☒QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES
EXCHANGE ACT OF 1934
For the quarterly period ended September 30, 2023
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 November 3, 2023, the registrant had 93,773,847 shares of common stock outstanding.
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 those related to climate change as well as environmental, health, and safety regulations and liabilities thereunder;
•our ability to achieve, reach, or otherwise meet initiatives, plans, or ambitions with respect to environmental, social and governance matters;
•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;
•oil, natural gas, and natural gas liquid prices and factors affecting the volatility of such prices;
•the impact of 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;
•outcomes and effects of litigation, claims, and disputes;
•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;
•our ability to pursue potential future capital management activities such as share repurchases, paying dividends on our common stock at their current level or at all, or additional mechanisms to return excess capital to our stockholders;
•the impact of the loss of a single customer or any purchaser of our products;
•the timing and ability to meet certain volume commitments related to purchase and transportation agreements;
•the impact of any pandemic or other public health epidemic, including the COVID-19 pandemic;
•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 expected timetable for completing the pending Vencer Acquisition (as defined herein);
•plans and expectations with respect to the recent acquisitions and the anticipated impact of the recent acquisitions on the Company’s results of operations, financial position, future growth opportunities, reserve estimates, and competitive position;
•the results, effects, benefits, and synergies of other mergers and acquisitions, including the Vencer Acquisition; and
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, 2022 (“2022 Form 10-K”), Exhibit 99.2 to our Current Report on Form 8-K filed with the Securities and Exchange Commission (“SEC”) on June 20, 2023, and in subsequent reports we file with the SEC (including Part II, Item 1A of this report);
•declines or volatility in the prices we receive for our oil, natural gas, and natural gas liquids;
•general economic conditions, whether internationally, nationally, or in the regional and local market areas in which we do business, including any future economic downturn, the impact of continued or further inflation, disruption in the financial markets, and the availability of credit on acceptable terms;
•our ability to identify and select possible additional acquisition and disposition opportunities;
•the effects of disruption of our operations or excess supply of oil and natural gas and other effects of world health events, including the COVID-19 pandemic (including any worsening thereof), and the actions by certain oil and natural gas producing countries, including Russia;
•the ability of our customers to meet their obligations to us;
•our access to capital on acceptable terms;
•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, health, and safety regulation and regulations addressing climate change);
•environmental, health, and safety risks;
•seasonal weather conditions as well as severe weather and other natural events caused by climate change;
•lease stipulations;
•drilling and operating risks, including the risks associated with the employment of horizontal drilling and completion techniques;
•our ability to acquire adequate supplies of water for drilling and completion operations;
•availability of oilfield equipment, services, and personnel;
•exploration and development risks;
•operational interruption of centralized 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;
•unforeseen difficulties encountered in operating in new geographic areas;
•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 (including the current events related to the Israel-Palestine conflict), South America, and Russia (including the current events involving Russia and Ukraine), and other sustained military campaigns or acts of terrorism or sabotage;
•the continuing effects of the COVID-19 pandemic, including any recurrence or the worsening thereof;
•disruptions to our business due to acquisitions and other significant transactions, including the Vencer Acquisition; and
•other economic, competitive, governmental, legislative, regulatory, geopolitical, and technological factors that may negatively impact our businesses, operations, or pricing.
All forward-looking statements speak only as of the date of this report. We disclaim any obligation to update or revise these statements unless required by law, and you should not place undue reliance on these forward-looking statements. Although we believe that our plans, intentions, and expectations reflected in or suggested by the forward-looking statements we make in this report are reasonable, we can give no assurance that these plans, intentions, or expectations will be achieved. We disclose other important factors that could cause our actual results to differ materially from our expectations under “Part I, Item 1A. Risk Factors” and other sections of our 2022 Form 10-K, Exhibit 99.2 to our Current Report on Form 8-K filed with the SEC on June 20, 2023 and in subsequent reports we file with the SEC (including Part II, Item 1A of this report). These cautionary statements qualify all forward-looking statements attributable to us or persons acting on our behalf.
Property and equipment (successful efforts method):
Proved properties
12,135,971
6,774,635
Less: accumulated depreciation, depletion, and amortization
(1,939,956)
(1,214,484)
Total proved properties, net
10,196,015
5,560,151
Unproved properties
973,102
593,971
Wells in progress
535,499
407,351
Other property and equipment, net of accumulated depreciation of $9,016 in 2023 and $7,329 in 2022
63,006
49,632
Total property and equipment, net
11,767,622
6,611,105
Long-term derivative assets
1,872
794
Right-of-use assets
91,766
24,125
Other noncurrent assets
31,563
6,945
Total assets
$
12,841,568
$
7,971,399
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities:
Accounts payable and accrued expenses
$
645,214
$
295,297
Production taxes payable
431,346
258,932
Oil and natural gas revenue distribution payable
745,214
538,343
Derivative liability
126,053
46,334
Asset retirement obligations
25,557
25,557
Lease liability
41,581
13,464
Deferred revenue
4,501
—
Total current liabilities
2,019,466
1,177,927
Long-term liabilities:
Senior notes
3,049,888
393,293
Credit facility
650,000
—
Ad valorem taxes
231,472
412,650
Derivative liability
10,768
17,199
Deferred income tax liabilities, net
458,590
319,618
Asset retirement obligations
304,812
265,469
Lease liability
50,924
11,324
Deferred revenue
45,015
—
Total liabilities
6,820,935
2,597,480
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, 93,772,363 and 85,120,287 issued and outstanding as of September 30, 2023 and December 31, 2022, respectively
5,004
4,918
Additional paid-in capital
4,955,206
4,211,197
Retained earnings
1,060,423
1,157,804
Total stockholders’ equity
6,020,633
5,373,919
Total liabilities and stockholders’ equity
$
12,841,568
$
7,971,399
The accompanying notes are an integral part of these condensed consolidated financial statements.
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (UNAUDITED)
(in thousands)
Nine Months Ended September 30,
2023
2022
Cash flows from operating activities:
Net income
$
481,420
$
966,212
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, depletion, and amortization
754,558
601,449
Abandonment and impairment of unproved properties
—
17,975
Stock-based compensation
25,577
24,469
Derivative loss
120,574
358,862
Derivative cash settlement loss
(44,907)
(492,120)
Amortization of deferred financing costs
5,706
3,319
(Gain) loss on property transactions, net
254
(15,859)
Deferred income tax expense
138,972
239,766
Other, net
(409)
202
Changes in operating assets and liabilities, net
(86,173)
260,588
Net cash provided by operating activities
1,395,572
1,964,863
Cash flows from investing activities:
Acquisitions of oil and natural gas properties, net of cash acquired
(3,711,466)
(330,459)
Proceeds from sale of oil and natural gas properties
5,764
—
Exploration and development of oil and natural gas properties
(782,119)
(708,958)
Additions to other property and equipment
(1,714)
(97)
Purchases of carbon offsets
(5,864)
(7,196)
Other
(1,464)
126
Net cash used in investing activities
(4,496,863)
(1,046,584)
Cash flows from financing activities:
Proceeds from credit facility
1,120,000
100,000
Payments to credit facility
(470,000)
(100,000)
Proceeds from issuance of senior notes
2,666,250
—
Payment of deferred financing costs
(42,909)
(1,174)
Redemption of senior notes
—
(100,000)
Dividends paid
(511,031)
(370,591)
Common stock repurchased and retired
(320,398)
—
Proceeds from exercise of stock options
458
232
Payment of employee tax withholdings in exchange for the return of common stock
(13,302)
(19,062)
Principal payments on finance lease obligations
(483)
—
Net cash provided by (used in) financing activities
2,428,585
(490,595)
Net change in cash, cash equivalents, and restricted cash
(672,706)
427,684
Cash, cash equivalents, and restricted cash:
Beginning of period(1)
768,134
254,556
End of period(1)
$
95,428
$
682,240
(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”).
Please refer to Note 14 for Supplemental Disclosures of Cash Flow Information.
The accompanying notes are an integral part of these condensed consolidated financial statements.
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. Civitas is an independent exploration and production company focused on the acquisition, development, and production of oil and associated liquids-rich natural gas primarily in the Denver-Julesburg Basin in Colorado (the “DJ Basin”) and the Permian Basin in Texas and New Mexico.
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, 2022 unaudited condensed consolidated balance sheet data has been derived from the audited consolidated financial statements contained in our 2022 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 2022 Form 10-K. In connection with the preparation of the unaudited condensed consolidated financial statements, the Company evaluated events subsequent to the balance sheet date of September 30, 2023, through the filing date of this report. The results of operations for the three and nine months ended September 30, 2023 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 2022 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 October 2021, the FASB issued ASU No. 2021-08, Business Combinations: Accounting for Contract Assets and Contract Liabilities from Contracts with Customers, which requires that the acquiring entity recognize and measure contract assets and contract liabilities acquired in a business combination in accordance with Topic 606. The Company adopted this guidance effective December 15, 2022 and the adoption did not have a material impact on the accompanying unaudited condensed consolidated financial statements.
There are no other accounting standards applicable to the Company that would have a material effect on the Company’s financial statements and disclosures that have been issued but not yet adopted by the Company as of September 30, 2023, and through the filing date of this report.
NOTE 2 - ACQUISITIONS AND DIVESTITURES
All mergers and acquisitions disclosed are accounted for under the acquisition method of accounting for business combinations under ASC Topic 805, Business Combinations. Accordingly, we conduct 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 are expensed as incurred. The fair value measurements of assets acquired and liabilities assumed are based on inputs that are not observable in the market, and therefore represent Level 3 inputs. The fair values of oil and natural gas properties are measured using valuation techniques that convert future cash flows to a single discounted amount. Significant inputs to the valuation of oil and natural gas properties include estimates of reserves, future operating and development costs, future commodity prices, estimated future cash flows, and a market-based weighted-average cost of capital. These inputs require significant judgments and estimates by management at the time of the valuation.
On June 19, 2023, the Company entered into a membership interest purchase agreement (the “Hibernia Acquisition Agreement”) with Hibernia Energy III Holdings, LLC and Hibernia Energy III-B Holdings, LLC, pursuant to which the Company agreed to purchase all of the issued and outstanding equity ownership interests of Hibernia Energy III, LLC and Hibernia Energy III-B, LLC.
On August 2, 2023, the Company completed the transactions contemplated by the Hibernia Acquisition Agreement (the “Hibernia Acquisition”) for aggregate consideration of approximately $2.2 billion in cash, subject to certain customary purchase price adjustments set forth in the Hibernia Acquisition Agreement. The following table presents the preliminary purchase price allocation of the assets acquired and the liabilities assumed in the Hibernia Acquisition:
Preliminary Purchase Price Allocation (in thousands)
Assets Acquired
Cash and cash equivalents
$
30,671
Accounts receivable - oil and natural gas sales
89,766
Accounts receivable - joint interest and other
4,874
Proved properties
2,123,791
Unproved properties
115,802
Other property and equipment
520
Right-of-use assets
30,393
Total assets acquired
$
2,395,817
Liabilities Assumed
Accounts payable and accrued expenses
$
91,977
Production taxes payable
10,320
Oil and natural gas revenue distribution payable
75,267
Asset retirement obligations
8,299
Lease liability
30,393
Total liabilities assumed
216,256
Net assets acquired
$
2,179,561
The purchase price allocation for the Hibernia Acquisition is preliminary, and Civitas is continuing to assess the fair values of certain of the Hibernia assets acquired and liabilities assumed. The Company expects to finalize the purchase price allocation as soon as practicable, which will not extend beyond the one-year measurement period.
Tap Rock Acquisition
On June 19, 2023, the Company entered into a membership interest purchase agreement (the “Tap Rock Acquisition Agreement”) with Tap Rock Resources Legacy, LLC (“Tap Rock I Legacy”), Tap Rock Resources Intermediate, LLC (“Tap Rock I Intermediate” and, together with Tap Rock I Legacy, the “Tap Rock I Sellers”), Tap Rock Resources II Legacy, LLC (“Tap Rock II Legacy”), Tap Rock Resources II Intermediate, LLC (“Tap Rock II Intermediate” and, together with Tap Rock II Legacy, the “Tap Rock II Sellers”), Tap Rock NM10 Legacy Holdings, LLC (“NM10 Legacy”), and Tap Rock NM10 Holdings Intermediate, LLC (“NM10 Intermediate” and together with NM10 Legacy, the “NM10 Sellers”, and the NM10 Sellers, together with the Tap Rock I Sellers and Tap Rock II Sellers, the “Tap Rock Sellers”), solely in its capacity as “Sellers’ Representative” (as defined therein), Tap Rock I Legacy, and solely for the limited purposes set forth therein, Tap Rock Resources, LLC, pursuant to which the Company agreed to purchase all of the issued and outstanding equity ownership interests of Tap Rock AcquisitionCo, LLC, Tap Rock Resources II, LLC, and Tap Rock NM10 Holdings, LLC from the Tap Rock I Sellers, the Tap Rock II Sellers and the NM10 Sellers, respectively.
On August 2, 2023, the Company completed the transactions contemplated by the Tap Rock Acquisition Agreement (the “Tap Rock Acquisition”). The following tables present the consideration transferred and preliminary purchase price allocation of the assets acquired and the liabilities assumed in the Tap Rock Acquisition:
Consideration (in thousands, except per share amount)
Cash consideration
$
1,508,143
Shares of common stock issued
13,538,472
Closing price per share(1)
$
73.14
Equity consideration
$
990,204
Total consideration(2)
$
2,498,347
_______________________
(1)Based on the closing stock price of Civitas common stock on August 2, 2023.
(2)Subject to certain customary purchase price adjustments set forth in the Tap Rock Acquisition Agreement.
Preliminary Purchase Price Allocation (in thousands)
Assets Acquired
Cash and cash equivalents
$
6,543
Accounts receivable - oil and natural gas sales
106,255
Accounts receivable - joint interest and other
31,300
Prepaid expenses and other
22,013
Proved properties
2,377,649
Unproved properties
298,859
Other property and equipment
12,827
Right-of-use assets
626
Total assets acquired
$
2,856,072
Liabilities Assumed
Accounts payable and accrued expenses
$
179,626
Production taxes payable
15,557
Oil and natural gas revenue distribution payable
78,758
Ad valorem taxes
1,374
Asset retirement obligations
31,518
Lease liability
626
Deferred revenue
50,266
Total liabilities assumed
357,725
Net assets acquired
$
2,498,347
The purchase price allocation for the Tap Rock Acquisition is preliminary, and Civitas is continuing to assess the fair values of certain of the Tap Rock assets acquired and liabilities assumed. The Company expects to finalize the purchase price allocation as soon as practicable, which will not extend beyond the one-year measurement period.
Revenue and earnings of the acquirees
The results of operations for the Hibernia Acquisition and Tap Rock Acquisition since the closing date have been included on our condensed consolidated financial statements for the three and nine months ended September 30, 2023. The amount of revenue of Hibernia and Tap Rock included in our accompanying unaudited condensed consolidated statements of operations (“statements of operations”) was approximately $124.1 million and $182.6 million, respectively, during the three and nine months ended September 30, 2023. We determined that disclosing the amount of Hibernia and Tap Rock related earnings included in the statements of operations is impracticable as the operations from these acquisitions were integrated into the operations of the Company from the dates of each acquisition.
The following unaudited pro forma financial information (in thousands, except per share amounts) represents a summary of the condensed consolidated results of operations for the three and nine months ended September 30, 2023 and 2022, assuming the Hibernia Acquisition and Tap Rock Acquisition had been completed as of January 1, 2022. The pro forma financial information is not necessarily indicative of the results of operations that would have been achieved if the Hibernia Acquisition and Tap Rock Acquisition had been effective as of this date, or of future results, and includes certain nonrecurring pro forma adjustments that were directly related to these business combinations. Specifically, pro forma earnings were adjusted to exclude transaction costs incurred associated with these acquisitions for the three and nine months ended September 30, 2023 and include such transaction costs in pro forma earnings for the nine months ended September 30, 2022.
Three Months Ended September 30,
Nine Months Ended September 30,
2023
2022
2023
2022
Total revenue
$
1,157,615
$
1,575,493
$
3,306,345
$
4,542,055
Net income
179,307
597,835
686,951
1,413,135
Net income per common share - basic
$
1.91
$
6.06
$
7.28
$
14.35
Net income per common share - diluted
1.90
6.03
7.22
14.27
Bison Acquisition
On March 1, 2022, the Company completed the acquisition of privately held DJ Basin operator Bison Oil & Gas II, LLC for consideration of approximately $280.4 million (the “Bison Acquisition”). Net assets acquired under the purchase price allocation were $294.0 million and consequently resulted in a bargain purchase gain of $13.6 million. Because of the immateriality of the Bison Acquisition, the related revenue and earnings, supplemental pro forma financial information, and detailed purchase price allocation are not disclosed.
Transaction costs
Transaction costs related to the aforementioned acquisitions are accounted for separately from the assets acquired and liabilities assumed and are included in transaction costs in the statements of operations. The Company incurred transaction costs of $28.5 million and $1.8 million during the three months ended September 30, 2023 and 2022, respectively, and $60.1 million and $23.8 million during the nine months ended September 30, 2023 and 2022, respectively.
Oil and natural gas sales revenue presented within the accompanying statements of operations is reflective of the revenue generated from contracts with customers. Revenue attributable to each identified revenue stream is disaggregated below (in thousands):
Three Months Ended September 30, 2023
Three Months Ended September 30, 2022
DJ Basin
Permian Basin(2)
Total
DJ Basin
Permian Basin
Total
Operating net revenues:
Oil
$
583,081
$
258,595
$
841,676
$
653,548
$
—
$
653,548
Natural gas(1)
68,641
12,694
81,335
216,917
—
216,917
Natural gas liquids (“NGL”)(1)
77,502
35,403
112,905
137,486
—
137,486
Oil and natural gas sales
$
729,224
$
306,692
$
1,035,916
$
1,007,951
$
—
$
1,007,951
__________________________
(1)Includes $0.4 million and $0.4 million of deferred revenue that has been recognized during the three months ended September 30, 2023 for natural gas and NGL, respectively.
(2)Represents revenue attributable to the Hibernia Acquisition and Tap Rock Acquisition for the period from August 2, 2023 through September 30, 2023.
Nine Months Ended September 30, 2023
Nine Months Ended September 30, 2022
DJ Basin
Permian Basin(2)
Total
DJ Basin
Permian Basin
Total
Operating net revenues:
Oil
$
1,584,498
$
258,595
$
1,843,093
$
1,981,308
$
—
$
1,981,308
Natural gas(1)
217,560
12,694
230,254
535,918
—
535,918
NGL(1)
243,714
35,403
279,117
459,899
—
459,899
Oil and natural gas sales
$
2,045,772
$
306,692
$
2,352,464
$
2,977,125
$
—
$
2,977,125
__________________________
(1)Includes $0.4 million and $0.4 million of deferred revenue that has been recognized during the nine months ended September 30, 2023 for natural gas and NGL, respectively.
(2)Represents revenue attributable to the Hibernia Acquisition and Tap Rock Acquisition for the period from August 2, 2023 through September 30, 2023.
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 and natural gas sales line item on the accompanying statements of operations. Please refer to Note 1 - Summary of Significant Accounting Policies in the 2022 Form 10-K for more information regarding the types of contracts under which oil, natural gas, and NGL sales revenue is generated.
The Company records revenue in the month production is delivered and control is transferred to the purchaser. However, settlement statements and payment may not be received for 30 to 60 days after the date production is delivered and control is transferred. Until such time settlement statements and payment are received, the Company records a revenue accrual based on, amongst other factors, an estimate of the volumes delivered at estimated prices as determined by the applicable contractual terms. The Company records the differences between its estimates and the actual amounts received for product sales in the month in which payment is received from the purchaser. For the three and nine months ended September 30, 2023 and 2022, revenue recognized in the reporting period related to performance obligations satisfied in prior reporting periods was insignificant. As of September 30, 2023 and December 31, 2022, the Company’s receivables from contracts with customers were $573.1 million and $343.5 million, respectively.
Accounts payable and accrued expenses contain the following (in thousands):
September 30, 2023
December 31, 2022
Accounts payable trade
$
85,938
$
31,783
Accrued drilling and completion costs
249,625
137,171
Accrued lease operating expense
70,722
18,109
Accrued gathering, transportation, and processing
80,441
59,398
Accrued general and administrative expense
19,282
20,054
Accrued transaction costs
6,410
—
Accrued commodity derivative settlements
20,599
12,514
Accrued interest expense
75,183
5,509
Accrued settlement
1,727
1,497
Other accrued expenses
35,287
9,262
Total accounts payable and accrued expenses
$
645,214
$
295,297
NOTE 5 - LONG-TERM DEBT
Senior Notes
Senior Notes are recorded net of unamortized discount and unamortized deferred financing costs within senior notes on the accompanying balance sheets, with no associated premiums. The tables below present the related carrying values as of September 30, 2023 and December 31, 2022 (in thousands):
As of September 30, 2023
Principal Amount
Unamortized Discount
Unamortized Deferred Financing Costs
Principal Amount, Net
2026 Senior Notes
$
400,000
$
—
$
5,489
$
394,511
2028 Senior Notes
1,350,000
16,409
5,773
1,327,818
2031 Senior Notes
1,350,000
16,600
5,841
1,327,559
Total
$
3,100,000
$
33,009
$
17,103
$
3,049,888
As of December 31, 2022
Principal Amount
Unamortized Discount
Unamortized Deferred Financing Costs
Principal Amount, Net
2026 Senior Notes
$
400,000
$
—
$
6,707
$
393,293
8.375% Senior Notes due 2028 and 8.750% Senior Notes due 2031. On June 29, 2023, the Company issued $1.35 billion aggregate principal amount of 8.375% Senior Notes due 2028 (the “2028 Senior Notes”), at par, pursuant to an indenture (the “2028 Indenture”) among the Company, Computershare Trust Company, N.A., as trustee, and the guarantors party thereto, and $1.35 billion aggregate principal amount of 8.750% Senior Notes due 2031 (the “2031 Senior Notes”), at par, pursuant to an indenture (the “2031 Indenture”) among the Company, Computershare Trust Company, N.A., as trustee. Upon issuance of the 2028 Senior Notes and 2031 Senior Notes, the Company received net proceeds of $2.67 billion after deducting fees of $33.8 million. The Company used the net proceeds from the 2028 Senior Notes and 2031 Senior Notes, together with cash on hand and borrowings under the Credit Facility (as defined below), to fund a portion of the consideration for the Hibernia Acquisition and Tap Rock Acquisition. Interest on the 2028 Senior Notes and 2031 Senior Notes will accrue at the rate of 8.375% per annum and 8.750% per annum, respectively, and will be payable semi-annually in arrears on January 1 and July 1 of each year, commencing on January 1, 2024.
The 2028 Indenture and 2031 Indenture each contain covenants that limit, among other things, the Company’s ability and the ability of its subsidiaries to: incur or guarantee additional indebtedness; create liens securing indebtedness; pay dividends on or redeem or repurchase stock or subordinated debt; make specified types of investments and acquisitions; enter into or permit to exist contractual limits on the ability of the Company’s subsidiaries to pay dividends to the Company; enter into transactions with affiliates; and 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 2028 Indenture and 2031 Indenture as of September 30, 2023, and through the filing of this report. Each of the 2028 Indenture and 2031 Indenture also contain customary events of default.
At any time prior to July 1, 2025, the Company may redeem all or part of the 2028 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 July 1, 2025, the Company may redeem all or part of the 2028 Senior Notes at redemption prices (expressed as percentages of the principal amount redeemed) equal to (i) 104.188% for the twelve-month period beginning on July 1, 2025; (ii) 102.094% for the twelve-month period beginning on July 1, 2026; and (iii) 100.000% for the period beginning July 1, 2027 and at any time thereafter, plus accrued and unpaid interest, if any to, but excluding the redemption date.
At any time prior to July 1, 2026, the Company may redeem all or part of the 2031 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 July 1, 2026, the Company may redeem all or part of the 2031 Senior Notes at redemption prices (expressed as percentages of the principal amount redeemed) equal to (i) 104.375% for the twelve-month period beginning on July 1, 2026; (ii) 102.188% for the twelve-month period beginning on July 1, 2027; and (iii) 100.000% for the period beginning July 1, 2028 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 2028 Senior Notes or 2031 Senior Notes at any time prior to July 1, 2025 or 2026, respectively, with an amount not to exceed the net cash proceeds from certain equity offerings at a redemption price equal to 108.375%, with respect to the 2028 Senior Notes, and 108.750%, with respect to the 2031 Senior Notes, of the principal amount of such series of 2028 Senior Notes and 2031 Senior Notes redeemed, plus accrued and unpaid interest, if any, provided, however, that (i) at least 65.0% of the aggregate principal amount of 2028 Senior Notes and 2031 Senior Notes of such series originally issued on the issue date (but excluding the 2028 Senior Notes and 2031 Senior Notes of such series held by the Company and its subsidiaries) remains outstanding immediately after the occurrence of such redemption (unless all such 2028 Senior Notes and 2031 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 2028 Senior Notes and 2031 Senior Notes are fully and unconditionally guaranteed on a senior unsecured basis by all of the Company’s subsidiaries, including the entities that became subsidiaries of the Company upon the consummation of the Hibernia Acquisition and Tap Rock Acquisition, as well as by certain other future subsidiaries that may be required to guarantee the 2028 Senior Notes and 2031 Senior Notes.
5.000% Senior Notes due 2026. On October 13, 2021, the Company issued $400.0 million aggregate principal amount of 5.000% Senior Notes due 2026 (the “2026 Senior Notes”) pursuant to an indenture (the “2026 Indenture”), among Civitas Resources, Wells Fargo Bank, National Association, as trustee, and the guarantors party thereto. Interest accrues at the rate of 5.000% per annum and is payable semiannually in arrears on April 15 and October 15 of each year. Payments commenced on April 15, 2022.
The 2026 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 2026 Indenture as of September 30, 2023, and through the filing of this report. In addition, certain of these covenants will be terminated before the 2026 Senior Notes mature if at any time no default or event of default exists under the 2026 Indenture and the 2026 Senior Notes receive an investment-grade rating from at least two ratings agencies. The 2026 Indenture also contains customary events of default.
At any time prior to October 15, 2023, the Company may redeem the 2026 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 2026 Senior Notes at redemption prices (expressed as percentages of the principal amount redeemed) equal to (i) 102.500% for the twelve-month period beginning on October 15, 2023; (ii) 101.250% for the twelve-month period beginning on October 15, 2024; and (iii) 100.000% 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 2026 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 105.000% of the principal amount of the 2026 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 2026 Senior Notes originally issued on the issue date (but excluding 2026 Senior Notes held by the Company) remains outstanding immediately after the occurrence of such redemption (unless all such 2026 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 2026 Senior Notes are fully and unconditionally guaranteed on a senior unsecured basis by all of Civitas’ existing subsidiaries, including the entities that became subsidiaries of the Company upon the consummation of the Hibernia Acquisition and Tap Rock Acquisition.
7.500% Senior Notes due 2026. In April 2021, the Company issued $100.0 million aggregate principal amount of 7.500% Senior Notes due 2026 pursuant to an indenture by and among Civitas Resources, U.S. Bank National Association, as trustee, and the guarantors party thereto. Interest accrued at the rate of 7.500% 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 7.500% Senior Notes at 100.0% of their aggregate principal amount, plus accrued and unpaid interest thereon to the redemption date.
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, as lenders, that has an aggregate maximum commitment amount of $4.0 billion and is set to mature on August 2, 2028 (together with all amendments thereto, the “Credit Facility” or the “Credit Agreement”).
The Credit Facility is guaranteed by all restricted domestic subsidiaries of the Company, including the entities that became subsidiaries of the Company upon the consummation of the Hibernia Acquisition and Tap Rock Acquisition, and is secured by first priority security interests on substantially all assets, including a mortgage on at least 90% of the total value of the proved properties evaluated in the most recently delivered reserve reports prior to the amendment effective date, including any engineering reports relating to the oil and natural gas properties of the restricted domestic subsidiaries of the Company, subject to customary exceptions.
The Credit Facility contains customary representations and affirmative covenants. The Credit Facility also contains customary negative covenants, which, among other things, and subject to certain exceptions, include restrictions on (i) liens, (ii) indebtedness, guarantees and other obligations, (iii) restrictions in agreements on liens and distributions, (iv) mergers or consolidations, (v) asset sales, (vi) restricted payments, (vii) investments, (viii) affiliate transactions, (ix) change of business, (x) foreign operations or subsidiaries, (xi) name changes, (xii) use of proceeds, letters of credit, (xiii) gas imbalances, (xiv) hedging transactions, (xv) additional subsidiaries, (xvi) changes in fiscal year or fiscal quarter, (xvii) operating leases, (xviii) prepayments of certain debt and other obligations, (xix) sales or discounts of receivables, (xx) dividend payment thresholds, and (xxi) cash balances.
In addition, the Company is subject to certain financial covenants under the Credit Facility, as tested on the last day of each fiscal quarter, including, without limitation, (a) permitted net leverage ratio of 3.00 to 1.00 and (b) a current ratio, inclusive of the unused commitments then available to be borrowed, to not be less than 1.00 to 1.00. The Company was in compliance with all covenants under the Credit Facility as of September 30, 2023 and through the filing of this report. 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 Secured Overnight Financing Rate (“SOFR”) plus the applicable margin. ABR is established as a rate per annum equal to the greatest of (a) the rate of interest publicly announced by JPMorgan as its prime rate, (b) the applicable rate of interest published by the Federal Reserve Bank of New York plus 0.5%, or (c) the term-specific SOFR plus 1.0%, subject to a 1.5% floor plus the applicable margin of 1.0% to 2.0%, 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 0.5% floor plus the applicable margin of 2.0% to 3.0%, based on the utilization of the Credit Facility. Interest on borrowings that bear interest at the SOFR are payable on the last day of the applicable interest period selected by the Company, and interest on borrowings that bear interest at the ABR are payable quarterly in arrears.
In connection with the Company’s entry into the Hibernia Acquisition Agreement and the Tap Rock Acquisition Agreement, on June 23, 2023, the Company entered into an amendment to the Credit Agreement. Pursuant to the amendment, the Company was authorized to, among other things, (i) offer and issue the 2028 Senior Notes and the 2031 Senior Notes, (ii) incur indebtedness pursuant to those certain debt commitment letters by and among the Company, Bank of America N.A., BofA Securities, Inc., and JPMorgan Chase Bank, N.A. providing for two separate 364-day bridge loan facilities in an aggregate principal amount of up to $2.7 billion (such facilities, the “Bridge Facilities” and the loans made thereunder, the “Bridge Loans”), the proceeds of which would have, if drawn, been used to partially fund the Hibernia Acquisition and the Tap Rock Acquisition, (iii) incur the debt described in the immediately preceding clauses (i) and (ii) without any corresponding reduction in the borrowing base of the Credit Facility, and (iv) incur pari passu term loan indebtedness subject to a total secured leverage test of 2.00 to 1.00 and certain other customary terms and conditions. Because the 2028 Senior Notes and 2031 Senior Notes successfully closed and were issued on June 29, 2023, the Company did not draw on the Bridge Loans and has terminated the commitments under the Bridge Facilities. Consequently, approximately $0.5 million and $21.0 million of fees associated with the Bridge Facilities were incurred and expensed to transaction costs in the accompanying statements of operations for the three and nine months ended September 30, 2023, respectively.
Finally, in connection with the Company’s closing of the Hibernia Acquisition and Tap Rock Acquisition, on August 2, 2023, the Company entered in an amendment to the Credit Agreement whereby aggregate elected commitments increased from $1.0 billion to $1.85 billion, the borrowing base increased from $1.85 billion to $3.0 billion, and the aggregate maximum credit commitment increased from $2.0 billion to $4.0 billion. In addition, the maturity of the Credit Facility was extended to August 2028. The next scheduled borrowing base redetermination date is set to occur in May 2024.
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):
November 7, 2023
September 30, 2023
December 31, 2022
Revolving credit facility
$
—
$
650,000
$
—
Letters of credit
2,100
2,100
12,100
Available borrowing capacity
1,847,900
1,197,900
987,900
Total aggregate elected commitments
$
1,850,000
$
1,850,000
$
1,000,000
As of September 30, 2023 and December 31, 2022, the unamortized deferred financing costs associated with the amendments to the Credit Facility were $36.1 million and $8.5 million, respectively. Of the unamortized deferred financing costs, (i) $28.6 million and $5.5 million are presented within other noncurrent assets on the accompanying balance sheets as of September 30, 2023 and December 31, 2022, respectively, and (ii) $7.5 million and $3.0 million are presented within prepaid expenses and other on the accompanying balance sheets as of September 30, 2023 and December 31, 2022, respectively.
Interest Expense
For the three months ended September 30, 2023 and 2022, the Company incurred interest expense of $76.5 million and $7.5 million, respectively. For the nine months ended September 30, 2023 and 2022, the Company incurred interest expense of $92.7 million and $24.7 million, respectively. No interest was capitalized during the three and nine months ended September 30, 2023 and 2022.
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.
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.
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 ECMC alleging violations of various Colorado statutes and ECMC regulations governing oil and gas operations. The Company has further received notices from the Colorado Air Pollution Control Division. The Company continues to engage in discussions regarding resolution of the alleged violations. As of September 30, 2023 and December 31, 2022, the Company has accrued approximately $0.8 million and $0.7 million, respectively, associated with the NOAVs and Colorado Air Pollution Control Division notices.
Commitments
Firm Transportation Agreements. The Company is party to a 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 $28.5 million as of September 30, 2023. The Company has not and does not expect to incur any deficiency payments.
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 volume commitment of 20,000 Bbls per day over a term ending in December 2023. The aggregate financial commitment fee over the remaining term is $11.7 million as of September 30, 2023. 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 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 NGL 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 fee over the remaining term is $109.7 million as of September 30, 2023, which fluctuates with commodity prices as this is a value-based percentage of proceeds sales contract. During the three months ended September 30, 2023, we recorded $3.6 million in unused commitments in the statements of operations based on volumes delivered relative to the minimum volume commitment. Based on current projections, the Company may incur approximately $31.9 million, inclusive of the amounts recorded as described above, of shortfall payments under the Gathering Agreement during the remaining term of approximately six years; however, the Company is actively engaging alternative strategies to reduce any potential contract deficiencies incurred in future periods.
Additionally, the Company is also party to a gas gathering and processing agreement with several third-party producers and a third-party midstream provider to deliver to two different plants over terms that end in August 2025 and July 2026. The Company’s share of these commitments requires an incremental 51.5 and 20.6 million cubic feet of natural gas (“MMcf”) per day, respectively, over a baseline volume of 65 MMcf per day for a period of seven years following the in-service dates of the plants. The Company may be required to pay a shortfall fee for any incremental volume deficiencies under these commitments. These contractual obligations can be reduced by the Company’s proportionate share of the collective volumes delivered to the plants by other incremental third-party volumes available to the midstream provider that are in excess of the total commitments. Because of the third-party producer reduction provision, we believe that the aggregate financial commitment fee over the remaining term is zero as of September 30, 2023. 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 over various terms ending in December 2025, regardless of the amount delivered. The aggregate financial commitment fee over the remaining term for these contracts was $9.0 million as of September 30, 2023.
The minimum annual payments under these agreements for the next five years as of September 30, 2023 are presented below (in thousands):
Firm Transportation
Minimum Volume(1)
Remainder of 2023
$
4,531
$
21,688
2024
18,026
20,655
2025
5,910
21,349
2026
—
17,598
2027
—
16,900
2028 and thereafter
—
32,240
Total
$
28,467
$
130,430
___________________________
(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 and complete a total of 106 qualifying 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.
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, in conjunction with the Company’s merger with Extraction Oil & Gas, Inc. (“Extraction”) in November 2021, Civitas assumed Extraction’s 2021 Long Term Incentive Plan (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”.
The Company records compensation expense associated with the issuance of awards under the LTIP on a straight-line basis over the vesting period based on the fair value of the awards as of the date of grant within general and administrative expense. The following table outlines the compensation expense recorded by type of award (in thousands):
Three Months Ended September 30,
Nine Months Ended September 30,
2023
2022
2023
2022
Restricted and deferred stock units
$
4,711
$
5,809
$
13,905
$
14,991
Performance stock units
3,591
4,435
11,672
9,478
Total stock-based compensation
$
8,302
$
10,244
$
25,577
$
24,469
As of September 30, 2023, 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
$
39,645
2026
Performance stock units
23,225
2025
Total unrecognized stock-based compensation
$
62,870
Restricted Stock Units and Deferred Stock Units
The Company grants time-based Restricted Stock Units (“RSUs”) to its officers, executives, and employees and time-based Deferred Stock Units (“DSUs”) to its non-employee directors as part of its LTIP. Each RSU and DSU represents a right to receive one share of the Company’s common stock after the RSU or DSU vests and is settled as described below. RSUs generally vest and settle either over a (i) one-year vesting period, with the entire grant vesting and settling on the anniversary date, (ii) two-year vesting period, with one-half of the total grant vesting and settling on each anniversary date, or (iii) three-year vesting period, with one-third of the total grant vesting and settling on each anniversary date. Each RSU is entitled to a dividend equivalent right to receive, upon settlement, a cash payment based on the regular cash dividends that would have been paid on a share of the Company’s common stock during the period between the grant date and the date the RSUs vest and are settled. Accrued but unpaid dividend equivalents are recognized as a liability on the accompanying balance sheets, until the recipients receive the dividend equivalents upon vesting and settlement. DSUs generally vest over a one-year period following the grant date. DSUs are settled in shares of the Company’s common stock upon the non-employee director’s separation of service from the Board of Directors (the “Board”). Each DSU is entitled to a dividend equivalent right to receive a cash payment based on the regular cash dividends that would have been paid on a share of the Company’s common stock. All amounts payable as a result of such dividend equivalent right are paid (1) with respect to vested DSUs, at the same time dividends are paid to the Company’s stockholders and (2) with respect to unvested DSUs, when such underlying DSUs vest. Accrued but unpaid dividend equivalents in respect of unvested DSUs are recognized as a liability on the accompanying balance sheets, until the recipients receive the dividend equivalents upon vesting. The grant-date fair value of RSUs and DSUs is equal to the closing price of the Company’s common stock on the date of the grant.
A summary of the status and activity of non-vested RSUs and DSUs for the nine months ended September 30, 2023 is presented below:
RSUs and DSUs
Weighted-Average Grant-Date Fair Value
Non-vested, beginning of year
675,898
$
50.27
Granted
549,127
72.30
Vested
(364,159)
47.30
Forfeited
(48,866)
58.78
Non-vested, end of period
812,000
$
65.99
The aggregate grant-date fair value of the RSUs and DSUs granted under the LTIP during the nine months ended September 30, 2023 was $39.7 million.
The Company grants market-based performance stock units (“PSUs”) to its officers and certain executives as part of its LTIP. The number of shares of the Company’s common stock issued to settle PSUs ranges from zero to 225% (or, for PSUs granted prior to fiscal year 2023, 200%) of the number of PSUs granted and is determined based on performance achievement against certain market-based criteria over a three-year performance period. PSUs generally vest and settle on December 31 of the year preceding the third anniversary of the date of grant. Each PSU is entitled to a dividend equivalent right to receive, upon settlement, a cash payment based on the regular cash dividends that would have been paid on a share of the Company’s common stock during the period between the grant date and the date the PSUs vest and are settled. Accrued but unpaid dividend equivalents are recognized as a liability on the accompanying balance sheets, until the recipients receive the dividend equivalents upon vesting and settlement.
Performance achievement is determined based on either, or a combination of, (1) the Company’s annualized absolute total stockholder return (“TSR”) or (2) for certain PSUs granted prior to fiscal year 2023, the Company’s absolute TSR relative to that of a defined peer group. 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 resultant amount is then annualized based on the length of the performance period.
The grant-date fair value of the PSUs was estimated using a Monte Carlo valuation model. The Monte Carlo valuation model is based on random projections of stock price paths and must be repeated numerous times to achieve a probabilistic assessment. Significant assumptions used in this valuation include the Company’s expected volatility as well as the volatilities for each of the Company’s peers and an interpolated risk-free interest rate based on U.S. Treasury yields with maturities consistent with the performance period.
A summary of the status and activity of non-vested PSUs for the nine months ended September 30, 2023 is presented below:
PSUs (1)
Weighted-Average Grant-Date Fair Value
Non-vested, beginning of year
345,999
$
77.42
Granted
247,421
104.44
Vested
(89,901)
78.49
Forfeited
(73,759)
87.49
Expired
(242)
18.26
Non-vested, end of period
429,518
$
91.07
___________________________
(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 225% (or, for PSUs granted prior to fiscal year 2023, 200%), depending on the level of satisfaction of the performance condition.
The aggregate grant-date fair value of the PSUs granted under the LTIP during the nine months ended September 30, 2023 was $25.8 million.
Stock Options
The LTIP allows for the issuance of stock options to the Company’s employees at the sole discretion of the Board. Options expire ten years from the grant date unless otherwise determined by the Board.
Stock options are valued using a Black-Scholes Model where expected volatility is based on an average historical volatility of a peer group selected by management over a period consistent with the expected life assumption on the grant date, the risk-free rate of return is based on the U.S. Treasury constant maturity yield on the grant date with a remaining term equal to the expected term of the awards, and the Company’s expected life of stock option awards is derived from the midpoint of the average vesting time and contractual term of the awards.
A summary of the status and activity of stock options for the nine months ended September 30, 2023 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
15,170
$
34.36
Exercised
(13,928)
34.36
Expired
(111)
34.36
Outstanding, end of period
1,131
$
34.36
3.6
$
49
Options outstanding and exercisable
1,131
$
34.36
3.6
$
49
The aggregate intrinsic value of options exercised during the nine months ended September 30, 2023 was $0.5 million.
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.
The Company uses Level 2 inputs to measure the fair value of oil and natural gas commodity price derivatives. The fair value of the Company’s commodity price derivatives is estimated using industry-standard models that contemplate various inputs including, but not limited to, the contractual price of the underlying position, current market prices, forward commodity price curves, volatility factors, time value of money, and the credit risk of both the Company and its counterparties. We validate our fair value estimate by corroborating the original source of inputs, monitoring changes in valuation methods and assumptions, and reviewing counterparty mark-to-market statements and other supporting documentation. Refer to Note 9 - Derivatives for more information regarding the Company’s derivative instruments.
The following tables present the Company’s financial assets and liabilities that were accounted for at fair value on a recurring basis as of September 30, 2023 and December 31, 2022 and their classification within the fair value hierarchy (in thousands):
As of September 30, 2023
Level 1
Level 2
Level 3
Derivative assets
$
—
$
8,930
$
—
Derivative liabilities
$
—
$
136,821
$
—
As of December 31, 2022
Level 1
Level 2
Level 3
Derivative assets
$
—
$
3,284
$
—
Derivative liabilities
$
—
$
63,533
$
—
Long-Term Debt
The 2026 Senior Notes, 2028 Senior Notes, and 2031 Senior Notes are recorded at cost, net of any unamortized discount or deferred financing costs. As of September 30, 2023, the fair value of the 2026 Senior Notes, 2028 Senior Notes, and 2031 Senior Notes were $375.4 million, $1.38 billion, and $1.38 billion, respectively. These fair values are based on quoted market prices, and as such, are designated as Level 1 within the fair value hierarchy. The recorded value of the Credit Facility, if any, 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.
Warrants
Warrants issued are indexed to the Company’s common stock and required to be net share settled via a cashless exercise. Accordingly, they are classified as equity instruments. The Company’s share price traded below the exercise price of the warrants and therefore were not exercisable during the three and nine months ended September 30, 2023 and 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 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 and Unproved Properties
We measure acquired assets or businesses at fair value on a nonrecurring basis and review our proved and unproved oil and natural gas properties for impairment using inputs that are not observable in the market, and are therefore designated as Level 3 within the valuation hierarchy. There were no impairments of proved properties recorded during the three and nine months ended September 30, 2023 and 2022, and no abandonment and impairment of unproved properties expense was incurred during the three months ended September 30, 2023 and 2022. During the nine months ended September 30, 2023 and 2022, the Company incurred abandonment and impairment of unproved properties expense of zero and $18.0 million, respectively. Please refer to Note 1 – Summary of Significant Accounting Policies in the 2022 Form 10-K for information on the Company’s policies for determining fair value of its proved and unproved properties and related impairment expense.
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 and natural gas production and the associated impact on cash flows. The Company’s commodity derivative contracts consist of swaps, collars, basis protection swaps, and puts. As of September 30, 2023, 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.
A typical swap arrangement guarantees a fixed price on contracted volumes. 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 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.
Basis protection swaps are arrangements that guarantee a price differential for natural gas from a specified delivery point. For basis protection swaps, the Company receives a payment from the counterparty if the price differential is greater than the stated terms of the contract and pays the counterparty if the price differential is less than the stated terms of the contract.
A put arrangement gives the Company the right to sell the underlying commodity at a strike price over the term of the contract. If the index price is higher than the strike price, no payment or receipt occurs. If the index price is lower than the strike price, the Company receives the difference between the index price and the strike price.
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 September 30, 2023 and December 31, 2022 (in thousands):
September 30, 2023
December 31, 2022
Derivative Assets:
Commodity contracts - current
$
7,058
$
2,490
Commodity contracts - noncurrent
1,872
794
Total derivative assets
8,930
3,284
Amounts not offset in the accompanying balance sheets
(906)
—
Total derivative assets, net
$
8,024
$
3,284
Derivative Liabilities:
Commodity contracts - current
$
(126,053)
$
(46,334)
Commodity contracts - long-term
(10,768)
(17,199)
Total derivative liabilities
(136,821)
(63,533)
Amounts not offset in the accompanying balance sheets
906
—
Total derivative liabilities, net
$
(135,915)
$
(63,533)
The following table summarizes the components of the derivative gain (loss) presented on the accompanying statements of operations for the periods below (in thousands):
Three Months Ended September 30,
Nine Months Ended September 30,
2023
2022
2023
2022
Derivative cash settlement loss:
Oil contracts
$
(32,397)
$
(67,623)
$
(38,010)
$
(307,563)
Natural gas contracts
(625)
(66,610)
(6,897)
(149,485)
NGL contracts
—
(9,678)
—
(35,072)
Total derivative cash settlement loss
(33,022)
(143,911)
(44,907)
(492,120)
Change in fair value gain (loss)
(117,639)
153,192
(75,667)
133,258
Total derivative gain (loss)
$
(150,661)
$
9,281
$
(120,574)
$
(358,862)
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 proved properties 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 unaudited condensed consolidated 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.
A roll-forward of the Company’s asset retirement obligation is as follows (in thousands):
Amount
Balance as of December 31, 2022
$
291,026
Additional liabilities incurred
42,549
Accretion expense
12,134
Liabilities settled
(15,340)
Balance as of September 30, 2023
$
330,369
Current portion
25,557
Long-term portion
$
304,812
NOTE 11-EARNINGS PER SHARE
Earnings per basic and diluted share are calculated under the treasury stock method. Basic net income per common share is calculated by dividing net income by the basic weighted-average common shares outstanding for the respective period. Diluted net income per common share is calculated by dividing net income by the diluted weighted-average common shares outstanding, which includes the effect of potentially dilutive securities. Potentially dilutive securities consist of unvested RSUs, DSUs, and 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.
As discussed in Note 7 - Stock-Based Compensation, PSUs represent the right to receive a number of shares of the Company’s common stock ranging from zero to 225% (or, for PSUs granted prior to fiscal year 2023, 200%) of PSUs granted based on the performance achievement over the applicable performance period. 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 awards.
The Company has also issued stock options and warrants, which both represent the right to purchase the Company’s common stock at a specified exercise price. The number of potentially dilutive shares related to the stock options and warrants is based on the number of shares, if any, that would be exercisable at the end of the respective reporting period, assuming that 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.
The following table sets forth the calculations of basic and diluted net income per common share (in thousands, except per share amounts):
Three Months Ended September 30,
Nine Months Ended September 30,
2023
2022
2023
2022
Net income
$
139,672
$
405,752
$
481,420
$
966,212
Basic net income per common share
$
1.57
$
4.77
$
5.75
$
11.37
Diluted net income per common share
$
1.56
$
4.74
$
5.70
$
11.30
Weighted-average shares outstanding - basic
88,911
85,069
83,700
84,968
Add: dilutive effect of stock awards
720
485
768
527
Weighted-average shares outstanding - diluted
89,631
85,554
84,468
85,495
There were 10,103 and 109,519 shares that were anti-dilutive for the three months ended September 30, 2023 and 2022, respectively. There were 7,437 and 68,171 shares that were anti-dilutive for the nine months ended September 30, 2023 and 2022, respectively.
The exercise price of the Company’s warrants was in excess of the Company’s stock price during the three and nine months ended September 30, 2023 and 2022; therefore, they were excluded from the earnings per share calculation.
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 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 merger activity in 2021, the Company had a valuation allowance of $25.4 million as of both September 30, 2023 and December 31, 2022 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 Internal Revenue Code. The Company will continue to monitor facts and circumstances in the reassessment of the likelihood that the deferred tax assets will be realized.
The net deferred tax liability as of September 30, 2023 and December 31, 2022 was $458.6 million and $319.6 million, respectively. Additionally, prepaid income taxes under current assets as of September 30, 2023 and December 31, 2022 were $21.6 million and $29.6 million, respectively.
During the three months ended September 30, 2023 and 2022, the Company recorded income tax expense of $29.7 million and $136.3 million, respectively. During the nine months ended September 30, 2023 and 2022, the Company recorded income tax expense of $139.1 million and $312.2 million, respectively. 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 due to the effect of state income taxes, excess tax benefits and deficiencies on stock-based compensation awards, and tax limitations on compensation of covered individuals. During the three and nine months ended September 30, 2023, income tax expense was additionally impacted by deferred tax benefits from state apportionment changes as a result of the Hibernia Acquisition and Tap Rock Acquisition. During the three and nine months ended September 30, 2022, income tax expense was additionally impacted by changes in valuation allowances and other permanent differences including bargain purchase gain.
The Company had no unrecognized tax benefits as of September 30, 2023 and December 31, 2022. 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 2023.
On August 16, 2022, the Inflation Reduction Act (“IRA”) was signed into law. Among other provisions, the IRA imposes a 15% corporate alternative minimum tax (“Corporate AMT”) for tax years beginning after December 31, 2022. The Company is evaluating the potential impact of the Corporate AMT on our current income tax expense and income taxes payable; however, we currently do not believe this will materially affect our income taxes paid for the 2023 tax year.
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 leases (in thousands):
September 30, 2023
December 31, 2022
Operating Leases
Field equipment(1)
$
64,076
$
15,131
Corporate leases
6,140
8,235
Vehicles
4,446
759
Total right-of-use asset
$
74,662
$
24,125
Field equipment(1)
$
64,132
$
15,131
Corporate leases
6,796
8,898
Vehicles
4,446
759
Total lease liability
$
75,374
$
24,788
Finance Leases
Right of use asset - field equipment
$
17,104
$
—
Lease liability - field equipment
$
17,131
$
—
____________________________
(1)Includes drilling rigs, compressors, certain natural gas processing equipment, and other field equipment.
Future commitments by year for the Company’s leases with a lease term of greater than one year as of September 30, 2023 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):
NOTE 14 - SUPPLEMENTAL DISCLOSURES OF CASH FLOW INFORMATION
Supplemental cash flow disclosures are presented below (in thousands):
Nine Months Ended September 30,
2023
2022
Supplemental cash flow information:
Cash (paid) refunded for income taxes
$
7,861
$
(59,800)
Cash paid for interest
(17,110)
(17,124)
Supplemental non-cash investing activities:
Non-cash investing activities
1,065,901
—
Non-cash financing activities
990,204
—
Changes in working capital related to capital expenditures
(112,454)
33
NOTE 15 - STOCKHOLDERS’ EQUITY
Share Repurchases
On January 24, 2023, we entered into a privately-negotiated share purchase agreement with CPPIB Crestone Peak Resources Canada Inc. for the purchase of approximately 4.9 million shares of the Company’s common stock at a price of $61.00 per share for a total purchase price of approximately $300.0 million. The purchase closed on January 27, 2023 and was funded from the Company’s cash on hand. The shares repurchased were immediately retired.
In February 2023, we announced that the Board provided authorization for a stock repurchase program (the “stock repurchase program”) pursuant to which we may, from time to time and through December 31, 2024, acquire shares of our common stock in the open market, in privately negotiated transactions, or through block trades, derivative transactions, or purchases made in accordance with the Rule 10b5-1 of the Exchange Act in an amount not to exceed $1.0 billion, exclusive of any fees, commissions, or other expenses related to such repurchases. In June 2023, commensurate with the announcement of the Hibernia Acquisition and Tap Rock Acquisition, the Board reduced the amount of stock authorized for repurchase by the Company under the stock repurchase program from $1.0 billion to $500.0 million. The stock repurchase program does not require any specific number of shares to be acquired and can be modified or discontinued by the Board at any time. As of September 30, 2023, the Company has repurchased approximately 312,800 shares under the program at a weighted average price of $64.55 per share for a total cost of $20.3 million.
We record share repurchases at cost, which includes incremental direct transaction costs, as a reduction to stockholder’s equity. As part of the incremental direct transactions costs and subject to netting against the fair value of stock issuances, we record a 1% excise tax with the corresponding liability recorded within accounts payable and accrued expenses on the accompanying balance sheets. Any excess of cost over the par value is charged to additional paid-in-capital on a pro-rata basis, with any remaining cost charged to retained earnings.
Dividends
As approved by the Board, cash dividends are paid quarterly and consist of a base and variable component. Variable cash dividends are equal to 50% of free cash flow after the base cash dividend for the preceding twelve-month period and pro forma for all acquisition and divestiture activity, assuming pro forma compliance with certain leverage targets.
The following table summarizes the dividends declared for the nine months ended September 30, 2023 and 2022:
Base
Variable
Total
Total
(per share)
(per share)
(per share)
(in thousands)
2023:
First quarter
$
0.50
$
1.65
$
2.15
$
176,878
Second quarter
$
0.50
$
1.62
$
2.12
$
173,358
Third Quarter
$
0.50
$
1.24
$
1.74
$
167,010
2022:
First quarter
$
0.46
$
0.75
$
1.21
$
104,444
Second quarter
$
0.46
$
0.90
$
1.36
$
117,151
Third Quarter
$
0.46
$
1.30
$
1.76
$
151,729
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.
On October 3, 2023, the Company entered into a purchase and sale agreement (the “PSA”) with Vencer Energy, LLC (“Vencer”), pursuant to which the Company agreed to acquire from Vencer certain oil and gas properties, interests and related assets located in Glasscock, Martin, Midland, Reagan and Upton Counties, Texas (the “Assets”).
As consideration for the pending transactions contemplated by the PSA (the “Vencer Acquisition”, Vencer will receive an aggregate of $2.15 billion with the initial consideration payable at the closing of the transactions (the “Closing”) comprised of (i) $1.0 billion in cash, subject to certain customary purchase price adjustments set forth in the PSA (as adjusted, the “Cash Consideration”), and (ii) 7,289,515 shares of common stock, par value $0.01 per share, of the Company (the “Shares”) valued at approximately $600.0 million, subject to certain customary anti-dilution and purchase price adjustments (as adjusted, the “Stock Consideration”).
As further consideration for the Assets, the Company will pay to Vencer up to $550.0 million in cash on January 3, 2025 (the “Deferred Payment” and, together with the Cash Consideration and the Stock Consideration, as each may be adjusted, the “Purchase Price”). The Company has the option to increase the Cash Consideration payable at Closing and retire all or a portion of the Deferred Payment, in which event, the remaining Deferred Payment (if any) due on January 3, 2025, will be reduced as and to the extent provided in the PSA.
The obligations of the parties to complete the Vencer Acquisition are subject to the satisfaction or waiver of customary closing conditions set forth in the PSA. In connection with and upon execution of the PSA, the Company deposited with an escrow agent a cash deposit equal to 7.5% of the unadjusted Purchase Price, which deposit will be credited against the Purchase Price payable at closing, or returned to the Company if the closing does not occur for any reason other than as a result of a breach of the Company that results in certain closing conditions not to be satisfied (as further described in the PSA).
Fifth Amendment to the Credit Facility
In connection with the Company’s entry into the PSA, on October 6, 2023, the Company entered into an amendment to the Credit Agreement (the “Fifth Amendment”). The Fifth Amendment amends the Credit Agreement to, among other things, permit the Company to incur, on or before January 31, 2024, an aggregate of up to $1.5 billion of indebtedness comprised of new senior unsecured notes, unsecured bridge facilities or a combination thereof, provided the proceeds therefrom are used to fund the Vencer Acquisition.
8.625% Senior Notes due 2030
On October 17, 2023, the Company issued $1.0 billion aggregate principal amount of 8.625% Senior Notes due 2030 (the “2030 Senior Notes”), at par, pursuant to an indenture (the “2030 Indenture”) among the Company, Computershare Trust Company, N.A., as trustee, and the guarantors party thereto. Upon issuance of the 2030 Senior Notes, the Company received net proceeds of $987.5 million after deducting fees of $12.5 million. The Company expects to use the net proceeds, together with cash on hand, to fund a portion of the cash purchase price for the Vencer Acquisition. Pending the potential use of the net proceeds to fund a portion of the consideration for the Vencer Acquisition, the Company has temporarily applied the net proceeds to repay outstanding borrowings under the Credit Facility.
The 2030 Senior Notes are subject to a special mandatory redemption such that if (i) the consummation of the Vencer Acquisition does not occur on or before January 31, 2024 or (ii) prior thereto, the Company notifies Computershare Trust Company, N.A. that it will not pursue the consummation of the Vencer Acquisition, it will be required to redeem all 2030 Senior Notes then outstanding (such redemption, the “Special Mandatory Redemption”) at a redemption price equal to 100% of the principal amount of the 2030 Senior Notes to be redeemed, plus accrued and unpaid interest to, but excluding, the date of the Special Mandatory Redemption.
The 2030 Senior Notes will mature on November 1, 2030. Interest on the 2030 Senior Notes will accrue at the rate of 8.625% per annum and will be payable semi-annually in arrears on May 1 and November 1 of each year, commencing on May 1, 2024.
At any time prior to November 1, 2026, the Company may redeem all or part of the 2030 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 November 1, 2026, the Company may redeem all or part of the 2030 Senior Notes at redemption prices (expressed as percentages of the principal amount redeemed) equal to (i) 104.313% for the twelve-month period beginning on November 1, 2026; (ii) 102.156% for the twelve-month period beginning on November 1, 2027; and (iii) 100.000% for the period beginning November 1, 2028 and at any time thereafter, plus accrued and unpaid interest, if any, to, but excluding, the redemption date (subject to the right of the noteholders on the relevant record date to receive interest on the relevant interest payment date).
The Company may redeem up to 35% of the aggregate principal amount of the 2030 Senior Notes at any time prior to November 1, 2026 with an amount not to exceed the net cash proceeds from certain equity offerings at a redemption price equal to 108.625% of the principal amount of the 2030 Senior Notes redeemed, plus accrued and unpaid interest, if any, provided, however, that (i) at least 65.0% of the aggregate principal amount of 2030 Senior Notes originally issued on the issue date (but excluding 2030 Senior Notes held by the Company and its subsidiaries) remains outstanding immediately after the occurrence of such redemption (unless all such 2030 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 2030 Indenture contains covenants that limit, among other things, the Company’s ability and the ability of its subsidiaries to: incur or guarantee additional indebtedness; create liens securing indebtedness; pay dividends on or redeem or repurchase stock or subordinated debt; make specified types of investments and acquisitions; enter into or permit to exist contractual limits on the ability of the Company’s subsidiaries to pay dividends to the Company; enter into transactions with affiliates; and 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 2030 Indenture through the filing of this report. The 2030 Indenture also contain customary events of default.
The 2030 Senior Notes are fully and unconditionally guaranteed on a senior unsecured basis by all of the Company’s existing subsidiaries and are expected to be guaranteed by certain other future subsidiaries that may be required to guarantee the 2030 Senior Notes.
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 2022 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 exploration and production company focused on the acquisition, development, and production of oil and associated liquids-rich natural gas primarily in the DJ Basin in Colorado and the Permian Basin in Texas and New Mexico. The Company’s primary objective is to maximize stockholder returns by responsibly developing our oil and natural gas resources. To achieve this, Civitas is guided by four foundational pillars that we believe add long-term, sustainable value. These pillars are: generate free cash flow, maintain a premier balance sheet, return free cash flow to stockholders, and demonstrate ESG leadership.
Financial and Operating Results
Our financial and operational results include:
•Crude oil equivalent sales volumes increased 33% for the three months ended September 30, 2023 when compared to the same period during 2022 primarily due to the Hibernia Acquisition and Tap Rock Acquisition;
•Lease operating expense per barrel of oil equivalent (“Boe”) increased by 57% for the three months ended September 30, 2023 when compared to the same period during 2022 primarily due to increased cost of operatorship in New Mexico as a result of the Tap Rock Acquisition;
•Cash dividends of $163.5 million, or $1.74 per share, declared and paid during the three months ended September 30, 2023;
•Share repurchases of 5.2 million shares of the Company’s common stock at a weighted average of $61.21 per share during the nine months ended September 30, 2023;
•Cash flows provided by operating activities for the nine months ended September 30, 2023 were $1.4 billion, as compared to $2.0 billion during the nine months ended September 30, 2022. Please refer to Liquidity and Capital Resources below for additional discussion; and
•Capital expenditures, inclusive of accruals, were $894.6 million during the nine months ended September 30, 2023, of which $28.7 million represents land and midstream capital expenditures.
Commodity prices continue to be impacted by various macro-economic factors influencing the balance of supply and demand. In 2022 and continuing into 2023, commodity prices have remained relatively strong, which has improved our earnings and ability to generate free cash flow. The strength in commodity prices has been primarily driven by increased demand resulting from the global recovery from the COVID-19 pandemic. Additionally, Russia’s invasion of Ukraine and related economic sanctions imposed on Russia, as well as OPEC+ restraining production growth, further augmented supply shortages, causing upward pressure on oil prices. An escalation of the Israel-Palestine conflict could also lead to further oil supply disruptions and create uncertainty.
Drivers of upward price pressure are tempered by economic uncertainty surrounding inflation and increased interest rates. These inflationary pressures could also result in increases to our capital and operating expenses and could impact the cost of oilfield services, equipment, and personnel retention, among other things. Increases in interest rates as a result of inflation and a potentially recessionary economic environment in the United States could also have a negative effect on the demand for oil and natural gas. The foregoing destabilizing factors have caused dramatic fluctuations in global financial markets and uncertainty about world-wide oil and natural gas supply and demand, which in turn has increased the volatility of oil and natural gas prices.
The below graph depicts monthly average NYMEX WTI oil and NYMEX natural gas HH spot price over the periods ended September 30, 2023 and 2022.
In light of uncertainty associated with oil and natural gas demand, future monetary policy relating to inflationary pressures, and governmental policies aimed at transitioning toward lower carbon energy, we cannot predict any future volatility in or levels of commodity prices or demand for oil and natural gas.
The following discussion and analysis should be read in conjunction with our condensed consolidated financial statements and the notes thereto contained in Part I, Item 1 of this report. Comparative results of operations for the period indicated are discussed below.
The following table summarizes our product revenues, sales volumes, and average sales prices for the periods indicated:
Three Months Ended September 30,
2023
2022
Change
Percent Change
Revenues (in thousands):
Crude oil sales(1)
$
841,393
$
653,831
$
187,562
29
%
Natural gas sales(2)
80,112
215,853
(135,741)
(63)
%
NGL sales
112,905
137,486
(24,581)
(18)
%
Product revenue
$
1,034,410
$
1,007,170
$
27,240
3
%
Sales Volumes:
Crude oil (MBbls)
10,474.1
7,234.3
3,239.8
45
%
Natural gas (MMcf)
37,379.8
29,192.8
8,187.0
28
%
NGL (MBbls)
4,940.6
4,118.5
822.1
20
%
Crude oil equivalent (MBoe)(3)
21,644.7
16,218.3
5,426.4
33
%
Average Sales Prices (before derivatives)(4):
Crude oil (per Bbl)
$
80.33
$
90.38
$
(10.05)
(11)
%
Natural gas (per Mcf)
$
2.14
$
7.39
$
(5.25)
(71)
%
NGL (per Bbl)
$
22.85
$
33.38
$
(10.53)
(32)
%
Crude oil equivalent (per Boe)(3)
$
47.79
$
62.10
$
(14.31)
(23)
%
Average Sales Prices (after derivatives)(4):
Crude oil (per Bbl)
$
77.24
$
81.03
$
(3.79)
(5)
%
Natural gas (per Mcf)
$
2.13
$
5.11
$
(2.98)
(58)
%
NGL (per Bbl)
$
22.85
$
31.03
$
(8.18)
(26)
%
Crude oil equivalent (per Boe)(3)
$
46.26
$
53.23
$
(6.97)
(13)
%
_____________________________
(1)Crude oil sales excludes $0.3 million and $(0.3) million of oil transportation revenues from third parties, which do not have associated sales volumes, for the three months ended September 30, 2023 and 2022, respectively.
(2)Natural gas sales excludes $1.2 million and $1.1 million of gas gathering revenues from third parties, which do not have associated sales volumes, for the three months ended September 30, 2023 and 2022, respectively.
(3)Determined using the ratio of 6 thousand cubic feet (“Mcf”) of natural gas to 1 Bbl of crude oil.
(4)Derivatives economically hedge the price we receive for oil, natural gas, and NGL. For the three months ended September 30, 2023, the derivative cash settlement loss for oil and natural gas was $32.4 million and $0.6 million, respectively. For the three months ended September 30, 2022, the derivative cash settlement loss for oil, natural gas, and NGL was $67.6 million, $66.6 million, and $9.7 million, respectively. Please refer to Note 9 - Derivatives under Part I, Item 1 of this report for additional disclosures.
Product revenues increased by 3% to $1,034.4 million for the three months ended September 30, 2023 compared to $1,007.2 million for the three months ended September 30, 2022. The increase was primarily due to a 33% increase in crude oil equivalent sales volumes driven by the Hibernia Acquisition and Tap Rock Acquisition that closed on August 2, 2023, partially offset by a 23% decrease in oil equivalent pricing, excluding the impact of derivatives.
The following table summarizes our operating expenses for the periods indicated (in thousands, except per Boe amounts):
Three Months Ended September 30,
2023
2022
Change
Percent Change
Operating Expenses:
Lease operating expense
$
94,660
$
45,063
$
49,597
110
%
Midstream operating expense
11,661
9,214
2,447
27
%
Gathering, transportation, and processing
77,540
84,482
(6,942)
(8)
%
Severance and ad valorem taxes
83,437
85,029
(1,592)
(2)
%
Exploration
429
4,355
(3,926)
(90)
%
Depreciation, depletion, and amortization
320,469
212,070
108,399
51
%
Unused commitments
3,942
193
3,749
1,942
%
Bad debt recovery
(24)
(11)
(13)
(118)
%
Transaction costs
28,450
1,814
26,636
1,468
%
General and administrative expense
36,154
37,296
(1,142)
(3)
%
Operating expenses
$
656,718
$
479,505
$
177,213
37
%
Selected Costs ($ per Boe):
Lease operating expense
$
4.37
$
2.78
$
1.59
57
%
Midstream operating expense
0.54
0.57
(0.03)
(5)
%
Gathering, transportation, and processing
3.58
5.21
(1.63)
(31)
%
Severance and ad valorem taxes
3.85
5.24
(1.39)
(27)
%
Exploration
0.02
0.27
(0.25)
(93)
%
Depreciation, depletion, and amortization
14.81
13.08
1.73
13
%
Unused commitments
0.18
0.01
0.17
1,700
%
Transaction costs
1.31
0.11
1.20
1,091
%
General and administrative expense
1.67
2.30
(0.63)
(27)
%
Operating expenses
$
30.33
$
29.57
$
0.76
3
%
Lease operating expense. Our lease operating expense increased $49.6 million, or 110%, to $94.7 million for the three months ended September 30, 2023 from $45.1 million for the three months ended September 30, 2022, and increased 57% on an equivalent basis per Boe. The increase in lease operating expense per Boe is primarily the result of the increased cost of operatorship in New Mexico as a result of the Tap Rock Acquisition as well as other increased costs associated with extreme seasonal weather.
Midstream operating expense. Our midstream operating expense increased $2.5 million, or 27%, to $11.7 million for the three months ended September 30, 2023 from $9.2 million for the three months ended September 30, 2022, and decreased 5% on an equivalent basis per Boe. Midstream operating expense increased due to increases in labor and compression costs. Conversely, midstream operating expense per Boe decreased period over period due to the incremental crude oil equivalent sales volumes associated with the Hibernia Acquisition and Tap Rock Acquisition with no associated midstream operating expense as no midstream assets were acquired in these transactions.
Gathering, transportation, and processing. Gathering, transportation, and processing expense decreased $7.0 million, or 8%, to $77.5 million for the three months ended September 30, 2023 from $84.5 million for the three months ended September 30, 2022, and decreased 31% on an equivalent basis per Boe. 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 contributed to a decrease in gathering, transportation, and processing expense. Furthermore, gathering, transportation, and processing costs are incurred subsequent to the transfer of control for a significant portion of the midstream contracts assumed through the Hibernia Acquisition and Tap Rock Acquisition and are thereby recorded net within oil and natural gas sales. As a result, gathering, transportation, and processing expense per Boe decreased period over period.
Severance and ad valorem taxes. Our severance and ad valorem taxes decreased $1.6 million, or 2%, to $83.4 million for the three months ended September 30, 2023 from $85.0 million for the three months ended September 30, 2022, and decreased 27% on an equivalent basis per Boe. The decrease in severance and ad valorem taxes per Boe is primarily due to an increase in product revenues generated through the Hibernia Acquisition in the state of Texas, which generally levies lower severance and ad valorem tax rates relative to the states of Colorado and New Mexico.
Depreciation, depletion, and amortization. Our depreciation, depletion, and amortization expense increased $108.4 million, or 51%, to $320.5 million for the three months ended September 30, 2023 from $212.1 million for the three months ended September 30, 2022, and increased 13% on an equivalent basis per Boe. The increase in depreciation, depletion, and amortization expense per Boe is due to an increase in the depletion rate driven by an increase in the depletable property base in proportion to proved reserves.
Unused commitments. During the three months ended September 30, 2023 and 2022, we incurred $3.9 million and $0.2 million, respectively, in unused commitments primarily due to certain deficiency payments incurred under minimum volume natural gas and water commitments.
Transaction costs. During the three months ended September 30, 2023, we incurred $28.5 million in legal, advisor, and other costs associated with the Hibernia Acquisition and Tap Rock Acquisition. Please refer to Note 2 - Acquisitions and Divestitures under Part I, Item 1 of this report for additional discussion. During the three months ended September 30, 2022, we incurred $1.8 million in legal, advisor, and other costs associated with other acquisitions.
General and administrative expense. Our general and administrative expense decreased $1.1 million, or 3%, to $36.2 million for the three months ended September 30, 2023 from $37.3 million for the three months ended September 30, 2022, and decreased 27% on an equivalent basis per Boe. The decrease in general and administrative expense is primarily due to a decrease in charitable contributions.
Derivative gain (loss). Our derivative loss for the three months ended September 30, 2023 was $150.7 million as compared to a gain of $9.3 million for the three months ended September 30, 2022. Our derivative loss for the three months ended September 30, 2023 is due to fair market value adjustments caused by increases in expected future market prices relative to our future contracted hedge prices and settlement losses caused by market prices being higher than our current contracted hedge prices at the time of settlement. Our derivative gain for the three months ended September 30, 2022 is due to fair market value adjustments caused by decreases in expected future market prices relative to our future contracted hedge prices and offset by settlement losses caused by market prices being higher than our current contracted hedge prices at the time of settlement. Please refer to Note 9 - Derivatives under Part I, Item 1 of this report for additional discussion.
Interest expense. Our interest expense for the three months ended September 30, 2023 and 2022 was $76.5 million and $7.5 million, respectively. The increase in interest expense is attributable to the debt issued in conjunction with the financing of the Hibernia Acquisition and Tap Rock Acquisition. Average debt outstanding for the three months ended September 30, 2023 and 2022 was $3.5 billion and $400.0 million, respectively. The components of interest expense for the periods presented are as follows (in thousands):
Three Months Ended September 30,
2023
2022
Senior Notes
$
62,797
$
5,000
Credit Facility
8,613
—
Commitment and letter of credit fees under the Credit Facility
1,473
1,329
Amortization of deferred financing costs
3,401
1,139
Finance lease
183
—
Total interest expense
$
76,467
$
7,468
Income tax expense. Our income tax expense for the three months ended September 30, 2023 and 2022 was $29.7 million and $136.3 million, resulting in an effective tax rate of 17.5% and 25.2% on pre-tax income, respectively. Our effective tax rate 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 due to the effect of state income taxes, excess tax benefits and deficiencies on stock-based compensation awards, and tax limitations on compensation of covered individuals. During the three months ended September 30, 2023, income tax expense was additionally impacted by deferred tax benefits from state apportionment changes as a result of the Hibernia Acquisition and Tap Rock Acquisition. During the three months ended September 30, 2022, income tax expense was additionally impacted by changes in valuation allowances and other permanent differences including bargain purchase gain. Please refer to Note 12 - Income Taxes under Part I, Item 1 of this report for additional discussion.
The following table summarizes our product revenues, sales volumes, and average sales prices for the periods indicated:
Nine Months Ended September 30,
2023
2022
Change
Percent Change
Revenues (in thousands):
Crude oil sales(1)
$
1,842,200
$
1,981,015
$
(138,815)
(7)
%
Natural gas sales(2)
226,773
533,581
(306,808)
(57)
%
NGL sales
279,117
459,899
(180,782)
(39)
%
Product revenue
$
2,348,090
$
2,974,495
$
(626,405)
(21)
%
Sales Volumes:
Crude oil (MBbls)
24,612.9
20,666.2
3,946.7
19
%
Natural gas (MMcf)
90,634.7
84,882.7
5,752.0
7
%
NGL (MBbls)
12,062.3
11,660.8
401.5
3
%
Crude oil equivalent (MBoe)(3)
51,781.0
46,474.1
5,306.9
11
%
Average Sales Prices (before derivatives)(4):
Crude oil (per Bbl)
$
74.85
$
95.86
$
(21.01)
(22)
%
Natural gas (per Mcf)
$
2.50
$
6.29
$
(3.79)
(60)
%
NGL (per Bbl)
$
23.14
$
39.44
$
(16.30)
(41)
%
Crude oil equivalent (per Boe)(3)
$
45.35
$
64.00
$
(18.65)
(29)
%
Average Sales Prices (after derivatives)(4):
Crude oil (per Bbl)
$
73.30
$
80.98
$
(7.68)
(9)
%
Natural gas (per Mcf)
$
2.43
$
4.53
$
(2.10)
(46)
%
NGL (per Bbl)
$
23.14
$
36.43
$
(13.29)
(36)
%
Crude oil equivalent (per Boe)(3)
$
44.48
$
53.41
$
(8.93)
(17)
%
_____________________________
(1)Crude oil sales excludes $0.9 million and $0.3 million of oil transportation revenues from third parties, which do not have associated sales volumes, for the nine months ended September 30, 2023 and 2022, respectively.
(2)Natural gas sales excludes $3.5 million and $2.3 million of gas gathering revenues from third parties, which do not have associated sales volumes, for the nine months ended September 30, 2023 and 2022, respectively.
(3)Determined using the ratio of 6 Mcf of natural gas to 1 Bbl of crude oil.
(4)Derivatives economically hedge the price we receive for oil, natural gas, and NGL. For the nine months ended September 30, 2023, the derivative cash settlement loss for oil and natural gas was $38.0 million and $6.9 million, respectively. For the nine months ended September 30, 2022, the derivative cash settlement loss for oil, natural gas, and NGL was $307.6 million, $149.5 million, and $35.1 million, respectively. Please refer to Note 9 - Derivatives under Part I, Item 1 of this report for additional disclosures.
Product revenues decreased by 21% to $2.3 billion for the nine months ended September 30, 2023 compared to $3.0 billion for the nine months ended September 30, 2022. The decrease was primarily due to a 29%, decrease in oil equivalent pricing, excluding the impact of derivatives, partially offset by an 11% increase in crude oil equivalent sales volumes driven by the Hibernia Acquisition and Tap Rock Acquisition that closed on August 2, 2023.
The following table summarizes our operating expenses for the periods indicated (in thousands, except per Boe amounts):
Nine Months Ended September 30,
2023
2022
Change
Percent Change
Operating Expenses:
Lease operating expense
$
191,728
$
122,959
$
68,769
56
%
Midstream operating expense
35,041
22,395
12,646
56
%
Gathering, transportation, and processing
209,765
214,404
(4,639)
(2)
%
Severance and ad valorem taxes
188,242
234,203
(45,961)
(20)
%
Exploration
1,546
6,436
(4,890)
(76)
%
Depreciation, depletion, and amortization
754,558
601,449
153,109
25
%
Abandonment and impairment of unproved properties
—
17,975
(17,975)
(100)
%
Unused commitments
4,696
2,700
1,996
74
%
Bad debt expense (recovery)
559
(7)
566
8,086
%
Transaction costs
60,077
23,766
36,311
153
%
General and administrative expense
106,553
102,682
3,871
4
%
Operating expenses
$
1,552,765
$
1,348,962
$
203,803
15
%
Selected Costs ($ per Boe):
Lease operating expense
$
3.70
$
2.65
$
1.05
40
%
Midstream operating expense
0.68
0.48
0.20
42
%
Gathering, transportation, and processing
4.05
4.61
(0.56)
(12)
%
Severance and ad valorem taxes
3.64
5.04
(1.40)
(28)
%
Exploration
0.03
0.14
(0.11)
(79)
%
Depreciation, depletion, and amortization
14.57
12.94
1.63
13
%
Abandonment and impairment of unproved properties
—
0.39
(0.39)
(100)
%
Unused commitments
0.09
0.06
0.03
50
%
Bad debt expense (recovery)
0.01
—
0.01
100
%
Transaction costs
1.16
0.51
0.65
127
%
General and administrative expense
2.06
2.21
(0.15)
(7)
%
Operating expenses
$
29.99
$
29.03
$
0.96
3
%
Lease operating expense. Our lease operating expense increased $68.7 million, or 56%, to $191.7 million for the nine months ended September 30, 2023 from $123.0 million for the nine months ended September 30, 2022, and increased 40% on an equivalent basis per Boe. The increase in lease operating expense per Boe is primarily the result of the following: (i) the increased cost of operatorship in New Mexico as a result of the Tap Rock Acquisition, (ii) the impact of inflation in areas such as labor, power, and rentals, and (iii) extreme seasonal weather that created prolonged downtime and meaningfully higher costs to bring wells back online.
Midstream operating expense. Our midstream operating expense increased $12.6 million, or 56%, to $35.0 million for the nine months ended September 30, 2023 from $22.4 million for the nine months ended September 30, 2022, and increased 42% on an equivalent basis per Boe. Midstream operating expense increased due to increases in labor and compression costs.
Gathering, transportation, and processing. Gathering, transportation, and processing expense decreased $4.6 million, or 2%, to $209.8 million for the nine months ended September 30, 2023 from $214.4 million for the nine months ended September 30, 2022, and decreased 12% on an equivalent basis per Boe. 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 contributed to a decrease in gathering, transportation, and processing expense. Furthermore, gathering, transportation, and processing costs are incurred subsequent to the transfer of control for a significant portion of the midstream contracts assumed through the Hibernia Acquisition and Tap Rock Acquisition and are thereby recorded net within oil and natural gas sales. As a result, gathering, transportation, and processing expense per Boe decreased period over period.
Severance and ad valorem taxes. Our severance and ad valorem taxes decreased $46.0 million, or 20%, to $188.2 million for the nine months ended September 30, 2023 from $234.2 million for the nine months ended September 30, 2022, and decreased 28% on an equivalent basis per Boe. Severance and ad valorem taxes primarily correlate to revenues, which decreased by 21% for the nine months ended September 30, 2023 when compared to the same period in 2022. Additionally, the incremental decrease in severance and ad valorem taxes per Boe is primarily due to an increase in product revenues generated through the Hibernia Acquisition in the state of Texas, which generally levies lower severance and ad valorem tax rates relative to the states of Colorado and New Mexico.
Depreciation, depletion, and amortization. Our depreciation, depletion, and amortization expense increased $153.1 million, or 25%, to $754.6 million for the nine months ended September 30, 2023 from $601.5 million for the nine months ended September 30, 2022, and increased 13% on an equivalent basis per Boe. The increase in depreciation, depletion, and amortization expense per Boe is due to an increase in the depletion rate driven by an increase in the depletable property base in proportion to proved reserves.
Abandonment and impairment of unproved properties. During the nine months ended September 30, 2022, we incurred $18.0 million in abandonment and impairment of unproved properties due to the Company’s assessment of its locations and replacement of non-core legacy locations with newly acquired locations. No abandonment and impairment of unproved properties was incurred during the nine months ended September 30, 2023.
Unused commitments. During the nine months ended September 30, 2023 and 2022, we incurred $4.7 million and $2.7 million, respectively, in unused commitments primarily due to certain deficiency payments incurred under minimum volume crude oil, natural gas, and water commitments.
Transaction costs. During the nine months ended September 30, 2023, we incurred $60.1 million in short-term financing fees as well as legal, advisor, and other costs associated with acquisitions. Please refer to Note 2 - Acquisitions and Divestitures under Part I, Item 1 of this report for additional discussion. During the nine months ended September 30, 2022, we incurred $23.8 million in legal, advisor, and other costs associated with the Bison Acquisition and other mergers that closed in the fourth quarter of 2021. Transaction costs include zero and $7.6 million of severance payments associated with merger and acquisition activity for the nine months ended September 30, 2023 and 2022, respectively.
General and administrative expense. Our general and administrative expense increased $3.9 million, or 4%, to $106.6 million for the nine months ended September 30, 2023 from $102.7 million for the nine months ended September 30, 2022, and decreased 7% on an equivalent basis per Boe. The increase in general and administrative expense is primarily due to an increase in headcount and an increase in professional services, partially offset by a decrease in charitable contributions. General and administrative expense per Boe decreased due to oil equivalent sales volumes being 11% higher during the nine months ended September 30, as compared to the same period in 2022.
Derivative loss. Our derivative loss for the nine months ended September 30, 2023 and 2022 was $120.6 million and $358.9 million, respectively. Our derivative loss for the nine months ended September 30, 2023 is due to fair market value adjustments caused by increases in expected future market prices relative to our future contracted hedge prices and settlement losses caused by market prices being higher than our current contracted hedge prices at the time of settlement. Our derivative loss for the nine months ended September 30, 2022 is due to settlement losses caused by market prices being higher than our current contracted hedge prices at the time of settlement, partially offset by fair market value adjustments caused by decreases in expected future market prices relative to our future contracted hedge prices. Please refer to Note 9 - Derivatives under Part I, Item 1 of this report for additional discussion.
Interest expense. Our interest expense for the nine months ended September 30, 2023 and 2022 was $92.7 million and $24.7 million, respectively. The increase in interest expense is attributable to the debt issued in conjunction with the financing of the Hibernia Acquisition and Tap Rock Acquisition. Average debt outstanding for the nine months ended September 30, 2023 and 2022 was $2.3 billion and $447.4 million, respectively. The components of interest expense for the periods presented are as follows (in thousands):
Nine Months Ended September 30,
2023
2022
Senior Notes
$
74,081
$
17,521
Credit Facility
8,613
116
Commitment and letter of credit fees under the Credit Facility
Income tax expense. Our income tax expense for the nine months ended September 30, 2023 and 2022 was $139.1 million and $312.2 million, resulting in an effective tax rate of 22.4% and 24.4% on pre-tax income, respectively. Our effective tax rate 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 due to the effect of state income taxes, excess tax benefits and deficiencies on stock-based compensation awards, and tax limitations on compensation of covered individuals. During the nine months ended September 30, 2023, income tax expense was additionally impacted by deferred tax benefits from state apportionment changes as a result of the Hibernia Acquisition and Tap Rock Acquisition. During the nine months ended September 30, 2022, income tax expense was additionally impacted by changes in valuation allowances and other permanent differences including bargain purchase gain. Please refer to Note 12 - Income Taxes under Part I, Item 1 of this report for additional discussion.
Liquidity and Capital Resources
The Company’s primary sources of liquidity include cash flows from operating activities, available borrowing capacity under the Credit Facility, potential proceeds from equity and/or debt capital markets transactions, potential proceeds from sales of assets, and other sources. We may use our available liquidity for operating activities, working capital requirements, capital expenditures, acquisitions, debt reduction, the return of capital to stockholders, and for general corporate purposes.
Our primary source of cash flows from operating activities is the sale of oil, natural gas, and NGL. As such, our cash flows are subject to significant volatility due to changes in commodity prices, as well as variations in our production volumes. The prices for these commodities are driven by a number of factors beyond our control, including global and regional product supply and demand, the impact of inflation and monetary policy, weather, product distribution, refining and processing capacity, regulatory constraints, and other supply chain dynamics, among other factors.
As of September 30, 2023, our liquidity was $1.3 billion, consisting of cash on hand of $95.3 million and $1.2 billion of available borrowing capacity on our Credit Facility. Borrowing capacity under the Credit Facility is primarily based on the value assigned to the proved reserves attributable to our oil and natural gas interests. On August 2, 2023, the Company closed the Hibernia Acquisition and Tap Rock Acquisition and simultaneously entered into an amendment to the Credit Facility that increased our aggregate elected commitments from $1.0 billion to $1.85 billion and increased the borrowing base from $1.85 billion to $3.0 billion. As of the date of filing of this report, the available borrowing capacity on our Credit Facility was $1.8 billion. The next scheduled borrowing base redetermination date is set to occur in May 2024.
The Credit Facility contains customary representations and various affirmative and negative covenants as well as certain financial covenants, including (a) a maximum ratio of the Company’s consolidated indebtedness 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 1.00 and (b) a current ratio, inclusive of the unused commitments then available to be borrowed, to not be less than 1.00 to 1.00. The Company was in compliance with all covenants under the Credit Facility as of September 30, 2023, and through the filing of this report. Please refer to Note 5 - Long-Term Debt and Note 16 - Subsequent Events under Part I, Item 1 of this report for additional information.
Our material short-term cash requirements include: the Vencer Acquisition, operating activities, working capital requirements, capital expenditures, commodity derivative liabilities, dividends, debt interest payments, and payments of contractual obligations. Our material long-term cash requirements from various contractual and other obligations include: debt obligations and related interest payments, firm transportation and minimum volume agreements, taxes, asset retirement obligations, and leases. Please refer to Part I, Item 1 for additional information. Our future capital requirements, both near-term and long-term, will depend on many factors, including, but not limited to, commodity prices, market conditions, our available liquidity and financing, acquisitions and divestitures of oil and gas properties, the availability of drilling rigs and completion crews, the cost of completion services, success of drilling programs, land and industry partner issues, weather delays, the acquisition of leases with drilling commitments, and other factors. We regularly consider which resources, including debt and equity financings, are available to meet our future financial obligations, planned capital expenditures, and liquidity requirements.
Funding for these requirements may be provided by any combination of the sources of liquidity outlined above. We expect our 2023 capital program to be funded by cash flows from operations. Although we cannot provide any assurance, based on our projected cash flows from operations, our cash on hand, and available borrowing capacity on our Credit Facility, we believe that we will have sufficient capital available to fund these requirements through the 12-month period following the filing of this report, and based on current expectations, the long-term.
The following table summarizes our cash flows and other financial measures for the periods indicated (in thousands):
Nine Months Ended September 30,
2023
2022
Net cash provided by operating activities
$
1,395,572
$
1,964,863
Net cash used in investing activities
(4,496,863)
(1,046,584)
Net cash provided by (used in) financing activities
2,428,585
(490,595)
Cash, cash equivalents, and restricted cash
95,428
682,240
Acquisition of oil and natural gas properties, net of cash acquired
(3,711,466)
(330,459)
Exploration and development of oil and natural gas properties
(782,119)
(708,958)
Cash flows provided by operating activities
Net cash provided by operating activities decreased by $569.3 million to $1.4 billion for the nine months ended September 30, 2023 as compared to $2.0 billion for the nine months ended September 30, 2022, which was primarily attributable to decreases in oil equivalent pricing. See Results of Operations above for more information on other factors driving these changes.
Cash flows used in investing activities
Net cash used in investing activities of $4.5 billion for the nine months ended September 30, 2023 was primarily the result of the acquisitions of oil and natural gas properties, net of cash acquired of $3.7 billion and the exploration and development of oil and natural gas properties of $782.1 million.
Net cash used in investing activities of $1.0 billion for the nine months ended September 30, 2022 was primarily the result of the exploration and development of oil and natural gas properties of $709.0 million and the acquisitions of oil and natural gas properties, net of cash acquired of $330.5 million.
Cash flows provided by (used in) financing activities
Net cash provided by financing activities of $2.4 billion for the nine months ended September 30, 2023 was primarily due to proceeds from the issuance of the 2028 Senior Notes and 2031 Senior Notes of $2.7 billion, net borrowings on the Credit Facility of $650 million, partially offset by dividends paid of $511.0 million, the repurchase and retirement of common stock of $320.4 million, the payment of deferred financing costs of $42.9 million, and the payment of employee tax withholdings in exchange for the return of common stock of $13.3 million.
Net cash used in financing activities of $490.6 million for the nine months ended September 30, 2022 was primarily the result of dividends paid of $370.6 million, the optional redemption of the 7.5% Senior Notes due 2026 principal of $100.0 million, and the payment of employee tax withholdings in exchange for the return of common stock of $19.1 million.
Material Commitments
There have been no significant changes from our 2022 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.
Adjusted EBITDAX represents earnings before interest, income taxes, depreciation, depletion, and amortization, exploration expense, and other non-cash and non-recurring charges. Adjusted EBITDAX excludes certain items that we believe affect the comparability of operating results and can exclude items that are generally non-recurring in nature or whose timing and/or amount cannot be reasonably estimated. Adjusted EBITDAX is a non-GAAP measure that we present because we believe it provides useful additional information to investors and analysts, as a performance measure, for analysis of our ability to internally generate funds for exploration, development, acquisitions, and to service debt. We are also subject to financial covenants under our Credit Facility based on adjusted EBITDAX ratios. See Note 5 - Long-Term Debt under Part I, Item 1 of this report for more information about financial covenants under our Credit Facility. In addition, adjusted EBITDAX is widely used by professional research analysts and others in the valuation, comparison, and investment recommendations of companies in the oil and natural gas exploration and production industry. Adjusted EBITDAX should not be considered in isolation or as a substitute for net income, net cash provided by operating activities, or other profitability or liquidity measures prepared under GAAP. Because adjusted EBITDAX excludes some, but not all items that affect net income and may vary among companies, the adjusted EBITDAX amounts presented may not be comparable to similar metrics of other companies.
The following table presents a reconciliation of the GAAP financial measure of net income to the non-GAAP financial measure of adjusted EBITDAX (in thousands):
Three Months Ended September 30,
Nine Months Ended September 30,
2023
2022
2023
2022
Net income
$
139,672
$
405,752
$
481,420
$
966,212
Deferred revenue recognized(1)
(750)
—
(750)
—
Exploration
429
4,355
1,546
6,436
Depreciation, depletion and amortization
320,469
212,070
754,558
601,449
Abandonment and impairment of unproved properties
—
—
—
17,975
Unused commitments
3,942
193
4,696
2,700
Transaction costs
28,450
1,814
60,077
23,766
Stock-based compensation(2)
8,302
10,244
25,577
24,469
Non-recurring general and administrative expense
—
5,481
—
11,816
Derivative (gain) loss
150,661
(9,281)
120,574
358,862
Derivative cash settlements loss
(33,022)
(143,911)
(44,907)
(492,120)
Interest expense
76,467
7,468
92,669
24,650
Interest income(3)
(15,365)
—
(28,172)
—
(Gain) loss on property transactions, net
—
938
254
(15,859)
Income tax expense
29,686
136,338
139,138
312,163
Adjusted EBITDAX
$
708,941
$
631,461
$
1,606,680
$
1,842,519
_________________________
(1)Included as a portion of oil and natural gas sales revenue in the accompanying statements of operations.
(2)Included as a portion of general and administrative expense in the accompanying statements of operations.
(3)Included as a portion of other income in the accompanying statements of operations.
Reconciliation of Free Cash Flow to Cash Provided by Operating Activities
Free cash flow is a supplemental non-GAAP financial measure that is calculated as net cash provided by operating activities before changes in operating assets and liabilities and less exploration and development of oil and natural gas properties, changes in working capital related to capital expenditures, and purchases of carbon offsets. We believe that free cash flow provides additional information that may be useful to investors in evaluating our ability to generate cash from our existing oil and natural gas assets to fund future exploration and development activities and to return cash to stockholders. Free cash flow is a supplemental measure of liquidity and should not be viewed as a substitute for cash flows from operations because it excludes certain required cash expenditures.
The following table presents a reconciliation of the GAAP financial measure of net cash provided by operating activities to the non-GAAP financial measure of free cash flow (in thousands):
Three Months Ended September 30,
Nine Months Ended September 30,
2023
2022
2023
2022
Net cash provided by operating activities
$
519,542
$
710,095
$
1,395,572
$
1,964,863
Add back: changes in operating assets and liabilities, net
118,237
(118,771)
86,173
(260,588)
Cash flow from operations before changes in operating assets and liabilities
637,779
591,324
1,481,745
1,704,275
Less: exploration and development of oil and natural gas properties
(263,170)
(241,772)
(782,119)
(708,958)
Less: changes in working capital related to capital expenditures
(168,799)
2,699
(112,454)
33
Less: purchases of carbon offsets
(213)
—
(5,864)
(7,196)
Free cash flow
$
205,597
$
352,251
$
581,308
$
988,154
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 2022 Form 10-Kfor any recently issued or adopted accounting standards.
Critical Accounting Estimates
Information regarding our critical accounting estimates is contained in Part II, Item 7 of our 2022 Form 10-K.During the three months ended September 30, 2023, there were no significant changes in the application of critical accounting policies.
Item 3. Quantitative and Qualitative Disclosures About Market Risk.
Oil and Natural Gas Price Risk
Our financial condition, results of operations, and capital resources are highly dependent upon the prevailing market prices of oil and natural gas. These commodity prices are subject to wide fluctuations and market uncertainties due to a variety of factors that are beyond our control. Factors influencing oil and natural gas prices include the level of global demand for oil and natural gas, the global supply of oil and natural gas, the establishment of and compliance with production quotas by oil exporting countries, weather conditions which determine the demand for natural gas, the price and availability of alternative fuels, local and global politics, and overall economic conditions. It is impossible to predict future oil and natural gas prices with any degree of certainty. Sustained weakness in oil and natural gas prices may adversely affect our financial condition and results of operations and may also reduce the amount of oil and natural gas reserves that we can produce economically. Any reduction in our oil and natural gas reserves, including reductions due to price fluctuations, can have an adverse effect on our ability to obtain capital for our exploration and development activities. Similarly, any improvements in oil and natural gas prices can have a favorable impact on our financial condition, results of operations, and capital resources.
Commodity Price Derivative Contracts
Our primary commodity risk management objective is to protect the Company’s balance sheet. We periodically 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, basis protection swaps, and puts. Upon settlement of the contract(s), if the relevant market commodity price exceeds our contracted swap price, or the collar’s ceiling strike price, we are required to pay our counterparty the difference for the volume of production associated with the contract. Generally, this payment is made up to 15 business days prior to the receipt of cash payments from our customers. This could have an adverse impact on our cash flows for the period between derivative settlements and payments for revenue earned. 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. Please refer to the Note 9 - Derivatives under Part I, Item 1 of this report for summary derivative activity tables.
Interest Rates
As of September 30, 2023 and on the filing date of this report, we had $650.0 million and zero, respectively, outstanding on our Credit Facility. Borrowings under our Credit Facility bear interest at a fluctuating rate that is tied to an
Alternate Base Rate or Secured Overnight Financing Rate, at our option. Any increases in these interest rates can have an adverse impact on our results of operations and cash flows. As of September 30, 2023 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 derivative activities, we have exposure to financial institutions in the form of derivative transactions. As of September 30, 2023 and on the filing date of this report, our derivative contracts have been executed with 15 and 15 counterparties, respectively, all of which are members of the Credit Facility lender group and have investment grade credit ratings. However, if our counterparties fail to perform their obligations under the contracts, we could suffer financial loss.
We are also subject to credit risk due to concentration of our oil and natural gas receivables with certain significant customers. The inability or failure of our significant customers to meet their obligations to us or their insolvency or liquidation may adversely affect our financial results. We review the credit rating, payment history, and financial resources of our customers, but we do not require our customers to post collateral.
Marketability of Our Production
The marketability of our production depends in part upon the availability, proximity, and capacity of third-party refineries, access to regional trucking, pipeline and rail infrastructure, natural gas gathering systems, and processing facilities. We deliver crude oil and natural gas produced through trucking services, pipelines, and rail facilities that we do not own. The lack of availability or capacity on these systems and facilities could reduce the price offered for our production or result in the shut-in of producing wells or the delay or discontinuance of development plans for properties.
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.
Item 4. Controls and Procedures.
Evaluation of Disclosure Controls and Procedures
Our management, with the participation of our principal executive officer and principal financial officer, evaluated the effectiveness of our disclosure controls and procedures as of September 30, 2023. 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 (15 U.S.C. 78a et seq.) is recorded, processed, summarized, and reported, within the time periods specified in SEC rules and forms. Disclosure controls and procedures include, without limitation, controls and procedures designed to ensure that information required to be disclosed by a company in the reports that it files or submits under the Exchange Act is accumulated and communicated to the company’s management, including its principal executive and principal financial officers and internal audit function, as appropriate, to allow timely decisions regarding required disclosure. Based on the evaluation of our disclosure controls and procedures as of September 30, 2023, our principal executive officer and principal financial officer concluded that, as of such date, our disclosure controls and procedures were effective at the reasonable assurance level.
Management recognizes that any controls and procedures, no matter how well designed and operated, can provide only reasonable assurance of achieving their objectives, and management necessarily applies its judgment in evaluating the cost-benefit relationship of possible controls and procedures. To assist management, we have established an internal audit function to verify and monitor our internal controls and procedures. The Company’s internal control system is supported by written policies and procedures, contains self-monitoring mechanisms, and is audited by the internal audit function. Appropriate actions are taken by management to correct deficiencies as they are identified.
Changes in Internal Control over Financial Reporting
There were no changes in our internal control over financial reporting identified in management’s evaluation pursuant to Rules 13a-15(d) or 15d-15(d) of the Exchange Act during the quarter ended September 30, 2023 that materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.
Information regarding our legal proceedings can be found in Note 6 - Commitments and Contingencies under Part I, Item 1 of this report.
Item 1A. Risk Factors.
Our business faces many risks. Any of the risk factors discussed in this report or our other SEC filings could have a material impact on our business, financial position, or results of operations. Additional risks and uncertainties not presently known to us or that we currently believe to be immaterial may also impair our business operation. For a discussion of our potential risks and uncertainties, see the risk factors in Part I, Item 1A in our 2022 Form 10-K and Exhibit 99.2 to our Current Report on Form 8-K filed with the SEC on June 20, 2023, together with other information in this report and other reports and materials we may subsequently 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, Use of Proceeds, and Issuer Purchases of Equity Securities.
The following table provides information about our purchases of our common stock during the three months ended September 30, 2023:
Total Number of Shares Purchased(2)
Average Price Paid per Share
Total Number of
Shares Purchased as Part of Publicly Announced Plans or Programs(1)
Maximum Dollar value that May Yet be Purchased Plans or Programs (in thousands)(1)
July 1, 2023 - July 31, 2023
741
$
70.98
—
$
479,810
August 1, 2023 - August 31, 2023
7,887
76.05
—
479,810
September 1, 2023 - September 30, 2023
155
83.30
—
479,810
Total
8,783
$
75.75
—
$
479,810
_________________________
(1)In February 2023, we announced that the Board provided authorization for the stock repurchase program pursuant to which we may, from time to time and through December 31, 2024, acquire shares of our common stock in the open market, in privately negotiated transactions, or through block trades, derivative transactions, or purchases made in accordance with the Rule 10b5-1 of the Exchange Act in an amount not to exceed $1.0 billion, exclusive of any fees, commissions, or other expenses related to such repurchases. In June 2023, commensurate with the announcement of the Hibernia Acquisition and Tap Rock Acquisition, the Board reduced the amount of stock authorized for repurchase by the Company under the stock repurchase program from $1.0 billion to $500.0 million. The stock repurchase program does not require any specific number of shares to be acquired and can be modified or discontinued by the Board at any time.
(2)Purchases outside of the stock repurchase program represent shares received by the Company from officers, former officers, executives, and employees for the payment of personal income tax withholding obligations upon the vesting of restricted stock awards.
Item 3. Defaults Upon Senior Securities.
None.
Item 4. Mine Safety Disclosures.
Not applicable.
Item 5. Other Information.
During the three months ended September 30, 2023, no director or officer of the Company adopted or terminated a “Rule 10b5-1 trading arrangement” or “non-Rule 10b5-1 trading arrangement,” as each term is defined in Item 408 of Regulation S-K.
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:
November 7, 2023
By:
/s/ Chris Doyle
Chris Doyle
President and Chief Executive Officer (principal executive officer)
