total | $ | 41,400 | $ | 191,933 | ||||||||||
___________________________
(1)The above calculation is based on the minimum volume commitment schedule (as defined in the relevant agreement) and applicable differential fees.
Other commitments. The Company is party to a drilling commitment agreement with a third-party midstream provider such that the Company is required to drill a total of 106 horizontal wells, whereby a minimum number of wells out of the total must be drilled by a deadline occurring every two years over a period ending December 31, 2026. The drilling commitment agreement provides for, among other things, a number of specifications such as minimum consecutive days of production, well performance, and lateral length. Wells operated by others can satisfy this commitment, subject to limitations. If the Company were to fail to complete the wells by the applicable deadline, it would be in breach of the agreement and the third-party midstream provider could attempt to assert damages against Civitas and its affiliates. As of the date of filing, the Company cannot reasonably estimate how much, if any, damages will be paid.
Refer to Note 13 - Leases for lease commitments.
19
NOTE 7 - STOCK-BASED COMPENSATION
Long Term Incentive Plans
In April 2017, the Company adopted the 2017 Long Term Incentive Plan (“2017 LTIP”), which provides for the issuance of restricted stock units, performance stock units, and stock options, and reserved 2,467,430 shares of common stock. In June 2021, the Company adopted the 2021 Long Term Incentive Plan (“2021 LTIP”), which reserved an incremental 700,000 shares of common stock to those previously reserved under the 2017 LTIP. Finally, pursuant to the Extraction Merger Agreement, Civitas assumed the Extraction Equity Plan, which reserved 3,305,080 shares of common stock now issuable by Civitas. The 2017 LTIP, 2021 LTIP, and Extraction Equity Plan are collectively referred to herein as the “LTIP”.
In November 2021, the Company adopted a non-employee director compensation program (the “Director Compensation Program”), which provides that non-employee directors will receive grants of deferred stock units (“DSUs”). In connection with the adoption of the Director Compensation Program, the Company adopted a First Amendment to the 2021 LTIP that, among other things, allows the Company to determine whether dividend rights granted pursuant to the LTIP should be reinvested, paid currently or paid in accordance with the terms of an associated award.
The Company records compensation expense associated with the issuance of awards under the LTIP 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, | ||||||||||||||||||||||
| 2022 | 2021 | 2022 | 2021 | ||||||||||||||||||||
| Restricted and deferred stock units | $ | 3,917 | $ | 1,746 | $ | 9,182 | $ | 3,067 | |||||||||||||||
| Performance stock units | 2,218 | 449 | 5,043 | 740 | |||||||||||||||||||
| Total stock-based compensation | $ | 6,135 | $ | 2,195 | $ | 14,225 | $ | 3,807 | |||||||||||||||
As of June 30, 2022, unrecognized compensation expense related to the awards granted under the LTIP will be amortized through the relevant periods as follows (in thousands):
| Unrecognized Compensation Expense | Final Year of Recognition | ||||||||||
| Restricted and deferred stock units | $ | 23,595 | 2025 | ||||||||
| Performance stock units | 18,951 | 2024 | |||||||||
| Total unrecognized stock-based compensation | $ | 42,546 | |||||||||
Restricted Stock Units (“RSUs”) and Deferred Stock Units
The Company typically grants RSUs to officers, directors, and employees and DSUs to directors as part of its LTIP. Each RSU and DSU represents a right to receive one share of the Company's common stock upon settlement of the award at the end of the specified vesting period.
RSUs generally vest and settle either over a (i) one-year vesting period, with the entire grant vesting and settling on the anniversary date or (ii) three-year vesting period, with one-third of the total grant vesting and settling on each anniversary date. DSUs generally vest in quarterly installments over a one-year period following the grant date. DSUs are settled in shares of the Company's common stock upon the director’s separation of service from the Board. The Company records compensation expense associated with the issuance of RSUs and DSUs on a straight-line basis over the vesting period based on the fair value of the awards as of the date of grant within general and administrative expense. The fair value of RSUs and DSUs is equal to the closing price of the Company’s common stock on the date of the grant.
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A summary of the status and activity of non-vested RSUs and DSUs for the six months ended June 30, 2022 is presented below:
| RSUs and DSUs | Weighted-Average Grant-Date Fair Value | ||||||||||
| Non-vested, beginning of year | 815,062 | $ | 42.18 | ||||||||
| Granted | 492,002 | 50.24 | |||||||||
| Vested | (574,865) | 42.80 | |||||||||
| Forfeited | (30,399) | 41.15 | |||||||||
| Non-vested, end of year | 701,800 | $ | 47.36 | ||||||||
The 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 officers as part of its LTIP. The number of shares of the Company’s common stock issued to settle PSUs ranges from zero to two times the number of PSUs granted and is determined based on performance achievement against certain criteria over a three-year performance period. PSUs generally vest and settle on the third anniversary of the date of the grant.
Performance achievement is determined based on one to two criteria. The first criterion is based on either, or a combination of, the Company’s absolute and relative total shareholder return (“TSR”) over the performance period. Absolute TSR is determined based upon the performance of the Company's common stock over the performance period relative to the price of the Company's common stock at the grant date. For awards with a relative TSR component, the Company's absolute TSR is compared with the absolute TSRs of a group of peer companies over the performance period. The absolute TSR for the Company and each of the peer companies is determined by dividing (A) (i) the volume-weighted average share price for the last 30 trading days of the performance period, minus (ii) the volume-weighted average share price for the 30 trading days preceding the beginning of the performance period, plus (iii) dividends paid by (B) the volume-weighted average share price for the 30 trading days preceding the beginning of the performance period. The second criterion, if applicable, is based on the Company's annual return on average capital employed (“ROCE”) for each year during the three-year performance period.
The total number of PSUs granted under the LTIP was split as follows for the relevant grant years:
| 2022 | 2021 | 2020 | |||||||||||||||
| TSR | 100 | % | 100 | % | 67 | % | |||||||||||
| ROCE | — | % | — | % | 33 | % | |||||||||||
As the 2020 PSUs depend on a performance-based settlement criterion, compensation expense may be adjusted in future periods as the number of units expected to vest increases or decreases based on the Company’s expected ROCE performance.
Of the grant-date fair value, the portion of the PSUs tied to TSR performance required a stochastic process method using a Brownian Motion simulation. A stochastic process is a mathematically defined equation that can create a series of outcomes over time. These outcomes are not deterministic in nature, which means that by iterating the equations multiple times, different results will be obtained for those iterations. In the case of the PSUs tied to TSR performance, the Company could not predict with certainty the path its stock price or the stock prices of its peers would take over the performance period. By using a stochastic simulation, the Company created multiple prospective stock pathways, statistically analyzed these simulations, and ultimately made inferences regarding the most likely path the stock price would take. As such, because future stock prices are stochastic, or probabilistic with some direction in nature, the stochastic method, specifically the Brownian Motion Model, was deemed an appropriate method by which to determine the fair value of the portion of the PSUs tied to TSR performance. Significant assumptions used in this simulation include the Company’s expected volatility, risk-free interest rate based on U.S. Treasury yield curve rates with maturities consistent with the performance period, as well as the volatilities for each of the Company’s peers.
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A summary of the status and activity of non-vested PSUs for the six months ended June 30, 2022 is presented below:
PSUs (1) | Weighted-Average Grant-Date Fair Value | ||||||||||
| Non-vested, beginning of year | 319,367 | $ | 57.58 | ||||||||
| Granted | 199,317 | 64.23 | |||||||||
| Vested | (91,523) | 32.49 | |||||||||
| Expired | (41,955) | 22.77 | |||||||||
| Non-vested, end of year | 385,206 | $ | 70.77 | ||||||||
___________________________
(1)The number of awards assumes that the associated performance condition is met at the target amount (multiplier of one). The final number of shares of the Company’s common stock issued may vary depending on the performance multiplier, which ranges from zero to two, depending on the level of satisfaction of the performance condition.
The fair value of the PSUs granted under the LTIP during the 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.
Stock options are valued using a Black-Scholes Model where expected volatility is based on an average historical volatility of a peer group selected by management over a period consistent with the expected life assumption on the grant date, the risk-free rate of return is based on the U.S. Treasury constant maturity yield on the grant date with a remaining term equal to the expected term of the awards, and the Company’s expected life of stock option awards is derived from the midpoint of the average vesting time and contractual term of the awards.
A summary of the status and activity of non-vested stock options for the six months ended June 30, 2022 is presented below:
| Stock Options | Weighted- Average Exercise Price | Weighted-Average Remaining Contractual Term (in years) | Aggregate Intrinsic Value (in thousands) | ||||||||||||||||||||
| Outstanding, beginning of year | 25,549 | $ | 34.36 | ||||||||||||||||||||
| Exercised | (6,036) | 34.36 | |||||||||||||||||||||
| Forfeited | (111) | 34.36 | |||||||||||||||||||||
| Outstanding, end of year | 19,402 | $ | 34.36 | 4.5 | $ | 348 | |||||||||||||||||
| Options outstanding and exercisable | 19,402 | $ | 34.36 | 4.5 | $ | 348 | |||||||||||||||||
The aggregate intrinsic value of options exercised during the six months ended June 30, 2022 was $0.1 million.
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NOTE 8 - FAIR VALUE MEASUREMENTS
The Company follows authoritative accounting guidance for measuring the fair value of assets and liabilities in its financial statements. This guidance defines fair value as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date. Further, this guidance establishes a hierarchy for inputs used in measuring fair value that maximizes the use of observable inputs and minimizes the use of unobservable inputs by requiring that the most observable inputs be used when available.
The fair value hierarchy is broken down into three levels based on the reliability of the inputs as follows:
Level 1: Quoted prices in active markets for identical assets or liabilities
Level 2: Quoted prices in active markets for similar assets and liabilities, quoted prices for identical or similar instruments in markets that are not active, and model-derived valuations whose inputs are observable or whose significant value drivers are observable
Level 3: Significant inputs to the valuation model are unobservable
Financial and non-financial assets and liabilities are classified based on the lowest level of input that is significant to the fair value measurement. The Company’s assessment of the significance of a particular input to the fair value measurement requires judgment and may affect the valuation of the fair value of assets and liabilities and their placement within the fair value hierarchy.
Derivatives
The Company uses Level 2 inputs to measure the fair value of oil, gas, and NGL commodity price derivatives. The fair value of the Company's commodity price derivatives is estimated using industry-standard models that contemplate various inputs including, but not limited to, the contractual price of the underlying position, current market prices, forward commodity price curves, volatility factors, time value of money, and the credit risk of both the Company and its counterparties. We validate our fair value estimate by corroborating the original source of inputs, monitoring changes in valuation methods and assumptions, and reviewing counterparty mark-to-market statements and other supporting documentation. Refer to Note 9 - Derivatives for more information regarding the Company’s derivative instruments.
The following tables present the Company’s financial assets and liabilities that were accounted for at fair value on a recurring basis as of June 30, 2022 and December 31, 2021 and their classification within the fair value hierarchy (in thousands):
| As of June 30, 2022 | |||||||||||||||||
| Level 1 | Level 2 | Level 3 | |||||||||||||||
| Derivative assets | $ | — | $ | — | $ | — | |||||||||||
| Derivative liabilities | $ | — | $ | 321,825 | $ | — | |||||||||||
| As of December 31, 2021 | |||||||||||||||||
| Level 1 | Level 2 | Level 3 | |||||||||||||||
| Derivative assets | $ | — | $ | 3,393 | $ | — | |||||||||||
| Derivative liabilities | $ | — | $ | 239,763 | $ | — | |||||||||||
Long-Term Debt
The 5.0% Senior Notes are recorded at cost, net of any unamortized deferred financing costs. As of June 30, 2022, the fair value of the 5.0% Senior Notes was $358.4 million. This fair value is based on quoted market prices, and as such, is designated as Level 1 within the fair value hierarchy. The recorded value of the Credit Facility approximates its fair value as it bears interest at a floating rate that approximates a current market rate. Please refer to Note 5 - Long-Term Debt for additional information.
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Warrants
As discussed in Note 2 - Acquisitions and Divestitures, the Company issued warrants in connection with the Extraction Merger. The warrants issued are indexed to the Company’s common stock and are required to be net share settled via a cashless exercise. The Company evaluated the warrants under authoritative accounting guidance and determined that they should be classified as equity instruments. The Company's share price traded below the exercise price of the warrants and therefore were not exercisable during the three and 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 and unproved properties are valued based on a discounted cash flow approach utilizing Level 3 inputs, including, amongst other things, reserve quantities and classification, pace of drilling plans, future commodity prices, future development and lease operating costs, and discount rates using a market-based weighted average cost of capital determined at the time of the acquisition. When estimating the fair value of unproved properties, additional risk-weighting adjustments are applied to probable and possible reserves. Net derivative liabilities assumed are valued based on Level 2 inputs similar to the Company's other commodity price derivatives.
Whenever events or circumstances indicate that the carrying value of proved properties may not be recoverable, the Company uses Level 3 inputs to measure and record impairment at fair value. There were no proved property impairments during the three and six months ended June 30, 2022 and 2021.
Impairments of Unproved Properties
Unproved properties are routinely evaluated for continued capitalization or impairment. On a quarterly basis, management assesses undeveloped leasehold costs for impairment by considering, among other things, remaining lease terms, future drilling plans and capital availability to execute such plans, commodity price outlooks, recent operational results, reservoir performance and geology, and estimated acreage value based on prices received for similar, recent acreage transactions by the Company or other market participants. During the three months ended June 30, 2022 and 2021, the Company incurred abandonment and impairment of unproved properties expense of zero and $2.2 million, respectively. During the six months ended June 30, 2022 and 2021, the Company incurred abandonment and impairment of unproved properties expense of $18.0 million and $2.2 million, respectively.
NOTE 9 - DERIVATIVES
The Company periodically enters into commodity derivative contracts to mitigate a portion of its exposure to potentially adverse market changes in commodity prices for its expected future oil, natural gas, and NGL production and the associated impact on cash flows. The Company's commodity derivative contracts consist of swap and collar arrangements as well as roll differential swaps. As of 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 does not designate its commodity derivative contracts as hedging instruments.
In a typical swap arrangement, if the agreed upon published third-party index price (“index price”) is lower than the fixed contract price at the time of settlement, the Company receives the difference between the index price and the fixed contract price. If the index price is higher than the fixed contact price at the time of settlement, the Company pays the difference between the index price and the fixed contract price.
A typical collar arrangement effectively establishes a floor and ceiling price on contracted volumes through the use of a short call and a long put (“two-way collar”). When the index price is above the ceiling price at the time of settlement, the Company pays the difference between the index price and the ceiling price. When the index price is below the floor price at the time of settlement, the Company receives the difference between the index price and floor price. When the index price is between the floor price and ceiling price, no payment or receipt occurs. A minority of our collar arrangements combine a two-way collar with a short put that holds an exercise price below the floor price (“three-way collar”). In these arrangements, when the index price is below the floor price at the time of settlement, the Company receives the difference between the index price and the floor price, capped at the difference between the floor price and the exercise price of the short put.
The Company has also entered into crude oil swap contracts to fix the differential in pricing between the NYMEX calendar month average and the physical crude oil delivery month (“Roll Differential”) in which the Company pays the periodic variable Roll Differential and receives a weighted-average fixed price differential. The weighted-average differential represents the amount of reduction to NYMEX West Texas Intermediate (“WTI”) prices for the notional volumes covered by the swap contracts.
As of June 30, 2022, the Company had entered into the following commodity price derivative contracts:
| Contract Period | ||||||||||||||||||||||||||||||||||||||
| Q3 2022 | Q4 2022 | Q1 2023 | Q2 2023 | Q3 - Q4 2023 | 2024 | |||||||||||||||||||||||||||||||||
Oil Derivatives (volumes in Bbl/day and prices in $/Bbls) | ||||||||||||||||||||||||||||||||||||||
| Swaps | ||||||||||||||||||||||||||||||||||||||
| NYMEX WTI Volumes | 10,507 | 9,538 | 457 | 448 | 364 | 479 | ||||||||||||||||||||||||||||||||
| Weighted-Average Contract Price | $ | 47.00 | $ | 46.84 | $ | 45.42 | $ | 46.29 | $ | 46.77 | $ | 53.96 | ||||||||||||||||||||||||||
| Two-Way Collars | ||||||||||||||||||||||||||||||||||||||
| NYMEX WTI Volumes | 8,296 | 7,393 | 1,054 | — | — | — | ||||||||||||||||||||||||||||||||
| 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 Volumes | 2,241 | 1,738 | 1,721 | 1,436 | 1,237 | 143 | ||||||||||||||||||||||||||||||||
| 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 Volumes | 2,000 | 2,000 | — | — | — | — | ||||||||||||||||||||||||||||||||
| 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 Volumes | 54,952 | 54,783 | 44,641 | 43,911 | 43,868 | 22,309 | ||||||||||||||||||||||||||||||||
| Weighted-Average Contract Price | $ | 2.76 | $ | 2.76 | $ | 2.51 | $ | 2.51 | $ | 2.51 | $ | 2.57 | ||||||||||||||||||||||||||
| CIG Volumes | 10,000 | 10,000 | — | — | — | — | ||||||||||||||||||||||||||||||||
| Weighted-Average Contract Price | $ | 2.13 | $ | 2.13 | $ | — | $ | — | $ | — | $ | — | ||||||||||||||||||||||||||
| Two-Way Collars | ||||||||||||||||||||||||||||||||||||||
| NYMEX HH Volumes | 81,018 | 79,148 | 9,558 | 1,563 | 1,822 | 1,033 | ||||||||||||||||||||||||||||||||
| 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 Volumes | 136 | 127 | 899 | 505 | — | 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 Volumes | 4,000 | 4,000 | — | — | — | — | ||||||||||||||||||||||||||||||||
| Weighted-Average Contract Price | $ | 20.22 | $ | 20.22 | $ | — | $ | — | $ | — | $ | — | ||||||||||||||||||||||||||
(1) The weighted-average differential represents the amount of reduction to NYMEX WTI prices for the notional volumes covered by the swap contracts.
Derivative Assets and Liabilities Fair Value
The Company’s commodity price derivatives are measured at fair value and are included in the accompanying balance sheets as derivative assets and liabilities. The following table contains a summary of all the Company’s derivative positions reported on the accompanying balance sheets as well as a reconciliation between the gross assets and liabilities and the potential effects of master netting arrangements on the fair value of the Company’s commodity derivative contracts as of June 30, 2022 and December 31, 2021 (in thousands):
| June 30, 2022 | December 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 loss presented on the accompanying statements of operations for the periods below (in thousands):
| Three Months Ended June 30, | Six Months Ended June 30, | ||||||||||||||||||||||
| 2022 | 2021 | 2022 | 2021 | ||||||||||||||||||||
| Derivative cash settlement loss: | |||||||||||||||||||||||
| Oil contracts | $ | (114,778) | $ | (18,794) | $ | (239,940) | $ | (21,616) | |||||||||||||||
| Gas contracts | (54,091) | (1,405) | (82,875) | (2,374) | |||||||||||||||||||
| NGL contracts | (12,762) | — | (25,394) | — | |||||||||||||||||||
| Total derivative cash settlement loss | (181,631) | (20,199) | (348,209) | (23,990) | |||||||||||||||||||
| Change in fair value gain (loss) | 108,981 | (53,771) | (19,934) | (73,399) | |||||||||||||||||||
| Total derivative loss | $ | (72,650) | $ | (73,970) | $ | (368,143) | $ | (97,389) | |||||||||||||||
NOTE 10 - ASSET RETIREMENT OBLIGATIONS
The Company recognizes an estimated liability for future costs associated with the abandonment of its oil and gas properties, including facilities requiring decommissioning. A liability for the fair value of an asset retirement obligation and corresponding increase to the carrying value of the related long-lived asset are recorded at the time a well is drilled or acquired, or a facility is constructed. The increase in carrying value is included in the proved properties line item in the accompanying balance sheets. The Company depletes the amount added to proved properties and recognizes expense in connection with the accretion of the discounted liability over the remaining estimated economic lives of the respective long-lived assets. Cash paid to settle asset retirement obligations is included in the cash flows from operating activities section of the accompanying statements of cash flows.
The Company’s estimated asset retirement obligation liability is based on historical experience plugging and abandoning wells, estimated economic lives, estimated plugging and abandonment cost, and regulatory requirements. The liability is discounted using the credit-adjusted risk-free rate estimated at the time the liability is incurred or revised.
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A roll-forward of the Company's asset retirement obligation is as follows (in thousands):
| Amount | |||||
Balance as of December 31, 2021 | $ | 225,315 | |||
| Additional liabilities incurred | 2,072 | ||||
| Accretion expense | 8,102 | ||||
| Liabilities settled | (8,385) | ||||
Balance as of June 30, 2022 | $ | 227,104 | |||
| Current portion | 24,000 | ||||
| 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, one share of the Company's common stock. The number of potentially dilutive shares related to unvested RSUs and DSUs is based on the number of shares, if any, that would be issuable at the end of the respective reporting period, assuming that date was the end of the vesting period. The Company issues PSUs, which represent the right to receive, upon settlement of the PSUs, a number of shares of the Company's common stock that ranges from zero to two times the number of PSUs granted on the award date. The number of potentially dilutive shares related to PSUs is based on the number of shares, if any, that would be issuable at the end of the respective reporting period, assuming that date was the end of the performance period applicable to such PSUs. The Company has also issued stock options and warrants, which both represent the right to purchase the Company's common stock at a specified exercise price. The number of potentially dilutive shares related to the stock options and warrants is based on the number of shares, if any, that would be exercisable at the end of the respective reporting period, assuming the date was the end of such stock options' or warrants' term. Stock options and warrants are only dilutive when the average price of the common stock during the period exceeds the exercise price. Please refer to Note 7 - Stock-Based Compensation for additional discussion.
The following table sets forth the calculations of basic and diluted net income (loss) per common share (in thousands, except per share amounts):
| Three Months Ended June 30, | Six Months Ended June 30, | ||||||||||||||||||||||
| 2022 | 2021 | 2022 | 2021 | ||||||||||||||||||||
| Net income (loss) | $ | 468,821 | $ | (25,319) | $ | 560,460 | $ | (25,438) | |||||||||||||||
| Basic net income (loss) per common share | $ | 5.52 | $ | (0.83) | $ | 6.60 | $ | (0.99) | |||||||||||||||
| Diluted net income (loss) per common share | $ | 5.48 | $ | (0.83) | $ | 6.56 | $ | (0.99) | |||||||||||||||
| Weighted-average shares outstanding - basic | 84,993 | 30,655 | 84,917 | 25,774 | |||||||||||||||||||
| Add: dilutive effect of contingent stock awards | 561 | — | 536 | — | |||||||||||||||||||
| Weighted-average shares outstanding - diluted | 85,554 | 30,655 | 85,453 | 25,774 | |||||||||||||||||||
There were 59,161 and 747,678 shares that were anti-dilutive for the three months ended June 30, 2022 and 2021, respectively. There were 30,822 and 777,564 shares that were anti-dilutive for the six months ended June 30, 2022 and 2021, respectively.
The exercise price of the Company's warrants was in excess of the Company's stock price during the three and six months ended June 30, 2022; therefore, they were excluded from the earnings per share calculation.
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NOTE 12 - INCOME TAXES
Deferred tax assets and liabilities are measured by applying the provisions of enacted tax laws to determine the amount of taxes payable or refundable currently or in future years related to cumulative temporary differences between the tax basis of assets and liabilities and amounts reported in the accompanying balance sheets. The tax effect of the net change in the cumulative temporary differences during each period in the deferred tax assets and liabilities determines the periodic provision for deferred taxes.
The following table outlines the Federal net operating loss (“NOL”) carryforwards acquired and deferred tax assets and liabilities recorded as a result of the mergers that closed in 2021 (in millions):
| HighPoint Merger | Extraction Merger | Crestone Peak Merger | |||||||||||||||
| Federal NOL carryforwards | $ | 219.0 | $ | 479.9 | $ | 555.7 | |||||||||||
| Deferred tax asset (liability) | $ | 110.5 | $ | 49.2 | $ | (125.1) | |||||||||||
| Valuation allowance | (48.1) | — | — | ||||||||||||||
| Net | $ | 62.4 | $ | 49.2 | $ | (125.1) | |||||||||||
The Company assesses the recoverability of its deferred tax assets each period by considering whether it is more likely than not that all or a portion of the deferred tax assets will be realized. In making such determination, the Company considers all available (both positive and negative) evidence, including future reversals of temporary differences, tax-planning strategies, projected future taxable income, and results of operations. As a result of the HighPoint Merger, the Company recorded a valuation allowance of $48.1 million during 2021 against certain acquired net operating losses and other tax attributes due to the limitation on realizability caused by the change of ownership provisions of Section 382 of the Code. The net deferred tax liability as of June 30, 2022 was $107.9 million, and the net deferred tax asset as of December 31, 2021 was $22.3 million. Additionally, income tax payable under current liabilities as of 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, equity-based compensation, and other permanent differences including bargain purchase gain. During the three 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, respectively. During the six months ended June 30, 2022 and 2021, the Company recorded income tax expense of $175.8 million and income tax benefit of $10.4 million, respectively.
The Company had no unrecognized tax benefits as of June 30, 2022 and December 31, 2021. The Company's management does not believe that there are any new items or changes in facts or judgments that would impact the Company's tax position taken thus far in 2022.
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NOTE 13 - LEASES
The Company’s right-of-use assets and lease liabilities are recognized on the accompanying balance sheets based on the present value of the expected lease payments over the lease term. The following table summarizes the asset classes of the Company's operating leases (in thousands):
| June 30, 2022 | December 31, 2021 | |||||||||||||
| Operating Leases | ||||||||||||||
Field equipment(1) | $ | 22,608 | $ | 29,312 | ||||||||||
| Corporate leases | 8,024 | 9,484 | ||||||||||||
| Vehicles | 855 | 1,089 | ||||||||||||
| $ | 31,487 | $ | 39,885 | |||||||||||
Field equipment(1) | $ | 22,608 | $ | 29,312 | ||||||||||
| Corporate leases | 8,565 | 9,870 | ||||||||||||
| Vehicles | 855 | 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 | ||||||
| 2023 | 13,523 | |||||||
| 2024 | 5,414 | |||||||
| 2025 | 1,742 | |||||||
| 2026 | 1,207 | |||||||
| Thereafter | 1,587 | |||||||
| Total lease payments | 33,683 | |||||||
| 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.
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Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations.
The following discussion and analysis of our financial condition and results of operations should be read in conjunction with “Management’s Discussion and Analysis of Financial Condition and Results of Operations” contained in our 2021 Form 10-K, as well as the unaudited condensed consolidated financial statements and notes thereto included in this Quarterly Report on Form 10-Q.
Executive Summary
We are an independent Denver-based exploration and production company focused on the acquisition, development, and production of oil and associated liquids-rich natural gas in the Rocky Mountain region, primarily in the Wattenberg Field of the DJ Basin of Colorado. We believe our acreage in the DJ Basin has been significantly delineated by our own drilling success and by the success of offset operators, providing confidence that our inventory is repeatable and will continue to generate economic returns. The majority of our revenues are generated through the sale of oil, natural gas, and natural gas liquids production.
The Company’s primary objective is to maximize shareholder returns by responsibly developing our oil and natural gas resources. Key aspects of our strategy include multi-well pad development across our leasehold, continuous safety improvement, strict adherence to health and safety regulations, environmental stewardship, disciplined approach to acquisitions and divestitures and capital allocation, and prudent risk management.
Financial and Operating Results
Our financial and operational results include:
•Crude oil equivalent sales volumes increased 314% for the three months ended June 30, 2022 when compared to the same period during 2021 primarily due to the Extraction and Crestone Peak mergers as well as the Bison Acquisition;
•General and administrative expense per barrel of oil equivalent (“Boe”) decreased by 41% for the three months ended June 30, 2022 when compared to the same period during 2021 due to the synergies achieved through the Extraction and Crestone Peak mergers as well as the Bison Acquisition;
•Lease operating expense per Boe decreased by 11% for the three months ended June 30, 2022 when compared to the same period during 2021;
•Total liquidity was $1.4 billion at June 30, 2022, consisting of cash on hand plus funds available under our Credit Facility, after giving effect to an aggregate of $12.4 million of undrawn letters of credit. Please refer to Liquidity and Capital Resources below for additional discussion;
•Cash dividends of $116.2 million, or $1.3625 per share, declared and paid during the three months ended June 30, 2022;
•Cash flows provided by operating activities for the six months ended June 30, 2022 were $1.3 billion, as compared to $79.6 million during the six months ended June 30, 2021. Please refer to Liquidity and Capital Resources below for additional discussion; and
•Capital expenditures, inclusive of accruals, were $473.1 million during the six months ended June 30, 2022, of which $39.8 million represents land and midstream capital expenditures.
Midstream Assets
The Company's midstream assets provide reliable gathering, treating, and storage for the Company’s operated production while reducing facility site footprints, leading to more cost-efficient operations and reduced emissions and surface disturbance per Boe produced. Additionally, this infrastructure helps ensure that the Company's production is not constrained by any single midstream service provider.
The net book value of the Company's midstream assets was $303.9 million as of June 30, 2022.
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Current Events and Outlook
Oil and natural gas prices continue to be impacted by the efforts to contain COVID-19, uncertainty regarding the continued pace of economic recovery, and changes to OPEC+ production levels. In addition, Russia’s invasion of Ukraine has led to regional instability, Although Russian export volumes of oil and gas have been only modestly impacted so far, uncertainty regarding potential future impacts of sanctions and buyer aversion to Russian hydrocarbons presents significant risk to future supply and demand balances. 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, and NGL prices. WTI oil prices have recovered to pre-pandemic levels, averaging approximately $101 per Bbl during the first half of 2022. With the current shortage of other sources of energy, and the economic growth associated with what appears to be a global emergence from the pandemic, the demand for and price of oil has increased. Although this demand outlook is expected to underpin oil prices, in light of uncertainty associated with recovering oil demand, future monetary policy, and governmental policies aimed at transitions toward lower carbon energy, we cannot predict any future volatility in or levels of commodity prices or demand for crude oil.
On April 1, 2021, we acquired HighPoint, and on November 1, 2021, we merged with Extraction and Crestone Peak. Additionally, on March 1, 2022, we acquired Bison. The Company believes it has successfully integrated the operations, production, and accounting databases derived from each of these mergers and acquisitions.
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 have 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 will drill approximately 190 and complete approximately 160 gross operated wells. Additionally, our land, midstream, and other capital activity budget was updated to $80 million to $100 million.
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Results of Operations
The following table summarizes our product revenues, sales volumes, and average sales prices for the periods indicated:
| Three Months Ended June 30, | |||||||||||||||||||||||
| 2022 | 2021 | Change | Percent Change | ||||||||||||||||||||
| Revenues (in thousands): | |||||||||||||||||||||||
Crude oil sales(1) | $ | 778,218 | $ | 115,923 | $ | 662,295 | 571 | % | |||||||||||||||
Natural gas sales(2) | 205,298 | 14,778 | 190,520 | 1,289 | % | ||||||||||||||||||
| NGL sales | 167,266 | 24,777 | 142,489 | 575 | % | ||||||||||||||||||
| Product revenue | $ | 1,150,782 | $ | 155,478 | $ | 995,304 | 640 | % | |||||||||||||||
| Sales Volumes: | |||||||||||||||||||||||
| Crude oil (MBbls) | 7,308.4 | 1,905.2 | 5,403.2 | 284 | % | ||||||||||||||||||
| Natural gas (MMcf) | 28,903.5 | 6,405.6 | 22,497.9 | 351 | % | ||||||||||||||||||
| NGL (MBbls) | 3,819.6 | 878.6 | 2,941.0 | 335 | % | ||||||||||||||||||
Crude oil equivalent (MBoe)(3) | 15,945.3 | 3,851.4 | 12,093.9 | 314 | % | ||||||||||||||||||
Average Sales Prices (before derivatives)(4): | |||||||||||||||||||||||
| Crude oil (per Bbl) | $ | 106.48 | $ | 60.85 | $ | 45.63 | 75 | % | |||||||||||||||
| Natural gas (per Mcf) | $ | 7.10 | $ | 2.31 | $ | 4.79 | 207 | % | |||||||||||||||
| NGL (per Bbl) | $ | 43.79 | $ | 28.20 | $ | 15.59 | 55 | % | |||||||||||||||
Crude oil equivalent (per Boe)(3) | $ | 72.17 | $ | 40.37 | $ | 31.80 | 79 | % | |||||||||||||||
Average Sales Prices (after derivatives)(4): | |||||||||||||||||||||||
| Crude oil (per Bbl) | $ | 90.78 | $ | 50.98 | $ | 39.80 | 78 | % | |||||||||||||||
| Natural gas (per Mcf) | $ | 5.23 | $ | 2.09 | $ | 3.14 | 150 | % | |||||||||||||||
| NGL (per Bbl) | $ | 40.45 | $ | 28.20 | $ | 12.25 | 43 | % | |||||||||||||||
Crude oil equivalent (per Boe)(3) | $ | 60.78 | $ | 35.12 | $ | 25.66 | 73 | % | |||||||||||||||
_____________________________
(1)Crude oil sales excludes $0.1 million and $0.2 million of oil transportation revenues from third parties, which do not have associated sales volumes, for the three months ended June 30, 2022 and 2021, respectively.
(2)Natural gas sales excludes $0.5 million and $0.4 million of gas gathering revenues from third parties, which do not have associated sales volumes, for the three months ended June 30, 2022 and 2021, respectively.
(3)Determined using the ratio of 6 thousand cubic feet (“Mcf”) of natural gas to 1 Bbl of crude oil.
(4)Derivatives economically hedge the price we receive for oil, natural gas, and NGL. For the three months ended June 30, 2022, the derivative cash settlement loss for oil, natural 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 was $18.8 million and $1.4 million, respectively. Please refer to Note 9 - Derivatives under Part I, Item 1 of this report for additional disclosures.
Product revenues increased by 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. The increase was largely due to a 314% increase in sales volumes and a $31.80, or 79%, increase in oil equivalent pricing, excluding the impact of derivatives. The increase in sales volumes is due to the Extraction and Crestone Peak mergers that closed on November 1, 2021, and the Bison Acquisition that closed on March 1, 2022. Additionally, we turned 126 gross wells to sales during the twelve-month period ending June 30, 2022.
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The following table summarizes our operating expenses for the periods indicated (in thousands, except per Boe amounts):
| Three Months Ended June 30, | |||||||||||||||||||||||
| 2022 | 2021 | Change | Percent Change | ||||||||||||||||||||
| Operating Expenses: | |||||||||||||||||||||||
| Lease operating expense | $ | 41,877 | $ | 11,358 | $ | 30,519 | 269 | % | |||||||||||||||
| Midstream operating expense | 7,469 | 4,246 | 3,223 | 76 | % | ||||||||||||||||||
| Gathering, transportation, and processing | 79,519 | 13,721 | 65,798 | 480 | % | ||||||||||||||||||
| Severance and ad valorem taxes | 85,870 | 9,813 | 76,057 | 775 | % | ||||||||||||||||||
| Exploration | 1,553 | 3,547 | (1,994) | (56) | % | ||||||||||||||||||
| Depreciation, depletion, and amortization | 204,519 | 35,006 | 169,513 | 484 | % | ||||||||||||||||||
| Abandonment and impairment of unproved properties | — | 2,215 | (2,215) | (100) | % | ||||||||||||||||||
| Unused commitments | 1,731 | 4,328 | (2,597) | (60) | % | ||||||||||||||||||
| Bad debt expense | 4 | — | 4 | 100 | % | ||||||||||||||||||
| Merger transaction costs | 1,418 | 18,246 | (16,828) | (92) | % | ||||||||||||||||||
| General and administrative expense | 29,666 | 12,144 | 17,522 | 144 | % | ||||||||||||||||||
| Operating expenses | $ | 453,626 | $ | 114,624 | $ | 339,002 | 296 | % | |||||||||||||||
| Selected Costs ($ per Boe): | |||||||||||||||||||||||
| Lease operating expense | $ | 2.63 | $ | 2.95 | $ | (0.32) | (11) | % | |||||||||||||||
| Midstream operating expense | 0.47 | 1.10 | (0.63) | (57) | % | ||||||||||||||||||
| Gathering, transportation, and processing | 4.99 | 3.56 | 1.43 | 40 | % | ||||||||||||||||||
| Severance and ad valorem taxes | 5.39 | 2.55 | 2.84 | 111 | % | ||||||||||||||||||
| Exploration | 0.10 | 0.92 | (0.82) | (89) | % | ||||||||||||||||||
| Depreciation, depletion, and amortization | 12.83 | 9.09 | 3.74 | 41 | % | ||||||||||||||||||
| Abandonment and impairment of unproved properties | — | 0.58 | (0.58) | (100) | % | ||||||||||||||||||
| Unused commitments | 0.11 | 1.12 | (1.01) | (90) | % | ||||||||||||||||||
| Bad debt expense | — | — | — | — | % | ||||||||||||||||||
| Merger transaction costs | 0.09 | 4.74 | (4.65) | (98) | % | ||||||||||||||||||
| General and administrative expense | 1.86 | 3.15 | (1.29) | (41) | % | ||||||||||||||||||
| Operating expenses | $ | 28.47 | $ | 29.76 | $ | (1.29) | (4) | % | |||||||||||||||
Lease operating expense. Our lease operating expense increased $30.5 million, or 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, and decreased 11% on an equivalent basis per Boe. Lease operating expense increased on an aggregate basis as a result of the Extraction and Crestone Peak mergers as well as the Bison Acquisition. Lease operating expense per Boe decreased as a result of the synergies achieved through the aforementioned mergers.
Midstream operating expense. Our midstream operating expense increased $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, and decreased 57% on an equivalent basis per Boe. Midstream operating expense increased on an aggregate basis due to the acquisition of certain midstream assets through the Crestone Peak Merger. Conversely, while certain midstream operating expenses correlate to sales volumes, the majority of the costs, such as compression, are fixed and thereby result in a decrease in midstream operating expense per Boe period over period.
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Gathering, transportation, and processing. Gathering, transportation, and processing expense increased $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, and increased 40% on an equivalent basis per Boe. Sales volumes have a direct correlation to gathering, transportation, and processing expense and increased 314% during the comparable periods. Additionally, we are party to a number of value-based percentage of proceeds sales contracts, which track solely with natural gas and NGL pricing and thereby have further contributed to the increase in gathering, transportation, and processing expense. Finally, the Company continually monitors for the best sales volumes outlet and thereby incurred increased gathering, transportation, and processing expense during the three months ended 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, and increased 111% on an equivalent basis per Boe. Severance and ad valorem taxes primarily correlate to revenues, which increased by 640% for the three months ended June 30, 2022 when compared to the same period in 2021. Additionally, through the Extraction and Crestone Peak mergers, we now operate in certain taxing districts with incrementally higher severance and ad valorem tax rates that are thereby contributing to the aggregate increase in severance and ad valorem taxes.
Depreciation, depletion, and amortization. Our depreciation, depletion, and amortization expense increased $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, and increased 41% on an equivalent basis per Boe. The increase in depreciation, depletion, and amortization expense is the result of (i) a $4.5 billion increase in the depletable property base primarily due to the Extraction and Crestone Peak mergers as well as the Bison Acquisition and (ii) a 314% increase in production between the comparable periods.
Abandonment and impairment of unproved properties. During the three months ended June 30, 2022 and 2021, we incurred zero and $2.2 million, respectively, in abandonment and impairment of unproved properties 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, 2022, we incurred $1.7 million in unused commitments primarily due to certain deficiency payments incurred under a minimum volume crude oil and a minimum volume water commitment. During the three months ended June 30, 2021, we incurred $4.3 million in unused commitments primarily due to the assumption of two firm natural gas pipeline transportation contracts in the HighPoint Merger to provide a guaranteed outlet for production from properties HighPoint had previously sold. Both firm transportation contracts, which expired on July 31, 2021, required us to pay transportation charges regardless of the amount of pipeline capacity utilized.
Merger transaction costs. During the three months ended 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 general and administrative expense increased $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, and decreased 41% on an equivalent basis per Boe. The primary drivers of the aggregate increase relate to an increase in salaries, benefits, and stock compensation expense associated with the Extraction and Crestone Peak mergers. General and administrative expense per Boe decreased due to oil equivalent sales volumes being 314% higher during the three months ended June 30, 2022 as compared to the same period in 2021.
Derivative loss. Our derivative loss for the three months ended June 30, 2022 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. Please refer to Note 9 - Derivatives under Part I, Item 1 of this report for additional discussion.
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Interest expense. Our interest expense for the three months ended June 30, 2022 and 2021 was $8.1 million and $3.2 million, respectively. Average debt outstanding for the three months ended June 30, 2022 and 2021 was $443.4 million and $123.2 million, respectively. The components of interest expense for the periods presented are as follows (in thousands):
| Three Months Ended June 30, | |||||||||||
| 2022 | 2021 | ||||||||||
| Senior Notes | $ | 5,646 | $ | 1,875 | |||||||
| Credit Facility | 116 | 1,160 | |||||||||
| Commitment fees under the Credit Facility | 1,179 | 329 | |||||||||
| Letter of credit fees under the Credit Facility | 73 | — | |||||||||
| Amortization of deferred financing costs | 1,102 | 433 | |||||||||
| Capitalized interest | — | (556) | |||||||||
| Total interest expense | $ | 8,116 | $ | 3,241 | |||||||
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The following table summarizes our product revenues, sales volumes, and average sales prices for the periods indicated:
| Six Months Ended June 30, | |||||||||||||||||||||||
| 2022 | 2021 | Change | Percent 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 sales | 322,413 | 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 $0.6 million and $0.5 million of oil transportation revenues from third parties, which do not have associated sales volumes, for the six months ended June 30, 2022 and 2021, respectively.
(2)Natural gas sales excludes $1.3 million and $1.2 million of gas gathering revenues from third parties, which do not have associated sales volumes, for the six months ended June 30, 2022 and 2021, respectively.
(3)Determined using the ratio of 6 Mcf of natural gas to 1 Bbl of crude oil.
(4)Derivatives economically hedge the price we receive for oil, natural gas, and NGL. For the six months ended June 30, 2022, the derivative cash settlement loss for oil, natural 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 was $21.6 million and $2.4 million, respectively. Please refer to Note 9 - Derivatives under Part I, Item 1 of this report for additional disclosures.
Product revenues increased by 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. The increase was largely due to a 428% increase in sales volumes and a $25.12, or 63%, increase in oil equivalent pricing, excluding the impact of derivatives. The increase in sales volumes is due to the HighPoint Merger that closed on April 1, 2021, the Extraction and Crestone Peak mergers that closed on November 1, 2021, and the Bison Acquisition that closed on March 1, 2022. Additionally, we turned 126 gross wells to sales during the twelve-month period ending June 30, 2022.
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The following table summarizes our operating expenses for the periods indicated (in thousands, except per Boe amounts):
| Six Months Ended June 30, | |||||||||||||||||||||||
| 2022 | 2021 | Change | Percent Change | ||||||||||||||||||||
| Operating Expenses: | |||||||||||||||||||||||
| Lease operating expense | $ | 77,896 | $ | 17,089 | $ | 60,807 | 356 | % | |||||||||||||||
| Midstream operating expense | 13,181 | 8,151 | 5,030 | 62 | % | ||||||||||||||||||
| Gathering, transportation, and processing | 129,922 | 18,688 | 111,234 | 595 | % | ||||||||||||||||||
| Severance and ad valorem taxes | 149,174 | 14,417 | 134,757 | 935 | % | ||||||||||||||||||
| Exploration | 2,081 | 3,643 | (1,562) | (43) | % | ||||||||||||||||||
| Depreciation, depletion, and amortization | 389,379 | 53,829 | 335,550 | 623 | % | ||||||||||||||||||
| Abandonment and impairment of unproved properties | 17,975 | 2,215 | 15,760 | 712 | % | ||||||||||||||||||
| Unused commitments | 2,507 | 4,328 | (1,821) | (42) | % | ||||||||||||||||||
| Bad debt expense | 4 | — | 4 | 100 | % | ||||||||||||||||||
| Merger transaction costs | 21,952 | 21,541 | 411 | 2 | % | ||||||||||||||||||
| General and administrative expense | 65,386 | 21,395 | 43,991 | 206 | % | ||||||||||||||||||
| Operating expenses | $ | 869,457 | $ | 165,296 | $ | 704,161 | 426 | % | |||||||||||||||
| Selected Costs ($ per Boe): | |||||||||||||||||||||||
| Lease operating expense | $ | 2.57 | $ | 2.98 | $ | (0.41) | (14) | % | |||||||||||||||
| Midstream operating expense | 0.44 | 1.42 | (0.98) | (69) | % | ||||||||||||||||||
| Gathering, transportation, and processing | 4.29 | 3.26 | 1.03 | 32 | % | ||||||||||||||||||
| Severance and ad valorem taxes | 4.93 | 2.52 | 2.41 | 96 | % | ||||||||||||||||||
| Exploration | 0.07 | 0.64 | (0.57) | (89) | % | ||||||||||||||||||
| Depreciation, depletion, and amortization | 12.87 | 9.40 | 3.47 | 37 | % | ||||||||||||||||||
| Abandonment and impairment of unproved properties | 0.59 | 0.39 | 0.20 | 51 | % | ||||||||||||||||||
| Unused commitments | 0.08 | 0.76 | (0.68) | (89) | % | ||||||||||||||||||
| Bad debt expense | — | — | — | — | % | ||||||||||||||||||
| Merger transaction costs | 0.73 | 3.76 | (3.03) | (81) | % | ||||||||||||||||||
| General and administrative expense | 2.16 | 3.74 | (1.58) | (42) | % | ||||||||||||||||||
| Operating expenses | $ | 28.73 | $ | 28.87 | $ | (0.14) | — | % | |||||||||||||||
Lease operating expense. Our lease operating expense increased $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 decreased 14% on an equivalent basis per Boe. Lease operating expense increased on an aggregate basis as a result of the HighPoint, Extraction, and Crestone Peak mergers as well as the Bison Acquisition. Lease operating expense per Boe decreased as a result of the synergies achieved through the aforementioned mergers.
Midstream operating expense. Our midstream operating expense increased $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, and decreased 69% on an equivalent basis per Boe. Midstream operating expense increased on an aggregate basis due to the acquisition of certain midstream assets through the HighPoint and Crestone Peak mergers. Conversely, while certain midstream operating expenses correlate to sales volumes, the majority of the costs, such as compression, are fixed and thereby result in a decrease in midstream operating expense per Boe period over period.
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Gathering, transportation, and processing. Gathering, transportation, and processing expense increased $111.2 million, or 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, and increased 32% on an equivalent basis per Boe. Sales volumes have a direct correlation to gathering, transportation, and processing expense and increased 428% during the comparable periods. Additionally, we are party to a number of value-based percentage of proceeds sales contracts, which track solely with natural gas and NGL pricing and thereby have further contributed to the increase in gathering, transportation, and processing expense. Finally, the Company continually monitors for the best sales volumes outlet and thereby incurred increased gathering, transportation, and processing expense during the six 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 $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, and increased 96% on an equivalent basis per Boe. Severance and ad valorem taxes primarily correlate to revenues, which increased by 761% for the six months ended June 30, 2022 when compared to the same period in 2021. Additionally, through the Extraction and Crestone Peak mergers, we now operate in certain taxing districts with incrementally higher severance and ad valorem tax rates that are thereby contributing to the aggregate increase in severance and ad valorem taxes.
Depreciation, depletion, and amortization. Our depreciation, depletion, and amortization expense increased $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, and increased 37% on an equivalent basis per Boe. The increase in depreciation, depletion, and amortization expense is the result of (i) a $4.5 billion increase in the depletable property base primarily due to the Extraction and Crestone Peak mergers as well as the Bison Acquisition and (ii) a 428% increase in production between the 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, we incurred $2.2 million in abandonment and impairment of unproved properties due to the reassessment of estimated probable and possible reserve locations based primarily upon economic viability and the expiration of non-core leases.
Unused commitments. During the six months ended June 30, 2022, we incurred $2.5 million in unused commitments primarily due to certain deficiency payments incurred under a minimum volume crude oil and a minimum volume water commitment. During the six months ended June 30, 2021, we incurred $4.3 million in unused commitments primarily due to the assumption of two firm natural gas pipeline transportation contracts in the HighPoint Merger to provide a guaranteed outlet for production from properties HighPoint had previously sold. Both firm transportation contracts, which expired on July 31, 2021, required us to pay transportation charges regardless of the amount of pipeline capacity utilized.
Merger transaction costs. During the 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 $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, and decreased 42% on an equivalent basis per Boe. The primary drivers of the aggregate increase relate to an increase in salaries, benefits, and stock compensation expense associated with the HighPoint, Extraction, and Crestone Peak mergers. General and administrative expense per Boe decreased due to oil equivalent sales volumes being 428% higher during the six months ended June 30, 2022 as compared to the same period in 2021.
Derivative loss. Our derivative loss for the six months ended June 30, 2022 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. Please refer to Note 9 - Derivatives under Part I, Item 1 of this report for additional discussion.
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Interest expense. Our interest expense for the six months ended June 30, 2022 and 2021 was $17.2 million and $3.7 million, respectively. Average debt outstanding for the six months ended June 30, 2022 and 2021 was $471.5 million and $61.9 million, respectively. The components of interest expense for the periods presented are as follows (in thousands):
| Six Months Ended June 30, | |||||||||||
| 2022 | 2021 | ||||||||||
| Senior Notes | $ | 12,521 | $ | 1,875 | |||||||
| Credit Facility | 116 | 1,160 | |||||||||
| Commitment fees under the Credit Facility | 2,161 | 655 | |||||||||
| Letter of credit fees under the Credit Facility | 204 | — | |||||||||
| Amortization of deferred financing costs | 2,180 | 526 | |||||||||
| Capitalized interest | — | (556) | |||||||||
| Total interest expense | $ | 17,182 | $ | 3,660 | |||||||
Liquidity and Capital Resources
The Company's anticipated sources of liquidity include cash from operating activities, borrowings under the Credit Facility, potential proceeds from sales of assets, and potential proceeds from equity and/or debt capital markets transactions. Our cash flows from operating activities are subject to significant volatility due to changes in commodity prices, as well as variations in our production. The prices for these commodities are driven by a number of factors beyond our control, including global and regional product supply and demand, weather, product distribution, refining and processing capacity, regulatory constraints, and other supply chain dynamics, among other factors.
Although we cannot provide any assurance, we believe cash flows from operating activities and availability under our Credit Facility should be sufficient to meet our cash requirements inclusive of, but not limited to, normal operating needs, debt service obligations, planned capital expenditures and commitments for at least the next twelve months and, based on current expectations, for the long term.
As of June 30, 2022, our liquidity was $1.4 billion, consisting of cash on hand of $439.3 million and $1.0 billion of available borrowing capacity on our Credit 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, 2022. As of June 30, 2022 and as of the date of filing, we had zero outstanding on our Credit Facility.
On April 20, 2022, we entered into the Second Amendment to the A&R Credit 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 5 - Long-Term Debt under Part I, Item 1 of this report for additional information.
The following table summarizes our cash flows and other financial measures for the periods indicated (in thousands):
| Six Months Ended June 30, | |||||||||||
| 2022 | 2021 | ||||||||||
| Net cash provided by operating activities | $ | 1,254,768 | $ | 79,559 | |||||||
| Net cash used in investing activities | (733,491) | (8,029) | |||||||||
| Net cash used in financing activities | (336,480) | (71,870) | |||||||||
| Cash, cash equivalents, and restricted cash | 439,353 | 24,505 | |||||||||
| Acquisition of oil and gas properties | (303,602) | (549) | |||||||||
| Exploration and development of oil and gas properties | (467,186) | (57,269) | |||||||||
Cash flows provided by operating activities
For the six months ended June 30, 2022 and 2021, the cash receipts and disbursements were attributable to our normal operating cycle. See Results of Operations above for more information on the factors driving these changes.
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Cash flows provided by (used in) investing activities
Net cash used in investing activities for the six months ended June 30, 2022 was primarily driven by $303.6 million of acquisitions of oil and gas properties, partially offset by cash acquired of $44.3 million. Additionally, we spent $467.2 million and $57.3 million on the exploration and development of oil and gas properties during the six months ended June 30, 2022 and 2021, respectively.
Cash flows used in financing activities
Net cash used in financing activities for the six months ended June 30, 2022 and 2021 was $336.5 million and $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 decrease in net payments on the Credit Facility of $55.0 million.
Non-GAAP Financial Measures
Adjusted EBITDAX represents earnings before interest, income taxes, depreciation, depletion, and amortization, exploration expense, and other non-cash and non-recurring charges. Adjusted EBITDAX excludes certain items that we believe affect the comparability of operating results and can exclude items that are generally non-recurring in nature or whose timing and/or amount cannot be reasonably estimated. Adjusted EBITDAX is a non-GAAP measure that we present because we believe it provides useful additional information to investors and analysts, as a performance measure, for analysis of our ability to internally generate funds for exploration, development, acquisitions, and to service debt. We are also subject to financial covenants under our Credit Facility based on adjusted EBITDAX ratios. See Liquidity and Capital Resources 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, net cash provided by operating activities, or other profitability or liquidity measures prepared under GAAP. Because adjusted EBITDAX excludes some, but not all items that affect net income and may vary among companies, the adjusted EBITDAX amounts presented may not be comparable to similar metrics of other companies.
The following table presents a reconciliation of the GAAP financial measure of net income to the non-GAAP financial measure of adjusted EBITDAX (in thousands):
| Three Months Ended June 30, | Six Months Ended June 30, | ||||||||||||||||||||||
| 2022 | 2021 | 2022 | 2021 | ||||||||||||||||||||
| Net income (loss) | $ | 468,821 | $ | (25,319) | $ | 560,460 | $ | (25,438) | |||||||||||||||
| Exploration | 1,553 | 3,547 | 2,081 | 3,643 | |||||||||||||||||||
| Depreciation, depletion, and amortization | 204,519 | 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 costs | 1,418 | 18,246 | 21,952 | 21,541 | |||||||||||||||||||
| Unused commitments | 1,731 | 4,328 | 2,507 | 4,328 | |||||||||||||||||||
| Gain on property transactions, net | — | — | (16,797) | — | |||||||||||||||||||
| Interest expense | 8,116 | 3,241 | 17,182 | 3,660 | |||||||||||||||||||
| Derivative loss | 72,650 | 73,970 | 368,143 | 97,389 | |||||||||||||||||||
| Derivative cash settlements loss | (181,631) | (20,199) | (348,209) | (23,990) | |||||||||||||||||||
| Income tax (benefit) expense | 152,464 | (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 1 - Summary of Significant Accounting Policies, Basis of Presentation under Part I, Item 1 of this report and Note 2 - Basis of Presentation in the 2021 Form 10-K for any recently issued or adopted accounting standards.
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Critical Accounting Estimates
Information regarding our critical accounting estimates is contained in Part II, Item 7 of our 2021 Form 10-K. During the three months ended 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 2021 Form 10-K in our obligations and commitments, other than what is disclosed within Note 6 - Commitments and Contingencies and Note 13 - Leases under Part I, Item 1 of this report.
Item 3. Quantitative and Qualitative Disclosures About Market Risk.
Oil, Natural Gas, and NGL Price Risk
Our financial condition, results of operations, and capital resources are highly dependent upon the prevailing market prices of oil, natural gas, and NGL. These commodity prices are subject to wide fluctuations and market uncertainties due to a variety of factors that are beyond our control. Factors influencing oil, natural gas, and NGL prices include the level of global demand for oil, natural gas, and NGL, the global supply of oil, natural gas, the establishment of and compliance with production quotas by oil exporting countries, weather conditions which determine the demand for natural gas, the price and availability of alternative fuels, local and global politics, and overall economic conditions. It is impossible to predict future oil, natural gas, and NGL prices with any degree of certainty. Sustained weakness in oil, natural gas, and NGL prices may adversely affect our financial condition and results of operations, and may also reduce the amount of oil and natural gas reserves that we can produce economically. Any reduction in our oil and natural gas reserves, including reductions due to price fluctuations, can have an adverse effect on our ability to obtain capital for our exploration and development activities. Similarly, any improvements in oil, natural gas, and NGL prices can have a favorable impact on our financial condition, results of operations, and capital resources.
Commodity Price Derivative Contracts
Our primary commodity risk management objective is to protect the Company’s balance sheet via the reduction in cash flow volatility. We enter into derivative contracts for oil, natural gas, and NGL using NYMEX futures or over-the-counter derivative financial instruments. The types of derivative instruments that we use include swaps, collars, and puts.
Upon settlement of a derivative contract, if the relevant market commodity price exceeds our contracted swap price, or the collar’s ceiling strike price, we are required to pay our counterparty the difference for the volume of production associated with the contract. Generally, this payment is made up to 15 business days prior to the receipt of cash payments from our customers. This could have an adverse impact on our cash flows for the period between derivative settlements and payments for revenue earned.
While we may reduce the potential negative impact of lower commodity prices, we may also be prevented from realizing the benefits of favorable price changes in the physical market.
Presently, our derivative contracts have been executed with 10 counterparties, all of which are members of our Credit Facility syndicate. We enter into contracts with counterparties whom we believe are well capitalized. However, if our counterparties fail to perform their obligations under the contracts, we could suffer financial loss. Please refer to the Note 9 - Derivatives under Part I, Item 1 of this report for summary derivative activity tables.
Interest Rates
At June 30, 2022 and on the filing date of this report, we had a zero balance on our Credit Facility. Borrowings under our Credit Facility bear interest at a fluctuating rate that is tied to an Alternate Base Rate or Secured Overnight Financing Rate, at our option. Any increases in these interest rates can have an adverse impact on our results of operations and cash flows. As of June 30, 2022 and through the filing date of this report, the Company was in compliance with all financial and non-financial covenants under the Credit Facility.
Counterparty and Customer Credit Risk
In connection with our derivatives activity, we have exposure to financial institutions in the form of derivative transactions. Presently, our derivative contracts have been executed with 10 counterparties, all of which are members of our Credit Facility syndicate. All counterparties on our derivative instruments currently in place have investment grade credit ratings.
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We are also subject to credit risk due to concentration of our oil, natural gas, and NGL receivables with certain significant customers. The inability or failure of our significant customers to meet their obligations to us or their insolvency or liquidation may adversely affect our financial results. We review the credit rating, payment history, and financial resources of our customers, but we do not require our customers to post collateral.
Marketability of Our Production
The marketability of our production depends in part upon the availability, proximity, and capacity of third-party refineries, access to regional trucking, pipeline and rail infrastructure, natural gas gathering systems, and processing facilities. We deliver crude oil, natural gas, and NGL produced through trucking services, pipelines, and rail facilities that we do not own. The lack of availability or capacity on these systems and facilities could reduce the price offered for our production or result in the shut-in of producing wells or the delay or discontinuance of development plans for properties.
A portion of our production may also be interrupted, or shut in, from time to time for numerous other reasons, including as a result of accidents, weather, field labor issues or strikes, or we might voluntarily curtail production in response to market conditions. If a substantial amount of our production is interrupted at the same time, it could adversely affect our cash flow.
Currently, there are no pipeline systems that service wells in our French Lake area of the Wattenberg Field. If neither we nor a third-party constructs the required pipeline system, we may not be able to fully test or develop our resources in French Lake.
Item 4. Controls and Procedures.
Evaluation of Disclosure Controls and Procedures
Our management, with the participation of our principal executive officer and principal financial officer, evaluated the effectiveness of our disclosure controls and procedures as of June 30, 2022. The term “disclosure controls and procedures,” as defined in Rules 13a-15(e) and 15d-15(e) under the Exchange Act, means controls and other procedures of a company that are designed to ensure that information required to be disclosed by a company in the reports that it files or submits under the Exchange Act is recorded, processed, summarized, and reported, within the time periods specified in SEC rules and forms. Disclosure controls and procedures include, without limitation, controls and procedures designed to ensure that information required to be disclosed by a company in the reports that it files or submits under the Exchange Act is accumulated and communicated to the company’s management, including its principal executive and principal financial officers and internal audit function, as appropriate, to allow timely decisions regarding required disclosure. Based on the evaluation of our disclosure controls and procedures as of June 30, 2022, our principal executive officer and principal financial officer concluded that, as of such date, our disclosure controls and procedures were effective at the reasonable assurance level.
Management recognizes that any controls and procedures, no matter how well designed and operated, can provide only reasonable assurance of achieving their objectives, and management necessarily applies its judgment in evaluating the cost-benefit relationship of possible controls and procedures. To assist management, we have established an internal audit function to verify and monitor our internal controls and procedures. The Company’s internal control system is supported by written policies and procedures, contains self-monitoring mechanisms, and is audited by the internal audit function. Appropriate actions are taken by management to correct deficiencies as they are identified.
Changes in Internal Control over Financial Reporting
There were no changes in our internal control over financial reporting identified in management’s evaluation pursuant to Rules 13a-15(d) or 15d-15(d) of the Exchange Act during the quarter ended June 30, 2022 that materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.
PART II. OTHER INFORMATION
Item 1. Legal Proceedings.
Information regarding our legal proceedings can be found in Note 6 - Commitments and Contingencies under Part I, Item 1 of this report.
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Item 1A. Risk Factors.
Our business faces many risks. Any of the risk factors discussed in this report or our other SEC filings could have a material impact on our business, financial position, or results of operations. Additional risks and uncertainties not presently known to us or that we currently believe to be immaterial may also impair our business operation. For a discussion of our potential risks and uncertainties, see the risk factors in Part I, Item 1A in our 2021 Form 10-K, together with other information in this report and other reports and materials we file with the SEC. We have identified these risk factors as important factors that could cause our actual results to differ materially from those contained in any written or oral forward-looking statements made by us or on our behalf.
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, 2022.
Issuer Purchases of Equity Securities. The following table contains information about our acquisition of equity securities during the three months ended June 30, 2022.
| Total Number of Shares | Maximum Number of | ||||||||||||||||||||||
| Total Number | Purchased as Part of | Shares that May Be | |||||||||||||||||||||
| of Shares | Average Price | Publicly Announced | Purchased Under Plans | ||||||||||||||||||||
Purchased(1) | Paid per Share | Plans or Programs | or Programs | ||||||||||||||||||||
| April 1, 2022 - April 30, 2022 | 20,408 | $ | 59.37 | — | — | ||||||||||||||||||
| May 1, 2022 - May 31, 2022 | 14,912 | $ | 64.23 | — | — | ||||||||||||||||||
| June 1, 2022 - June 30, 2022 | 5,326 | $ | 71.28 | — | — | ||||||||||||||||||
| Total | 40,646 | $ | 61.18 | — | — | ||||||||||||||||||
_________________________
(1)Represent shares that employees surrendered back to us that equaled in value the amount of taxes needed for payroll tax withholding obligations upon the vesting of restricted stock awards. These repurchases were not part of a publicly announced plan or program to repurchase shares of our common stock, nor do we have a publicly announced plan or program to repurchase shares of our common stock.
Dividend Policy. 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 and the indentures governing our senior notes restrict the payment of cash dividends on our common stock, as discussed further in Note 5 - Long-Term Debt under Part I, Item 1 of this report.
Item 3. Defaults Upon Senior Securities.
None.
Item 4. Mine Safety Disclosures.
Not applicable.
Item 5. Other Information.
None.
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Item 6. Exhibits.
Exhibit Number | Description | ||||
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| 101.INS† | XBRL Instance Document | ||||
101.SCH† | XBRL Taxonomy Extension Schema | ||||
101.CAL† | XBRL Taxonomy Extension Calculation Linkbase | ||||
101.DEF† | XBRL Taxonomy Extension Definition Linkbase | ||||
101.LAB† | XBRL Taxonomy Extension Label Linkbase | ||||
101.PRE† | XBRL Taxonomy Extension Presentation Linkbase | ||||
| 104 | Cover Page Interactive Data File (formatted as Inline XBRL and contained in Exhibit 101) | ||||
_________________________
* Management Contract or Compensatory Plan or Arrangement
† Filed or furnished herewith
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SIGNATURES
Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.
| CIVITAS RESOURCES, INC. | ||||||||||||||
| Date: | August 3, 2022 | By: | /s/ Chris Doyle | |||||||||||
| Chris Doyle | ||||||||||||||
President and Chief Executive Officer (principal executive officer) | ||||||||||||||
| By: | /s/ Marianella Foschi | |||||||||||||
| Marianella Foschi | ||||||||||||||
Chief Financial Officer (principal financial officer) | ||||||||||||||
| By: | /s/ Sandi K. Garbiso | |||||||||||||
| Sandi K. Garbiso | ||||||||||||||
Chief Accounting Officer and Treasurer (chief accounting officer) | ||||||||||||||
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