COVER PAGE
COVER PAGE - USD ($) $ in Billions | 12 Months Ended | ||
Dec. 31, 2021 | Mar. 04, 2022 | Jun. 30, 2021 | |
Cover [Abstract] | |||
Document Type | 10-K | ||
Document Annual Report | true | ||
Document Period End Date | Dec. 31, 2021 | ||
Current Fiscal Year End Date | --12-31 | ||
Document Transition Report | false | ||
Entity File Number | 001-35371 | ||
Entity Registrant Name | Civitas Resources, Inc. | ||
Entity Incorporation, State or Country Code | DE | ||
Entity Tax Identification Number | 61-1630631 | ||
Entity Address, Address Line One | 555 17th Street, | ||
Entity Address, Address Line Two | Suite 3700 | ||
Entity Address, City or Town | Denver, | ||
Entity Address, State or Province | CO | ||
Entity Address, Postal Zip Code | 80202 | ||
City Area Code | (303) | ||
Local Phone Number | 293-9100 | ||
Title of 12(b) Security | Common Stock, par value $0.01 per share | ||
Trading Symbol | CIVI | ||
Security Exchange Name | NYSE | ||
Entity Well-known Seasoned Issuer | Yes | ||
Entity Voluntary Filers | No | ||
Entity Current Reporting Status | Yes | ||
Entity Interactive Data Current | Yes | ||
Entity Filer Category | Large Accelerated Filer | ||
Entity Small Business | false | ||
Entity Emerging Growth Company | false | ||
ICFR Auditor Attestation Flag | true | ||
Entity Shell Company | false | ||
Entity Bankruptcy Proceedings, Reporting Current | true | ||
Entity Public Float | $ 1.2 | ||
Entity Common Stock, Shares Outstanding (in shares) | 84,937,154 | ||
Documents Incorporated by Reference | Portions of the registrant’s definitive proxy statement, will be filed with the Securities and Exchange Commission within 120 days of December 31, 2021, as incorporated by reference into Part III of this report for the year ended December 31, 2021. | ||
Entity Central Index Key | 0001509589 | ||
Amendment Flag | false | ||
Document Fiscal Year Focus | 2021 | ||
Document Fiscal Period Focus | FY |
AUDIT INFORMATION
AUDIT INFORMATION | 12 Months Ended |
Dec. 31, 2021 | |
Audit Information [Abstract] | |
Auditor Name | Deloitte & Touche LLP |
Auditor Location | Denver, Colorado |
Auditor Firm ID | 34 |
CONSOLIDATED BALANCE SHEETS
CONSOLIDATED BALANCE SHEETS - USD ($) $ in Thousands | Dec. 31, 2021 | Dec. 31, 2020 |
Current assets: | ||
Cash and cash equivalents | $ 254,454 | $ 24,743 |
Accounts receivable, net: | ||
Oil, natural gas, and NGL sales | 362,262 | 32,673 |
Joint interest and other | 66,390 | 14,748 |
Prepaid expenses and other | 21,052 | 3,574 |
Inventory of oilfield equipment | 12,386 | 9,185 |
Derivative assets | 3,393 | 7,482 |
Total current assets | 719,937 | 92,405 |
Property and equipment (successful efforts method): | ||
Proved properties | 5,457,213 | 1,056,773 |
Less: accumulated depreciation, depletion, and amortization | (430,201) | (211,432) |
Total proved properties, net | 5,027,012 | 845,341 |
Unproved properties | 688,895 | 98,122 |
Wells in progress | 177,296 | 50,609 |
Other property and equipment, net of accumulated depreciation of $4,742 in 2021 and $3,737 in 2020 | 51,639 | 3,239 |
Total property and equipment, net | 5,944,842 | 997,311 |
Right-of-use assets | 39,885 | 29,705 |
Deferred income tax assets | 22,284 | 60,520 |
Other noncurrent assets | 14,085 | 2,871 |
Total assets | 6,741,033 | 1,182,812 |
Current liabilities: | ||
Accounts payable and accrued expenses | 246,188 | 12,093 |
Production taxes payable | 144,408 | 25,332 |
Oil and natural gas revenue distribution payable | 466,233 | 18,613 |
Lease liability | 18,873 | 12,044 |
Derivative liability | 219,804 | 6,402 |
Asset retirement obligations | 24,000 | 0 |
Total current liabilities | 1,119,506 | 74,484 |
Long-term liabilities: | ||
Senior notes | 491,710 | 0 |
Lease liability | 21,398 | 17,978 |
Ad valorem taxes | 232,147 | 15,069 |
Derivative liability | 19,959 | 1,330 |
Asset retirement obligations | 201,315 | 28,699 |
Total liabilities | 2,086,035 | 137,560 |
Commitments and contingencies (note 6) | ||
Stockholders’ equity: | ||
Preferred stock, $.01 par value, 25,000,000 shares authorized, none outstanding | 0 | 0 |
Common stock, $.01 par value, 225,000,000 shares authorized, 84,572,846 and 20,839,227 issued and outstanding as of December 31, 2021 and 2020, respectively | 4,912 | 4,282 |
Additional paid-in capital | 4,199,108 | 707,209 |
Retained earnings | 450,978 | 333,761 |
Total stockholders’ equity | 4,654,998 | 1,045,252 |
Total liabilities and stockholders’ equity | $ 6,741,033 | $ 1,182,812 |
CONSOLIDATED BALANCE SHEETS (Pa
CONSOLIDATED BALANCE SHEETS (Parenthetical) - USD ($) $ in Thousands | Dec. 31, 2021 | Dec. 31, 2020 |
Statement of Financial Position [Abstract] | ||
Other property and equipment, accumulated depreciation | $ 4,742 | $ 3,737 |
Preferred stock, par value (in dollars per share) | $ 0.01 | $ 0.01 |
Preferred stock, shares authorized (in shares) | 25,000,000 | 25,000,000 |
Preferred stock, shares outstanding (in shares) | 0 | 0 |
Common stock, par value (in dollars per share) | $ 0.01 | $ 0.01 |
Common stock, shares authorized (in shares) | 225,000,000 | 225,000,000 |
Common stock, shares issued (in shares) | 84,572,846 | 84,572,846 |
Common stock, shares outstanding (in shares) | 20,839,227 | 20,839,227 |
CONSOLIDATED STATEMENTS OF OPER
CONSOLIDATED STATEMENTS OF OPERATIONS AND COMPREHENSIVE INCOME - USD ($) shares in Thousands, $ in Thousands | 12 Months Ended | ||
Dec. 31, 2021 | Dec. 31, 2020 | Dec. 31, 2019 | |
Operating net revenues: | |||
Oil, natural gas, and NGL sales | $ 930,614 | $ 218,090 | $ 313,220 |
Operating expenses: | |||
Lease operating expense | 52,391 | 21,957 | 25,249 |
Severance and ad valorem taxes | 65,113 | 3,787 | 25,598 |
Exploration | 7,937 | 596 | 797 |
Depreciation, depletion, and amortization | 226,931 | 91,242 | 76,453 |
Abandonment and impairment of unproved properties | 57,260 | 37,343 | 11,201 |
Unused commitments | 7,692 | 0 | 0 |
Bad debt expense | 607 | 818 | 0 |
Merger transaction costs | 43,555 | 6,676 | 0 |
General and administrative expense (including $15,558, $6,156, and $6,886, respectively, of stock-based compensation) | 65,132 | 34,936 | 39,668 |
Total operating expenses | 608,551 | 229,235 | 207,662 |
Other income (expense): | |||
Derivative gain (loss) | (60,510) | 53,462 | (37,145) |
Interest expense, net | (9,700) | (2,045) | (2,650) |
Gain (loss) on property transactions, net | 1,932 | (1,398) | 1,177 |
Other income (expense) | (2,006) | 4,107 | 127 |
Total other income (expense) | (70,284) | 54,126 | (38,491) |
Income from operations before income taxes | 251,779 | 42,981 | 67,067 |
Income tax benefit (expense) | (72,858) | 60,547 | 0 |
Net income | 178,921 | 103,528 | 67,067 |
Comprehensive income | $ 178,921 | $ 103,528 | $ 67,067 |
Net income per common share: | |||
Basic (in dollars per share) | $ 4.82 | $ 4.98 | $ 3.25 |
Diluted (in dollars per share) | $ 4.74 | $ 4.95 | $ 3.24 |
Weighted-average common shares outstanding | |||
Basic (in shares) | 37,155 | 20,774 | 20,612 |
Diluted (in shares) | 37,746 | 20,912 | 20,681 |
Midstream operating expense | |||
Operating expenses: | |||
Operating expenses | $ 17,426 | $ 14,948 | $ 12,014 |
Gathering, transportation, and processing | |||
Operating expenses: | |||
Operating expenses | $ 64,507 | $ 16,932 | $ 16,682 |
CONSOLIDATED STATEMENTS OF OP_2
CONSOLIDATED STATEMENTS OF OPERATIONS AND COMPREHENSIVE INCOME (Parenthetical) - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2021 | Dec. 31, 2020 | Dec. 31, 2019 | |
Income Statement [Abstract] | |||
General and administrative, stock compensation | $ 15,558 | $ 6,156 | $ 6,886 |
CONSOLIDATED STATEMENTS OF STOC
CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY - USD ($) $ in Thousands | Total | Common Stock | Additional Paid-In Capital | Accumulated Earnings |
Balance at beginning of period (in shares) at Dec. 31, 2018 | 20,543,940 | |||
Balance at beginning of period at Dec. 31, 2018 | $ 863,913 | $ 4,286 | $ 696,461 | $ 163,166 |
Increase (Decrease) in Stockholders' Equity [Roll Forward] | ||||
Restricted common stock issued (in shares) | 146,359 | |||
Restricted stock used for tax withholdings (in shares) | (46,561) | |||
Restricted stock used for tax withholdings | (1,176) | $ (2) | (1,174) | |
Stock-based compensation | 6,886 | 6,886 | ||
Net income | 67,067 | 67,067 | ||
Balance at end of period (in shares) at Dec. 31, 2019 | 20,643,738 | |||
Balance at end of period at Dec. 31, 2019 | 936,690 | $ 4,284 | 702,173 | 230,233 |
Increase (Decrease) in Stockholders' Equity [Roll Forward] | ||||
Restricted common stock issued (in shares) | 259,995 | |||
Restricted stock used for tax withholdings (in shares) | (64,506) | |||
Restricted stock used for tax withholdings | (1,122) | $ (2) | (1,120) | |
Stock-based compensation | 6,156 | 6,156 | ||
Net income | 103,528 | 103,528 | ||
Balance at end of period (in shares) at Dec. 31, 2020 | 20,839,227 | |||
Balance at end of period at Dec. 31, 2020 | 1,045,252 | $ 4,282 | 707,209 | 333,761 |
Increase (Decrease) in Stockholders' Equity [Roll Forward] | ||||
Issuance pursuant to acquisitions (in shares) | 63,397,194 | |||
Issuance pursuant to acquisitions | 3,403,850 | $ 634 | 3,403,216 | |
Restricted common stock issued (in shares) | 415,856 | |||
Restricted stock used for tax withholdings (in shares) | (125,740) | |||
Restricted stock used for tax withholdings | (5,927) | $ (4) | (5,923) | |
Exercise of stock options (in shares) | 46,309 | |||
Exercise of stock options | 1,585 | 1,585 | ||
Stock-based compensation | 15,558 | 15,558 | ||
Issuance of warrants | 77,463 | 77,463 | ||
Cash dividends, $1.16 per share | (61,704) | (61,704) | ||
Net income | 178,921 | 178,921 | ||
Balance at end of period (in shares) at Dec. 31, 2021 | 84,572,846 | |||
Balance at end of period at Dec. 31, 2021 | $ 4,654,998 | $ 4,912 | $ 4,199,108 | $ 450,978 |
CONSOLIDATED STATEMENTS OF ST_2
CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY (Parenthetical) | 12 Months Ended |
Dec. 31, 2021$ / shares | |
Statement of Stockholders' Equity [Abstract] | |
Cash dividends (in dollars per share) | $ 1.16 |
CONSOLIDATED STATEMENTS OF CASH
CONSOLIDATED STATEMENTS OF CASH FLOWS - USD ($) | 12 Months Ended | |||
Dec. 31, 2021 | Dec. 31, 2020 | Dec. 31, 2019 | ||
Cash flows from operating activities: | ||||
Net income | $ 178,921,000 | $ 103,528,000 | $ 67,067,000 | |
Adjustments to reconcile net income to net cash provided by operating activities: | ||||
Depreciation, depletion, and amortization | 226,931,000 | 91,242,000 | 76,453,000 | |
Deferred income tax expense (benefit) | 72,858,000 | (60,520,000) | 0 | |
Abandonment and impairment of unproved properties | 57,260,000 | 37,343,000 | 11,201,000 | |
Stock-based compensation | 15,558,000 | 6,156,000 | 6,886,000 | |
Amortization of deferred financing costs | 1,890,000 | 864,000 | 487,000 | |
Derivative (gain) loss | 60,510,000 | (53,462,000) | 37,145,000 | |
Derivative cash settlements gain (loss) | (275,914,000) | 49,406,000 | 1,691,000 | |
(Gain) loss on property transactions, net | (1,932,000) | 1,398,000 | (1,177,000) | |
Other | 90,000 | (186,000) | 4,399,000 | |
Changes in current assets and liabilities: | ||||
Accounts receivable, net | (100,881,000) | 24,945,000 | (2,688,000) | |
Prepaid expenses and other assets | (3,338,000) | 3,352,000 | (2,415,000) | |
Accounts payable and accrued liabilities | 47,510,000 | (41,278,000) | 28,320,000 | |
Settlement of asset retirement obligations | (4,864,000) | (3,992,000) | (2,722,000) | |
Net cash provided by operating activities | 274,599,000 | 158,796,000 | 224,647,000 | |
Cash flows from investing activities: | ||||
Acquisition of oil and natural gas properties | (1,250,000) | (3,210,000) | (14,087,000) | |
Cash acquired | 223,692,000 | 0 | 0 | |
Exploration and development of oil and natural gas properties | (151,500,000) | (60,149,000) | (242,487,000) | |
Proceeds from sale of oil and natural gas properties | 0 | 0 | 1,757,000 | |
Proceeds from (additions to) other property and equipment | 2,393,000 | |||
Proceeds from (additions to) other property and equipment | (440,000) | (341,000) | ||
Proceeds from note receivable | 212,000 | 0 | 0 | |
Net cash provided by (used in) investing activities | 73,547,000 | (63,799,000) | (255,158,000) | |
Cash flows from financing activities: | ||||
Proceeds from credit facility | 155,000,000 | 45,000,000 | 55,000,000 | |
Payments to credit facility | (589,000,000) | (125,000,000) | (25,000,000) | |
Proceeds from issuance of senior notes | 400,000,000 | 0 | 0 | |
Proceeds from exercise of stock options | 1,585,000 | 0 | 0 | |
Dividends paid | (60,780,000) | 0 | 0 | |
Payment of employee tax withholdings in exchange for the return of common stock | (5,927,000) | (1,122,000) | (1,176,000) | |
Deferred financing costs | (19,292,000) | (23,000) | (220,000) | |
Principal payments on finance lease obligations | (21,000) | (102,000) | 0 | |
Net cash provided by (used in) financing activities | (118,435,000) | (81,247,000) | 28,604,000 | |
Net change in cash, cash equivalents, and restricted cash | 229,711,000 | 13,750,000 | (1,907,000) | |
Cash, cash equivalents, and restricted cash: | ||||
Beginning of period | 24,845,000 | 11,095,000 | 13,002,000 | |
End of period | 254,556,000 | 24,845,000 | 11,095,000 | |
Supplemental cash flow disclosure: | ||||
Non-cash investing activities | [1],[2] | 4,911,186,000 | 0 | 0 |
Noncash financing activities | [2],[3] | 3,481,312,000 | 0 | 0 |
Cash paid for interest, net of capitalization | [2] | 1,829,000 | 1,546,000 | 4,110,000 |
Cash paid for income taxes | [2] | 14,000,000 | 0 | 0 |
Receivables exchanged for additional interests in oil and natural gas properties | [2] | 0 | 8,299,000 | 0 |
Changes in working capital related to drilling expenditures | [2] | (128,977,000) | $ 2,795,000 | $ 30,354,000 |
HighPoint | ||||
Supplemental cash flow disclosure: | ||||
Non-cash investing activities | 542,600,000 | |||
Noncash financing activities | 374,900,000 | |||
Extraction | ||||
Supplemental cash flow disclosure: | ||||
Non-cash investing activities | 2,109,500,000 | |||
Noncash financing activities | 1,844,100,000 | |||
Crestone Peak | ||||
Supplemental cash flow disclosure: | ||||
Non-cash investing activities | 2,259,100,000 | |||
Noncash financing activities | $ 1,262,200,000 | |||
[1] | (2) Includes $542.6 million, $2,109.5 million, and $2,259.1 million in non-cash property additions related to the HighPoint, Extraction, and Crestone Peak mergers, respectively. | |||
[2] | (1) Refer to Note 3 - Leases in the notes to the consolidated financial statements for discussion of right-of-use assets obtained in exchange for lease liabilities. | |||
[3] | (3) Includes $374.9 million, $1,844.1 million, and $1,262.2 million in non-cash consideration related to the HighPoint, Extraction, and Crestone Peak mergers, respectively. |
SUMMARY OF SIGNIFICANT ACCOUNTI
SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES | 12 Months Ended |
Dec. 31, 2021 | |
Accounting Policies [Abstract] | |
SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES | SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES Description of Operations Civitas is an independent Denver-based exploration and production company focused on the acquisition, development, and production of oil and associated liquids-rich natural gas in the Rocky Mountain region, primarily in the Wattenberg Field of the DJ Basin. Basis of Presentation The consolidated financial statements include the accounts of the Company. All significant intercompany balances and transactions have been eliminated in consolidation. The consolidated financial statements included herein were prepared from the records of the Company in accordance with GAAP, the instructions to Form 10-K, and Regulation S-X. Additionally, certain prior period amounts have been reclassified to conform to current period presentation in the accompanying financial statements. During the current year, the Company is separately presenting Production taxes payable on the accompanying balance sheets. Accordingly, prior year amounts have been reclassified from Accounts payable and accrued expenses to conform to current year presentation. In connection with the preparation of the consolidated financial statements, the Company evaluated subsequent events after the balance sheet date of December 31, 2021, through the filing date of this report. Use of Estimates The preparation of the consolidated financial statements in conformity with GAAP requires us to make estimates and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses, as well as the disclosure of contingent assets and liabilities and commitments as of the date of our financial statements. Actual results could differ from those estimates. Industry Segment and Geographic Information The Company operates in one industry segment, which is the development and production of oil, natural gas, and NGLs, and all of the Company's operations are conducted in the continental United States. Cash and Cash Equivalents The Company considers all highly liquid investments with original maturity dates of three months or less to be cash equivalents. The carrying value of cash and cash equivalents approximate fair value due to the short-term nature of these instruments. The Company maintains cash balances in excess of federal deposit insurance limits as of December 31, 2021 and 2020, potentially subjecting the Company to a concentration of credit risk. To mitigate this risk, we maintain our cash and cash equivalents in the form of money market and checking accounts with financial institutions that we believe are creditworthy and are also lenders under our Credit Facility. The following table provides a reconciliation of cash, cash equivalents, and restricted cash reported within the accompanying balance sheets, which sums to the total of such amounts shown in the accompanying statements of cash flows (in thousands): As of December 31, 2021 2020 2019 Cash and cash equivalents $ 254,454 $ 24,743 $ 11,008 Restricted cash (1) 102 102 87 Total cash, cash equivalents, and restricted cash $ 254,556 $ 24,845 $ 11,095 ____________________________ (1) Included in other noncurrent assets and consists of funds for road maintenance and repairs. Accounts Receivable The Company’s accounts receivable primarily consists of receivables due from purchasers of the Company's oil, natural gas, and NGL production and from joint interest owners on properties the Company operates. The Company is exposed to credit risk in the event of nonpayment by the purchasers of its production and/or joint interest owners on the properties it operates, nearly all of which are concentrated in energy-related industries. The Company continuously evaluates the creditworthiness of the Company's purchasers and joint interest owners on the properties it operates. Generally, the Company’s oil, natural gas, and NGLs receivables are collected within one The Company does not believe the loss of any single purchaser of its production would materially impact its financial position or results of operations, as oil, natural gas, and NGLs are products with well-established and highly liquid markets. For the periods presented below, the following purchasers of the Company's production accounted for more than 10% of the Company's revenue as follows: Year Ended December 31, 2021 2020 2019 Customer A 43 % 77 % 82 % Customer B 15 % — % — % Customer C 13 % 9 % 6 % Inventory of Oilfield Equipment Inventory of oilfield equipment consists of material and supplies to be used in connection with the Company’s operations. These inventories are recorded and relieved using the weighted average cost method and are stated at the lower of cost or net realizable value, which approximates fair value. Property and Equipment Proved Properties. The Company accounts for its oil and natural gas properties under the successful efforts method of accounting. Under this method, the costs of development wells are capitalized to proved properties whether those wells are successful or unsuccessful. Capitalized drilling and completion costs, including lease and well equipment, intangible development costs, and operational support facilities are depleted using the units-of-production method based on estimated proved developed reserves. Proved leasehold costs are also depleted; however, the units-of-production method is based on estimated total proved reserves. The computation of depletion expense takes into consideration restoration, dismantlement, and abandonment costs as well as the anticipated proceeds from salvaging equipment. Because all of our proved properties are currently located in a single field, we apply depletion on a single field basis. During the years ended December 31, 2021, 2020, and 2019, the Company incurred depletion expense of $212.5 million, $82.6 million, and $69.3 million, respectively. The Company assesses proved properties for impairment whenever events or circumstances indicate that their carrying value may not be recoverable. If carrying values exceed undiscounted future net cash flows, impairment is measured and recorded at fair value. Because there usually is a lack of quoted market prices for proved properties, the Company estimates the fair value using valuation techniques that convert estimated future net cash flows to a single discounted amount. Significant inputs and assumptions to this estimation include, but are not limited to, reserves volumes, future operating and development costs, future commodity prices, inclusive of applicable differentials, and a market-based weighted average cost of capital rate. The expected future cash flows used for impairment reviews include future production volumes associated with proved developed producing reserves and risk-adjusted proved undeveloped reserves, and when needed, probable and possible reserves. The partial sale of a proved property within an existing field is accounted for as a normal retirement and no net gain or loss on divestiture activity is recognized as long as such treatment does not significantly affect the units-of-production depletion rate. The sale of a partial interest in an individual proved property is accounted for as a recovery of cost. A net gain or loss on divestiture activity is recognized in the accompanying statements of operations for all other sales of proved properties. As of December 31, 2021, the net book value of the Company's midstream assets was $276.1 million in the accompanying balance sheets. Depreciation on the Company's midstream assets is calculated using the straight-line method over the estimated useful lives of the assets and properties they serve, which is approximately 30 years. Unproved Properties. Unproved properties consist of the costs to acquire undeveloped leases and are not subject to depletion until they are transferred to proved properties. Leasehold costs are transferred to proved properties on an ongoing basis as the properties to which they relate are evaluated and proved reserves established. Additional costs not subject to depletion include costs associated with development wells in progress or awaiting completion at year-end. These costs are transferred into costs subject to depletion on an ongoing basis as these wells are completed and proved reserves are established or confirmed. Unproved properties are routinely evaluated for continued capitalization or impairment. On a quarterly basis, management assesses undeveloped leasehold costs for impairment by considering, among other things, remaining lease terms, future drilling plans and capital availability to execute such plans, commodity price outlooks, recent operational results, reservoir performance and geology, and estimated acreage value based on prices received for similar, recent acreage transactions by the Company or other market participants. Changes in our assumptions of the estimated nonproductive portion of our undeveloped leases could result in additional impairment expense. During the years ended December 31, 2021, 2020, and 2019, the Company incurred $57.3 million, $37.3 million, and $11.2 million, respectively, in abandonment and impairment of unproved properties. The partial sale of unproved property is accounted for as a recovery of cost when there is uncertainty of the ultimate recovery of the cost applicable to the interest retained. Exploratory. Exploratory geological and geophysical, including exploratory seismic studies, and the costs of carrying and retaining unproved acreage are expensed as incurred. Under the successful efforts method of accounting, exploratory well costs are capitalized pending further evaluation of whether economically recoverable reserves have been found. If economically recoverable reserves are found, exploratory well costs will be capitalized as proved properties and will be accounted for following the successful efforts method of accounting described above. If economically recoverable reserves are not found, exploratory well costs are expensed as dry holes. The application of the successful efforts method of accounting requires judgment to determine the proper designation of wells as either development or exploratory, which will ultimately determine the proper accounting treatment of costs of dry holes. Once a well is drilled, the determination that economic proved reserves have been discovered may take considerable time and judgment. Exploratory dry hole costs are included in the cash flows from investing activities section as part of exploration and development of oil and natural gas properties within the accompanying statements of cash flows. Oil and Natural Gas Reserves. The successful efforts method of accounting outlined above inherently relies on the estimation of proved oil and natural gas reserves. Reserve quantities and the related estimates of future net cash flows are critical inputs in our calculation of units-of-production depletion and our evaluation of proved and unproved properties for impairment. The process of estimating and evaluating crude oil and natural gas reserves is complex, requiring the evaluation of available geological, geophysical, engineering and economic data to estimate underground accumulations of oil and natural gas that cannot be precisely measured. Consequently, the Company engages a third-party petroleum consultant to prepare our estimates of oil and natural gas reserves. Significant inputs and engineering assumptions used in developing the estimates of proved oil and natural gas reserves include reserves volumes, future operating and development costs, historical commodity prices, and the Company’s ability to convert proved undeveloped reserves to producing properties within five years of their initial proved booking. The data for a given property may also change substantially over time as a result of numerous factors, including additional development activity, evolving production history and a continual reassessment of the viability of production under changing economic conditions. As a result, revisions in existing reserve estimates occur. We cannot predict the amounts or timing of such future revisions. If such revisions are significant, they could significantly affect future amortization of capitalized costs and result in impairment of proved property. Other Property and Equipment Other property and equipment such as office furniture and equipment, buildings, and computer hardware and software are recorded at cost. Cost of renewals and improvements that substantially extend the useful lives of the assets are capitalized. Maintenance and repair costs are expensed as incurred. Depreciation is calculated using the straight-line method over the estimated useful lives of the assets, which range from three Leases The Company determines if an arrangement is representative of a lease at contract inception. Right-of-use (“ROU”) assets represent our right to use the underlying assets for the lease term and the corresponding lease liabilities represent our obligations to make lease payments arising from the leases. Operating and finance lease ROU assets and liabilities are recognized at the lease commencement date based on the present value of the lease payments over the lease term. When evaluating a contract, the Company applies certain judgments to determine, among other factors, lease classification as either operating or financing, lease term, and discount rate. The terms of certain of our leases include options to extend or terminate the lease, only when we can ascertain that it is reasonably certain we will exercise that option, as well as evergreen periods for which the penalties associated with termination are considered to be significant. Leases with an initial term of one year or less are not recorded on the balance sheets. As the Company does not have any leases with an implicit interest rate that can be readily determined, we utilize our incremental borrowing rate based on information available at the lease commencement date in determining the present value of lease payments. We determine our incremental borrowing rate at the lease commencement date using our Credit Facility benchmark rate and make adjustments for facility utilization and lease term. Subsequent measurement, as well as presentation of expenses and cash flows, will depend upon the classification of the lease as either a finance or operating lease. Please refer to Note 3 - Leases for additional discussion. Carbon Offsets The Company periodically purchases carbon offsets and renewable energy credits as a means to offset carbon emissions generated by its operations that could not otherwise be reduced or eliminated. Commensurate with their use, purchased carbon offsets and renewable energy credits are initially capitalized at cost as an intangible asset within other noncurrent assets on the accompanying balance sheets. Subsequently, capitalized carbon offsets and renewable energy credits are expensed when applied to the Company's carbon emissions through depletion, depreciation, and amortization expense on the accompanying statements of operations. Purchased carbon offsets and renewable energy credits expected to be utilized within the next 12 months are presented as short-term within prepaid expenses and other on the accompanying balance sheets. Deferred Financing Costs Deferred financing costs include origination, legal, and other fees incurred to issue debt or amend existing credit facilities. Deferred financing costs related to the Credit Facility are capitalized to prepaid expenses and other and other noncurrent assets on the accompanying balance sheets and amortized to interest expense, net on the accompanying statements of operations on a straight-line basis over the life of the Credit Facility. Deferred financing costs related to senior notes are capitalized within senior notes on the accompanying balance sheets and amortized to interest expense, net on the accompanying statements of operations using the effective interest method over the life of the respective borrowings. Asset Retirement Obligations The Company recognizes an asset retirement obligation at fair value based on the present value of costs expected to be incurred in connection with the future abandonment of its oil and natural gas properties, including wells and facilities, in accordance with applicable regulatory requirements. This obligation, and the corresponding capitalized cost recorded to proved properties, is recorded at the time assets are acquired, a well is completed and begins production, or a facility is constructed. The Company recognizes a periodic expense in connection with the accretion of the discounted asset retirement obligation over the remaining estimated economic lives of the respective long-lived assets. The accretion expense is recorded as a component of depreciation, depletion, and amortization in our accompanying statements of operations. If the fair value of the estimated asset retirement obligation changes, an adjustment is recorded to both the asset retirement obligation and the corresponding capitalized cost recorded to proved properties. The recognition of an asset retirement obligation requires management to make various assumptions informed by historical experience and applicable regulatory requirements including estimated plugging and abandonment costs, economic lives, inflation rates, and the Company's credit-adjusted risk-free rate. Cash paid to settle asset retirement obligations is included in the cash flows from operating activities section of the accompanying statements of cash flows. Please refer to Note 10 – Asset Retirement Obligations for a reconciliation of the Company’s total asset retirement obligation liability as of December 31, 2021 and 2020. Derivatives The Company periodically enters into commodity price derivative instruments to mitigate a portion of its exposure to potentially adverse market changes in commodity prices for its expected future oil, natural gas, and NGL production and the associated impact on cash flows. These instruments typically include commodity price swaps and collars, as well as, basis differential and roll differential swaps. The oil instruments are indexed to NYMEX WTI prices, natural gas instruments are indexed to NYMEX HH and CIG prices, and NGL instruments are indexed to OPIS prices, all of which have a high degree of historical correlation with actual prices received by the Company, before differentials. Presently, our derivative contracts have been executed with 10 counterparties, all but one of which are members of our Credit Facility syndicate. We enter into contracts with counterparties whom we believe are well capitalized and have certain minimum investment grade senior unsecured debt ratings. However, if our counterparties fail to perform their obligations under the contracts, we could suffer financial loss. Commodity price derivative instruments are measured at fair value and are included in the accompanying balance sheets as derivative assets and liabilities, with the exception of derivative instruments that meet the “normal purchase normal sale” exclusion. All commodity price derivative instruments are entered into for other-than-trading purposes. The Company does not designate its commodity price derivative contracts as hedging instruments. Accordingly, the Company reflects changes in the fair value of its commodity price derivative instruments in its accompanying statements of operations as they occur. We measure the fair value of our commodity price derivative instruments based upon a pricing model that utilizes market-based inputs, including, but not limited to, contractual price of the underlying position, current market prices, crude oil and natural gas forward curves, discount rates, volatility factors, and nonperformance risk. As of December 31, 2021 and 2020, all derivative instruments held by the Company were subject to master netting arrangements with various financial institutions. In general, the terms of the Company’s agreements provide for offsetting of amounts payable or receivable between it and the counterparty, at the election of both parties, for transactions that settle on the same date and in the same currency. The Company’s agreements also provide that in the event of an early termination, the counterparties have the right to offset amounts owed or owing under that and any other agreement with the same counterparty. The Company’s accounting policy is to not offset these positions in its accompanying balance sheets. Gains and losses on derivatives are included within the cash flows from operating activities section of the accompanying statements of cash flows. Please refer to Note 9 - Derivatives for additional discussion. Revenue Recognition Revenue is recognized 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. We consider 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. Oil sales. Under the Company’s crude purchase and marketing contracts, the Company typically delivers production at the wellhead, or other contractually agreed-upon delivery points, and collects an agreed-upon index price, net of pricing differentials. In this scenario, the Company recognizes revenue when control of its oil production transfers to the purchaser at the wellhead, or other contractually agreed-upon delivery point, at the net contracted price received. Natural gas and NGL sales . Under the Company's natural gas processing contracts, the Company delivers natural gas to a midstream processing entity at the wellhead, inlet of the midstream processing entity’s system, or other contractually agreed-upon delivery points. The delivery points are specified within each contract, and the point at which control transfers varies between the inlet and tailgate of the midstream processing facility. The midstream processing entity gathers and processes the natural gas and remits proceeds to the Company for the resulting sales of NGLs and residue gas. For the contracts where the Company maintains control through the tailgate of the midstream processing facility, the Company recognizes revenue on a gross basis, with gathering, transportation, and processing fees presented as an expense in the accompanying statements of operations. Alternatively, for those contracts where the Company relinquishes control at the inlet of the midstream processing facility, the Company recognizes natural gas and NGL revenues based on the contracted amount of the proceeds received from the midstream processing entity and, as a result, the Company recognizes revenue on a net basis. In certain natural gas processing agreements, the Company may elect to take its residue gas and/or NGLs in-kind at the tailgate of the midstream entity’s processing plant and subsequently market the product. Through the marketing process, the Company delivers product to the third-party purchaser at a contractually agreed-upon delivery point and receives a specified index price from the third-party purchaser. In this scenario, the Company recognizes revenue when the control transfers to the third-party purchaser at the delivery point based on the index price received from the third-party purchaser. The gathering and processing expense attributable to the natural gas processing contracts, as well as any transportation expense incurred to deliver the product to the third-party purchaser, are presented as gathering, transportation, and processing expense in the consolidated statements of operations. As noted above, 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. As a result, Company records a revenue accrual based on an estimate of the volumes delivered at estimated prices as determined by the applicable marketing agreements. The Company estimates its sales volumes based on Company-measured volume readings. 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 year ended December 31, 2021, revenue recognized in the reporting period related to performance obligations satisfied in prior reporting periods was insignificant. At December 31, 2021 and 2020, the Company's receivables from contracts with customers were $362.3 million and $32.7 million, respectively. As further described in Note 6 - Commitments and Contingencies , two contracts have an additional aspect of variable consideration related to the minimum volume commitments (“MVCs”) as specified in the agreement. On an on-going basis, the Company performs an analysis of expected risk adjusted production applicable to the agreements based on approved production plans to determine if liquidated damages are probable. As of December 31, 2021, the Company believes that the volumes delivered will be in excess of the MVCs required then and for the upcoming approved production plan. As a result of this analysis, to date, no variable consideration related to potential liquidated damages has been considered in the transaction price for the related agreements. Revenue attributable to each identified revenue stream is disaggregated below (in thousands): Year Ended December 31, 2021 2020 2019 Operating net revenues: Oil sales $ 614,811 $ 174,536 $ 268,865 Natural gas sales 144,708 24,243 28,296 NGL sales 171,095 19,311 16,059 Oil, natural gas, and NGL sales $ 930,614 $ 218,090 $ 313,220 Stock-Based Compensation The Company recognizes stock-based compensation based on the grant-date fair value of the equity instruments awarded. Stock-based compensation expense is recognized in the financial statements on a straight-line basis over the requisite service period for the entire award. The Company accounts for forfeitures of stock-based compensation awards as they occur. Please refer to Note 7 - Stock-Based Compensation for additional discussion. Income Taxes The Company accounts for income taxes under the asset and liability method, which requires recognition of deferred tax assets and liabilities for the expected future tax consequences of events that have been included in the balance sheet or tax returns. Deferred income tax assets and liabilities are measured using enacted tax rates applicable to the future period when those temporary differences are expected to be recovered or settled. If we determine that it is more likely than not that some portion or all of the deferred income tax assets will not be realized, a valuation allowance is recorded, thereby reducing the deferred income tax assets to what is considered to be realizable. The Company recognizes the tax benefit from an uncertain tax position only if it is more likely than not that the tax position will be sustained on examination by the taxing authorities based on the technical merits of the position. The Company's policy is to recognize interest and penalties related to uncertain tax positions in income tax expense. There were no uncertain tax positions during any period presented. The tax returns for 2020, 2019, and 2018 are still subject to audit by the Internal Revenue Service. Please refer to Note 12 - Income Taxes for additional discussion. Earnings Per Share The Company uses the treasury stock method to determine the effect of potentially dilutive instruments. Please refer to Note 11 - Earnings Per Share for additional discussion. Acreage Exchanges From time to time, we enter into acreage exchanges in order to consolidate our core acreage positions, enabling us to have more control over the timing of development activities, achieve higher working interests and provide us the ability to drill longer lateral length wells within those core areas. We account for our nonmonetary acreage exchanges in accordance with the guidance prescribed by Accounting Standards Codification ( “ ASC ” ) 845, Nonmonetary Transactions . For those exchanges that lack commercial substance, we record the acreage received at the net carrying value of the acreage surrendered to obtain it. For those acreage exchanges that are deemed to have commercial substance, we record the acreage received at fair value, with a related gain or loss recognized in earnings, in accordance with ASC 820, Fair Value Measurement . During the year ended December 31, 2021, the Company completed non-monetary acreage trades of certain oil and gas properties properties located in Weld County, Colorado. These trades were recorded at carryover basis with no gain or loss recognized. Business Combinations As part of our business strategy, we regularly pursue the acquisition of oil and natural gas properties. We utilize the acquisition method to account for acquisitions of businesses. Pursuant to this method, we allocate the cost of the acquisition, or purchase price, to assets acquired and liabilities assumed based on fair values as of the acquisition date. Please refer to Note 2 - Acquisitions and Divestitures for additional discussion. Fair Value of Financial Instruments The Company’s financial instruments consist of cash and cash equivalents, accounts receivables, and accounts payable are carried at cost, which approximates fair value due to the short-term maturity of these instruments. As discussed above, the Company's commodity price derivative instruments are recorded at fair value. The Company’s Senior Notes, as defined in Note 5 – Long-Term Debt , are recorded at cost, net of any unamortized deferred financing costs, and their respective fair values are disclosed in Note 8 – Fair Value Measurement s. The recorded value of the Company’s Credit Facility approximates its fair value as it bears interest at a floating rate that approximates a current market rate. The Company’s warrants were recorded at fair value upon issuance, with no recurring fair value measurement required. Considerable judgment is required to develop estimates of fair value. The estimates provided are not necessarily indicative of the amounts the Company would realize upon the sale or refinancing of such instruments. Please refer to Note 8 - Fair Value Measurement s for additional discussion. Recently Issued and Adopted Accounting Standards In June 2016, the FASB issued Update No. 2016-13, Financial Instruments - Credit Losses (Topic 326): Measurement of Credit Losses on Financial Instruments . The update changes the impairment model for most financial assets and certain other instruments, including trade and other receivables, and requires entities to use a new forward-looking expected loss model that will result in the earlier recognition of allowances for losses. The amended standard was adopted using a modified retrospective approach on January 1, 2020. The Company considered past events (including historical experience), current economic and industry conditions, reasonable and supportable forecasts, and lives of receivable balances and loss experience. Historically and currently, the Company's credit losses on oil and natural gas sales receivables and joint interest receivables have not been significant, and the adoption of this standard did not have a material impact on its consolidated financial statements. As of December 31, 2021 and 2020 the Company had an allowance of $3.7 million and $0.4 million, respectively, established against joint interest receivables. In August 2018, the FASB issued Update No. 2018-13, Disclosure Framework - Changes to the Disclosure Requirements for Fair Value Measurement . The objective of this update is to improve the effectiveness of fair value measurement disclosures. The new standard was adopted on January 1, 2020. The standard only impacted the form of the Company's disclosures. In March 2020, the FASB issued Update No. 2020-04, Reference Rate Reform (Topic 848), which provides temporary optional guidance to companies impacted by the transition away from the LIBOR. The amendment provides certain expedients and exceptions to applying GAAP in order to lessen the potential accounting burden when contracts, hedging relationships, and other transactions that reference LIBOR as a benchmark rate are modified. Further, in January 2021, the FASB issued Update No. 2021-01, Reference Rate Reform (Topic 848), which clarifies the scope of Topic 848 so that derivatives affected by the discounting transition are e |
ACQUISITIONS AND DIVESTITURES
ACQUISITIONS AND DIVESTITURES | 12 Months Ended |
Dec. 31, 2021 | |
Business Combination and Asset Acquisition [Abstract] | |
ACQUISITIONS AND DIVESTITURES | ACQUISITIONS AND DIVESTITURES HighPoint Merger On April 1, 2021, Civitas completed its previously announced acquisition of HighPoint Resources Corporation, a Delaware corporation (“HighPoint”), pursuant to the terms of HighPoint’s prepackaged plan of reorganization under Chapter 11 of the United States Bankruptcy Code (the “Prepackaged Plan”), which was confirmed by the U.S. Bankruptcy Court for the District of Delaware on March 18, 2021 pursuant to a confirmation order, and went effective on April 1, 2021 (the “HighPoint Merger”). The Prepackaged Plan implemented the merger and restructuring transactions in accordance with the Agreement and Plan of Merger, dated as of November 9, 2020 (the “HighPoint Merger Agreement”), by and among Civitas, HighPoint and Boron Merger Sub, Inc., a wholly-owned subsidiary of Civitas (“Merger Sub”). Pursuant to the Prepackaged Plan and the HighPoint Merger Agreement, at the effective time of the HighPoint Merger (the “HighPoint Effective Time”) and the effective date under the Prepackaged Plan, Merger Sub merged with and into HighPoint, with HighPoint continuing as the surviving corporation and wholly-owned subsidiary of Civitas. At the HighPoint Effective Time, each eligible share of common stock, par value $0.001 per share, of HighPoint issued and outstanding immediately prior to the HighPoint Effective Time was automatically converted into the right to receive 0.11464 shares of common stock, par value $0.01 per share, of Civitas (“Civitas Common Stock”), with cash paid in lieu of the issuance of any fractional shares. As a result, Civitas issued 487,952 shares of Civitas Common Stock to former HighPoint stockholders. Concurrently with the HighPoint Merger and pursuant to the Prepackaged Plan, and in exchange for the $625.0 million in aggregate principal amount outstanding of 7.0% Senior Notes due 2022 of HighPoint Operating Corporation (“HighPoint OpCo”) and 8.75% Senior Notes due 2025 of HighPoint OpCo (collectively, the “HighPoint Senior Notes”), Civitas issued to all holders of HighPoint Senior Notes an aggregate of (i) 9,314,214 shares of Civitas Common Stock and (ii) $100.0 million aggregate principal amount of 7.5% Senior Notes due 2026 (“7.5% Senior Notes”). Please refer to Note 5 - Long-term Debt for further discussion of the 7.5% Senior Notes. Immediately after the HighPoint Effective Time, in connection with the HighPoint Merger, Civitas entered into the Second Amendment, dated April 1, 2021, to the Credit Facility. Please refer to Note 5 - Long-term Debt for further discussion. The following tables present the HighPoint Merger consideration and purchase price allocation of the assets acquired and the liabilities assumed in the HighPoint Merger: Merger Consideration (in thousands, except per share amount) Shares of Civitas Common Stock issued to existing holders of HighPoint Common Stock (1) 488 Shares of Civitas Common Stock issued to existing holders of HighPoint Senior Notes 9,314 Total additional shares of Civitas Common Stock issued as merger consideration 9,802 Closing price per share of Civitas Common Stock (2) $ 38.25 Merger consideration paid in shares of Civitas Common Stock $ 374,933 Aggregate principal amount of the 7.5% Senior Notes 100,000 Total merger consideration $ 474,933 _________________________ (1) Based on the number of shares of HighPoint Common Stock issued and outstanding as of April 1, 2021 and the conversion ratio of 0.11464 per share of Civitas Common Stock. (2) Based on the closing stock price of Civitas Common Stock on April 1, 2021. Purchase Price Allocation (in thousands) Assets Acquired Cash and cash equivalents $ 49,827 Accounts receivable - oil and natural gas sales 26,343 Accounts receivable - joint interest and other 9,161 Prepaid expenses and other 3,608 Inventory of oilfield equipment 4,688 Proved properties 539,820 Other property and equipment, net of accumulated depreciation 2,769 Right-of-use assets 4,010 Deferred income tax assets 110,513 Other noncurrent assets 797 Total assets acquired $ 751,536 Liabilities Assumed Accounts payable and accrued expenses $ 51,088 Oil and natural gas revenue distribution payable 20,786 Lease liability 4,010 Derivative liability 18,500 Current portion of long-term debt 154,000 Ad valorem taxes 3,746 Asset retirement obligations 24,473 Total liabilities assumed 276,603 Net assets acquired $ 474,933 The HighPoint Merger was accounted for under the acquisition method of accounting for business combinations. Accordingly, we conducted assessments of the net assets acquired and recognized amounts for identifiable assets acquired and liabilities assumed at their estimated acquisition date fair values, while transaction and integration costs associated with the acquisition were expensed as incurred. The fair value measurements of assets acquired and liabilities assumed are based on inputs that are not observable in the market, and therefore represent Level 3 inputs. The fair values of crude oil and natural gas properties and asset retirement obligations were measured using valuation techniques that convert future cash flows to a single discounted amount. Significant inputs to the valuation of proved oil and natural gas properties include estimates of reserves, future operating and development costs, future commodity prices, estimated future cash flows, and a market-based weighted-average cost of capital rate of approximately 13%. These inputs require significant judgments and estimates by management at the time of the valuation. Extraction Merger Pursuant to the Extraction Merger Agreement, at the effective time of the Extraction Merger (the “Extraction Merger Effective Time”), (i) Raptor Eagle Merger Sub merged with and into Extraction, with Extraction continuing its existence as the surviving corporation as a wholly owned subsidiary of Civitas following the Extraction Merger (the “Extraction Surviving Corporation”), (ii) each share of common stock, par value $0.01 per share, of Extraction (the “Extraction Common Stock”) issued and outstanding as of immediately prior to the Extraction Merger Effective Time was converted into the right to receive 1.1711 shares of Civitas Common Stock for each share of Extraction Common Stock (the “Extraction Exchange Ratio”), with cash paid in lieu of the issuance of fractional shares, if any, and (iii) each holder of Extraction Common Stock received a total dividend equalization payment, as part of the Extraction Merger consideration, of approximately 0.017225678 shares of Civitas Common Stock per share of Extraction Common Stock related to dividends paid to Civitas’ stockholders on June 30, 2021 and September 30, 2021, with cash paid in lieu of the issuance of fractional shares, if any. Following the Extraction Merger and prior to the Crestone Peak Merger (as defined below), persons who were stockholders of Extraction immediately prior to the Extraction Merger owned approximately 50% of the combined company and persons who were stockholders of Civitas immediately prior to the Extraction Merger owned approximately 50% of the combined company. Additionally, pursuant to the Extraction Merger Agreement, at the Extraction Merger Effective Time, each award of restricted stock units (including those subject to performance-based vesting conditions) issued pursuant to Extraction’s 2021 Long Term Incentive Plan (the “Extraction Equity Plan”) that was outstanding immediately prior to the Extraction Merger Effective Time and that by its terms did not settle by reason of the occurrence of the closing of the Extraction Merger (each, an “Extraction RSU Award”) was assumed by Civitas and converted into a number of restricted stock units with respect to shares (rounded to the nearest number of whole shares) of Civitas Common Stock (such restricted stock unit, a “Converted RSU”) equal to the product of the number of Extraction Common Stock subject to the Extraction RSU Award immediately prior to the Extraction Merger Effective Time multiplied by the Extraction Exchange Ratio, effective as of the Extraction Merger Effective Time. As of the Extraction Merger Effective Time, each Converted RSU continued to be governed by the same terms and conditions (including vesting and forfeiture) that were applicable to the corresponding Extraction RSU Award immediately prior to the Extraction Merger Effective Time. However, any Extraction RSU Award subject to performance-based vesting conditions continued to be measured pursuant to the same terms and conditions of the underlying Extraction RSU Award in effect as of immediately prior to the Extraction Merger Effective Time. In addition, Converted RSUs subject to performance-based vesting conditions held by certain Extraction executives provide that, in the event such individual’s employment is terminated for death, disability, by Civitas for any reason other individual for good reason, in each case, on or within twelve months following the Extraction Merger Effective Time, the portion of such individual’s Converted RSUs subject to performance-based vesting conditions shall, effective as of such individual’s termination date, immediately vest in full based on deemed achievement of any applicable performance goals at the maximum level of performance. Further, effective as of immediately prior to the Extraction Merger Effective Time, each award of deferred stock units granted under the Extraction Equity Plan and held by a member of the Extraction board who was not a designee of Extraction for appointment to Civitas’ Board as of the Extraction Merger Effective Time immediately vested in full. Additionally, at the Extraction Merger Effective Time, in accordance with the terms of (i) the Extraction Tranche A warrants to purchase Extraction Common Stock, issued pursuant to that certain Warrant Agreement by and between Extraction and American Stock Transfer & Trust Company, LLC, as warrant agent (“AST”), dated as of January 20, 2021 (the “Tranche A Warrants”), and (ii) the Extraction Tranche B warrants to purchase Extraction Common Stock, issued pursuant to that certain Warrant Agreement by and between Extraction and AST, as warrant agent, dated as of January 20, 2021 (the “Tranche B Warrants,” and, together with the Tranche A Warrants, the “Extraction Warrants”), that were issued and outstanding immediately prior to the Extraction Merger Effective Time, were cancelled and Civitas executed a replacement warrant agreement for the Tranche A Warrants and a replacement warrant agreement for the Tranche B Warrants and issued to each holder of the Extraction Warrants a replacement warrant (each, a “Replacement Warrant”) that is exercisable for a number of shares of Civitas Common Stock equal to the number of shares of Civitas Common Stock that would have been issued or paid to a holder of the number of shares of Extraction Common Stock into which such Extraction Warrant was exercisable immediately prior to the Extraction Merger Effective Time. Each Replacement Warrant has an exercise price as set forth in the applicable Replacement Warrant Agreement, subject to adjustment as set forth therein. The Replacement Warrants may be exercised, in whole or in part, at any time or from time to time on or before 5:00 p.m., New York time, on (i) January 20, 2025, in the case of the Replacement Warrants for the Tranche A Warrants, or (ii) January 20, 2026, in the case of the Replacement Warrants for the Tranche B Warrants. The number of shares of Civitas Common Stock for which a Replacement Warrant is exercisable, and the exercise price of such Replacement Warrant, are subject to customary adjustments from time to time upon the occurrence of certain events, including the payment of in-kind dividends or distributions, splits, subdivisions or combinations of shares of Civitas Common Stock. A holder of a Replacement Warrant, in its capacity as such, is not entitled to any rights whatsoever as a stockholder of Civitas, except to the extent expressly provided in the applicable Replacement Warrant Agreement. 3.4 million Tranche A and 1.7 million Tranche B Replacement Warrants were issued. The following tables present the merger consideration and preliminary purchase price allocation of the assets acquired and the liabilities assumed in the Extraction Merger: Merger Consideration (in thousands, except per share amount) Shares of Civitas Common Stock issued as merger consideration (1) 31,095 Closing price per share of Civitas Common Stock (2) $ 56.10 Merger consideration paid in shares of Civitas Common Stock $ 1,744,431 Unvested restricted stock compensation expense as merger consideration $ 19,338 Unvested performance restricted stock compensation expense allocated as merger consideration 2,897 Total merger consideration $ 22,235 Tranche A warrants issued as merger consideration $ 52,164 Tranche B warrants issued as merger consideration 25,299 Total warrant merger consideration $ 77,463 Total merger consideration $ 1,844,129 _________________________ (1) Based on the number of shares of Extraction Common Stock issued and outstanding as of November 1, 2021 and the conversion ratio of 1.1711 per share of Civitas Common Stock. (2) Based on the closing stock price of Civitas Common Stock on November 1, 2021. Preliminary Purchase Price Allocation (in thousands) Assets Acquired Cash and cash equivalents $ 106,360 Accounts receivable - oil and natural gas sales 119,585 Accounts receivable - joint interest and other 33,054 Prepaid expenses and other 3,044 Inventory of oilfield equipment 9,291 Derivative assets 5,834 Proved properties 1,876,014 Unproved properties 193,400 Other property and equipment, net of accumulated depreciation 40,068 Right-of-use assets 6,883 Deferred income tax assets 49,194 Other noncurrent assets 4,248 Total assets acquired $ 2,446,975 Liabilities Assumed Accounts payable and accrued expenses $ 90,353 Production taxes payable 63,572 Oil and natural gas revenue distribution payable 170,002 Income tax payable 14,000 Lease liability 6,883 Derivative liability 100,474 Ad valorem taxes 87,071 Asset retirement obligations 68,741 Other noncurrent liabilities 1,750 Total liabilities assumed 602,846 Net assets acquired $ 1,844,129 The Extraction Merger was accounted for under the acquisition method of accounting for business combinations. Accordingly, we conducted assessments of the net assets acquired and recognized amounts for identifiable assets acquired and liabilities assumed at their estimated acquisition date fair values, while transaction and integration costs associated with the acquisition were expensed as incurred. The fair value measurements of assets acquired and liabilities assumed are based on inputs that are not observable in the market, and therefore represent Level 3 inputs. The fair values of crude oil and natural gas properties and asset retirement obligations were measured using valuation techniques that convert future cash flows to a single discounted amount. Significant inputs to the valuation of proved oil and natural gas properties include estimates of reserves, future operating and development costs, future commodity prices, estimated future cash flows, and a market-based weighted-average cost of capital rate of approximately 10%. These inputs require significant judgments and estimates by management at the time of the valuation. The purchase price allocation is preliminary, and Civitas is continuing to assess the fair values of certain of the Extraction assets acquired and liabilities assumed. In particular, assets and liabilities subject to potential adjustment, in amounts that could be material to the pro forma financial statements, include, but are not limited to, proved properties, unproved properties, and accounts payable and accrued expenses related to our continued assessment over the application of lease contracts and related deductions. We cannot reasonably estimate the impact of such conclusions as there is still a high level of uncertainty regarding the underlying terms and application. Crestone Peak Merger Pursuant to the Crestone Merger Agreement, at the effective time of the Crestone Peak Merger (the “Crestone Merger Effective Time”), (i) Merger Sub 1 merged with and into Crestone Peak (the “Merger Sub 1 Merger”), with Crestone Peak continuing its existence as the surviving corporation as a wholly owned subsidiary of Civitas following the Merger Sub 1 Merger (the “Crestone Surviving Corporation”), and (ii) subsequently, the Crestone Surviving Corporation merged with and into Merger Sub 2 (the “Merger Sub 2 Merger” and together with the Merger Sub 1 Merger, the “Crestone Peak Merger”), with Merger Sub 2 continuing its existence as the surviving entity as a wholly owned subsidiary of Civitas (the “Crestone Surviving Entity”). Pursuant to the Crestone Merger Agreement, at the effective time of the Merger Sub 1 Merger (the “Merger Sub 1 Merger Effective Time”), the shares of Crestone Peak common stock, par value $0.01 per share (“Crestone Peak Common Stock”) (excluding shares of Crestone Peak Common Stock held by Crestone Peak as treasury shares or by Civitas or Merger Sub 1 immediately prior to the Merger Sub 1 Merger Effective Time), issued and outstanding as of immediately prior to the Merger Sub 1 Merger Effective Time were converted into the right to collectively receive 22.5 million shares of Civitas Common Stock (the “Crestone Peak Merger Consideration”). In addition, at the effective time of the Merger Sub 2 Merger (the “Merger Sub 2 Merger Effective Time”), each share of common stock of the Crestone Surviving Corporation issued and outstanding as of immediately prior to the Merger Sub 2 Merger Effective Time was automatically cancelled and each unit of Merger Sub 2 issued and outstanding immediately prior to the Merger Sub 2 Merger Effective Time remained issued and outstanding and represents the only outstanding units of the Crestone Surviving Entity immediately following the Merger Sub 2 Merger. The Crestone Merger Agreement did not provide for specific treatment of equity compensation awards in connection with the Crestone Peak Merger. Certain Crestone Peak employees held profits interests and phantom equity awards based upon the Class B units of Crestone Peak vested in connection with the Crestone Peak Merger under the terms and conditions of the governing equity compensation plans. No employees received settlement payments with respect to any outstanding profits interests, but the outstanding phantom equity awards vested in connection with the Crestone Peak Merger and certain Crestone Peak employees received an aggregate amount of approximately $1.5 million in cash for settlement with respect to the outstanding phantom equity awards in connection with the Crestone Peak Merger. The following tables present the merger consideration and preliminary purchase price allocation of the assets acquired and the liabilities assumed in the Crestone Peak Merger: Merger Consideration (in thousands, except per share amount) Shares of Civitas Common Stock issued as merger consideration 22,500 Closing price per share of Civitas Common Stock (1) $ 56.10 Merger consideration paid in shares of Civitas Common Stock $ 1,262,250 _________________________ (1) Based on the closing stock price of Civitas Common Stock on November 1, 2021. Preliminary Purchase Price Allocation (in thousands) Assets Acquired Cash and cash equivalents $ 67,505 Accounts receivable - oil and natural gas sales 81,340 Accounts receivable - joint interest and other 9,917 Prepaid expenses and other 2,929 Inventory of oilfield equipment 11,951 Proved properties 1,797,814 Unproved properties 453,321 Other property and equipment, net of accumulated depreciation 7,980 Right-of-use assets 7,934 Total assets acquired $ 2,440,691 Liabilities Assumed Accounts payable and accrued expenses $ 134,791 Production taxes payable 52,435 Oil and natural gas revenue distribution payable 83,950 Lease liability 7,934 Derivative liability 338,383 Credit facility 280,000 Ad valorem taxes 66,913 Deferred income tax liabilities 125,086 Asset retirement obligations 88,949 Total liabilities assumed 1,178,441 Net assets acquired $ 1,262,250 The Crestone Peak Merger was accounted for under the acquisition method of accounting for business combinations. Accordingly, we conducted assessments of the net assets acquired and recognized amounts for identifiable assets acquired and liabilities assumed at their estimated acquisition date fair values, while transaction and integration costs associated with the acquisition were expensed as incurred. The fair value measurements of assets acquired and liabilities assumed are based on inputs that are not observable in the market, and therefore represent Level 3 inputs. The fair values of crude oil and natural gas properties and asset retirement obligations were measured using valuation techniques that convert future cash flows to a single discounted amount. Significant inputs to the valuation of proved oil and natural gas properties include estimates of reserves, future operating and development costs, future commodity prices, estimated future cash flows, and a market-based weighted-average cost of capital rate of approximately 10%. These inputs require significant judgments and estimates by management at the time of the valuation. The purchase price allocation is preliminary, and Civitas is continuing to assess the fair values of certain of the Crestone Peak assets acquired and liabilities assumed. In particular, assets and liabilities subject to potential adjustment, in amounts that could be material to the pro forma financial statements, include, but are not limited to, proved properties, unproved properties, and accounts payable and accrued expenses related to our continued assessment over the application of lease contracts and related deductions. We cannot reasonably estimate the impact of such conclusions as there is still a high level of uncertainty regarding the underlying terms and application. Revenue and earnings of the acquiree The amount of revenue of HighPoint, Extraction, and Crestone Peak included in our statement of operations during the year ended December 31, 2021 was approximately $244.7 million, $172.3 million, and $114.8 million, respectively. We determined that disclosing the amount of HighPoint, Extraction, and Crestone Peak related earnings included in the statements of operation is impracticable, as the operations from these mergers were integrated into the operations of the Company from the dates of each acquisition. Supplemental pro forma financial information The following unaudited pro forma financial information (in thousands, except per share amounts) represents a summary of the consolidated results of operations for the year ended December 31, 2021 and 2020, assuming the HighPoint, Extraction, and Crestone Peak mergers had been completed as of January 1, 2020. The pro forma financial information includes certain non-recurring pro forma adjustments that were directly attributable to the business combinations. The pro forma financial information is not necessarily indicative of the results of operations that would have been achieved if the mergers had been effective as of this date, or of future results. Year Ended December 31, 2021 As reported HighPoint (1) Extraction (2) Crestone Peak (2) Civitas Pro Forma Combined Total revenue $ 930,614 $ 72,019 $ 882,255 $ 508,038 $ 2,392,926 Net income (loss) 178,921 (46,657) 944,814 (299,688) 777,390 Net income per common share - basic $ 4.82 $ 9.37 Net income per common share - diluted $ 4.74 $ 9.30 _________________________ (1) Based on a closing date of April 1, 2021. (2) Based on a closing date of November 1, 2021. Year Ended December 31, 2020 As reported HighPoint Extraction Crestone Peak Civitas Pro Forma Combined Total revenue $ 218,090 $ 250,347 $ 557,904 $ 285,426 $ 1,311,767 Net income (loss) 103,528 (1,081,347) (1,335,406) (268,057) (2,581,282) Net income (loss) per common share - basic $ 4.98 $ (28.83) Net income (loss) per common share - diluted $ 4.95 $ (28.83) Following the completion of the Extraction Merger and the Crestone Peak Merger, persons who were stockholders of Civitas, Extraction and Crestone Peak immediately prior to the Crestone Peak Merger own approximately 37%, 37% and 26% of the combined company, respectively. Merger transaction costs of $43.6 million and $6.7 million related to the aforementioned mergers were accounted for separately from the assets acquired and liabilities assumed and are included in merger transaction costs in Civitas' statements of operations for the years ended December 31, 2021 and 2020, respectively. |
LEASES
LEASES | 12 Months Ended |
Dec. 31, 2021 | |
Leases [Abstract] | |
LEASES | LEASES The Company’s ROU assets and lease liabilities are recognized on the accompanying balance sheets based on the present value of the expected lease payments over the lease term. The following table summarizes the asset classes of the Company's operating and finance leases (in thousands): December 31, 2021 2020 Operating Leases Field equipment (1) $ 29,312 $ 27,537 Corporate leases 9,484 1,481 Vehicles 1,089 468 Total right-of-use asset $ 39,885 $ 29,486 Field equipment (1) $ 29,312 $ 27,537 Corporate leases 9,870 1,900 Vehicles 1,089 468 Total lease liability $ 40,271 $ 29,905 Finance Leases Right of use asset - field equipment (1) $ — $ 219 Lease liability - field equipment (1) $ — $ 117 ____________________________ (1) Includes compressors, certain natural gas processing equipment, and other field equipment. The following table summarizes the components of the Company's gross lease costs incurred for the periods below consisted of the following (in thousands): Year Ended December 31, 2021 2020 2019 Operating lease cost (1) $ 15,449 $ 13,957 $ 11,330 Finance lease cost Amortization of ROU assets 3 18 — Interest on lease liabilities 1 5 — Short-term lease cost 3,662 2,058 8,169 Variable lease cost (2) 56 (186) 259 Sublease income (3) (367) (358) (348) Total lease cost $ 18,804 $ 15,494 $ 19,410 ___________________________ (1) Includes office rent expense of $2.2 million, $1.1 million, and $1.1 million for the years ended December 31, 2021, 2020, and 2019, respectively. (2) Variable lease cost represents differences between lease obligations and actual costs incurred for certain leases that do not have fixed payments related to both lease and non-lease components. Such incremental costs include lease payment increases or decreases driven by market price fluctuations and leased asset maintenance costs. (3) The Company has subleased a portion of one of its office spaces for the remainder of the office lease term. Lease costs disclosed above are presented on a gross basis. A portion of these costs may have been or will be billed to other working interest owners. The Company's net share of these costs is included in various line items on the accompanying statements of operations or capitalized to proved properties or other property and equipment, as applicable. The Company recognizes operating lease cost on a straight-line basis. Finance lease cost is recognized based on the effective interest method for the lease liability and straight-line amortization for the right-of-use asset, resulting in more cost being recognized in earlier lease periods. Short-term and variable lease costs are recognized as incurred. Short-term lease cost represents payments for leases with a lease term of one year or less, excluding leases with a term of one month or less. Short-term leases include drilling rigs and other equipment. The Company's weighted-average remaining lease terms and discount rates as of December 31, 2021 are as follows: Operating Leases Weighted-average lease term (years) 2.7 Weighted-average discount rate 3.9% Supplemental cash flow information related to leases for the periods below consisted of the following (in thousands): Year Ended December 31, 2021 2020 2019 Cash paid for amounts included in the measurement of lease liabilities: Operating cash flows from operating leases $ 14,284 $ 12,768 $ 10,993 Operating cash flows from finance leases 1 5 — Financing cash flows from finance leases 21 102 — Right-of-use assets obtained in exchange for new operating lease obligations $ 25,469 $ 8,306 $ 16,568 Right-of-use assets obtained in exchange for new finance lease obligations — 219 — Future commitments by year for the Company's leases with a lease term of one year or more as of December 31, 2021 are presented in the table below. Such commitments are reflected at undiscounted values and are reconciled to the discounted present value recognized on the accompanying balance sheets as follows (in thousands): Operating Leases 2022 $ 20,044 2023 12,980 2024 5,247 2025 1,496 2026 1,178 Thereafter 1,586 Total lease payments 42,531 Less: imputed interest (2,260) Total lease liability $ 40,271 |
LEASES | LEASES The Company’s ROU assets and lease liabilities are recognized on the accompanying balance sheets based on the present value of the expected lease payments over the lease term. The following table summarizes the asset classes of the Company's operating and finance leases (in thousands): December 31, 2021 2020 Operating Leases Field equipment (1) $ 29,312 $ 27,537 Corporate leases 9,484 1,481 Vehicles 1,089 468 Total right-of-use asset $ 39,885 $ 29,486 Field equipment (1) $ 29,312 $ 27,537 Corporate leases 9,870 1,900 Vehicles 1,089 468 Total lease liability $ 40,271 $ 29,905 Finance Leases Right of use asset - field equipment (1) $ — $ 219 Lease liability - field equipment (1) $ — $ 117 ____________________________ (1) Includes compressors, certain natural gas processing equipment, and other field equipment. The following table summarizes the components of the Company's gross lease costs incurred for the periods below consisted of the following (in thousands): Year Ended December 31, 2021 2020 2019 Operating lease cost (1) $ 15,449 $ 13,957 $ 11,330 Finance lease cost Amortization of ROU assets 3 18 — Interest on lease liabilities 1 5 — Short-term lease cost 3,662 2,058 8,169 Variable lease cost (2) 56 (186) 259 Sublease income (3) (367) (358) (348) Total lease cost $ 18,804 $ 15,494 $ 19,410 ___________________________ (1) Includes office rent expense of $2.2 million, $1.1 million, and $1.1 million for the years ended December 31, 2021, 2020, and 2019, respectively. (2) Variable lease cost represents differences between lease obligations and actual costs incurred for certain leases that do not have fixed payments related to both lease and non-lease components. Such incremental costs include lease payment increases or decreases driven by market price fluctuations and leased asset maintenance costs. (3) The Company has subleased a portion of one of its office spaces for the remainder of the office lease term. Lease costs disclosed above are presented on a gross basis. A portion of these costs may have been or will be billed to other working interest owners. The Company's net share of these costs is included in various line items on the accompanying statements of operations or capitalized to proved properties or other property and equipment, as applicable. The Company recognizes operating lease cost on a straight-line basis. Finance lease cost is recognized based on the effective interest method for the lease liability and straight-line amortization for the right-of-use asset, resulting in more cost being recognized in earlier lease periods. Short-term and variable lease costs are recognized as incurred. Short-term lease cost represents payments for leases with a lease term of one year or less, excluding leases with a term of one month or less. Short-term leases include drilling rigs and other equipment. The Company's weighted-average remaining lease terms and discount rates as of December 31, 2021 are as follows: Operating Leases Weighted-average lease term (years) 2.7 Weighted-average discount rate 3.9% Supplemental cash flow information related to leases for the periods below consisted of the following (in thousands): Year Ended December 31, 2021 2020 2019 Cash paid for amounts included in the measurement of lease liabilities: Operating cash flows from operating leases $ 14,284 $ 12,768 $ 10,993 Operating cash flows from finance leases 1 5 — Financing cash flows from finance leases 21 102 — Right-of-use assets obtained in exchange for new operating lease obligations $ 25,469 $ 8,306 $ 16,568 Right-of-use assets obtained in exchange for new finance lease obligations — 219 — Future commitments by year for the Company's leases with a lease term of one year or more as of December 31, 2021 are presented in the table below. Such commitments are reflected at undiscounted values and are reconciled to the discounted present value recognized on the accompanying balance sheets as follows (in thousands): Operating Leases 2022 $ 20,044 2023 12,980 2024 5,247 2025 1,496 2026 1,178 Thereafter 1,586 Total lease payments 42,531 Less: imputed interest (2,260) Total lease liability $ 40,271 |
OTHER NONCURRENT ASSETS, ACCOUN
OTHER NONCURRENT ASSETS, ACCOUNTS PAYABLE, AND ACCRUED EXPENSES | 12 Months Ended |
Dec. 31, 2021 | |
Other Assets [Abstract] | |
OTHER NONCURRENT ASSETS, ACCOUNTS PAYABLE, AND ACCRUED EXPENSES | OTHER NONCURRENT ASSETS, ACCOUNTS PAYABLE, AND ACCRUED EXPENSES Other noncurrent assets contain the following (in thousands): As of December 31, 2021 2020 Deferred financing costs $ 7,543 $ 725 Operating bonds 3,485 1,641 Carbon offsets 1,967 — Notes receivable 506 — AMT credit refund 403 403 Restricted cash 102 102 Other 79 — Other noncurrent assets $ 14,085 $ 2,871 Accounts payable and accrued expenses contain the following (in thousands): As of December 31, 2021 2020 Accounts payable trade $ 19,623 $ 1,931 Accrued drilling and completion costs 129,430 453 Accrued lease operating expense 19,077 1,793 Accrued general and administrative expense 21,163 4,942 Accrued merger transaction costs 1,475 2,587 Accrued oil and NGL hedging 26,601 — Accrued interest expense 6,303 322 Accrued settlement 20,791 — Other accrued expenses 1,725 65 Total accounts payable and accrued expenses $ 246,188 $ 12,093 |
LONG-TERM DEBT
LONG-TERM DEBT | 12 Months Ended |
Dec. 31, 2021 | |
Debt Disclosure [Abstract] | |
LONG-TERM DEBT | LONG-TERM DEBT 5.0% Senior Notes On October 13, 2021, the Company issued $400.0 million aggregate principal amount of 5.0% Senior Notes due 2026 (the “5.0% Senior Notes”) pursuant to an indenture, dated October 13, 2021 (the “5.0% Indenture”), among Civitas Resources, the guarantors party thereto and Wells Fargo Bank, National Association, as trustee. Following the closing of the offering, the Company used the net proceeds from the Offering and cash on hand to repay all borrowings under the Credit Facility, all borrowings outstanding under the Crestone Peak credit facility, and for general corporate purposes. Interest accrues at the rate of 5.0% per annum and will be payable semiannually in arrears on April 15 and October 15, commencing on April 15, 2022. The 5.0% Senior Notes contain covenants that limit, among other things, the Company’s ability and the ability of its subsidiaries 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; (vii) and sell assets or merge with other companies. These covenants are subject to a number of important limitations and exceptions. In addition, certain of these restrictive covenants will be terminated before the 5.0% Senior Notes mature if at any time no default or event of default exists under the 5.0% Indenture and the 5.0% Senior Notes receive an investment-grade rating from at least two ratings agencies. The 5.0% Indenture also contains customary events of default. At any time prior to October 15, 2023, the Company may redeem the 5.0% Senior Notes, in whole or in part, at a redemption price equal to the sum of (i) the principal amount thereof, plus (ii) the “make-whole” premium at the redemption date, plus (iii) accrued and unpaid interest, if any, to, but excluding, the date of redemption (subject to the right of the noteholders on the relevant record date to receive interest on the relevant interest payment date). On or after October 15, 2023, the Company may redeem all or part of the 5.0% Senior Notes at redemption prices (expressed as percentages of the principal amount redeemed) equal to (i) 102.5% for the twelve-month period beginning on October 15, 2023; (ii) 101.25% for the twelve-month period beginning on October 15, 2024; and (iii) 100.0% for the twelve-month period beginning October 15, 2025 and at any time thereafter, plus accrued and unpaid interest, if any, 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 5.0% Senior Notes at any time prior to October 15, 2023 with an amount not to exceed the net cash proceeds from certain equity offerings at a redemption price equal to 105.0% of the principal amount of the 5.0% Senior Notes redeemed, plus accrued and unpaid interest, if any, thereon to, but not including, the redemption date, provided, however, that (i) at least 65.0% of the aggregate principal amount of the 5.0% Senior Notes originally issued on the issue date (but excluding 5.0% Senior Notes held by CIVI and its subsidiaries) remains outstanding immediately after the occurrence of such redemption (unless all such 5.0% Senior Notes are redeemed substantially concurrently) and (ii) the redemption occurs within 180 days after the date of the closing of such equity offering. The 5.0% Senior Notes are fully and unconditionally guaranteed on a senior unsecured basis by all of Civitas' existing subsidiaries. 7.5% Senior Notes In conjunction with the HighPoint Merger, the Company issued $100.0 million aggregate principal amount of 7.5% Senior Notes due 2026 pursuant to an indenture (the “7.5% Indenture”), dated April 1, 2021, by and among Civitas Resources, U.S. Bank National Association (“US Bank”), as trustee, and the subsidiary guarantors party thereto. Interest accrues at the rate of 7.5% per annum and will be payable semiannually in arrears on April 30 and October 31, commencing on October 31, 2021. The 7.5% Indenture contains restrictive covenants that, among other things, restrict the ability of Civitas Resources, and each of its restricted subsidiaries to: (i) incur additional indebtedness and issue preferred stock; (ii) pay dividends or make other distributions in respect of the Company's common stock; (iii) make other restricted payments and investments; (iv) create liens; (v) restrict distributions or other payments from Civitas' restricted subsidiaries; (v) sell assets, including capital stock of restricted subsidiaries; (vi) merge or consolidate with other entities; and (vii) enter into transactions with affiliates. These restrictive covenants are subject to a number of important qualifications and limitations. In addition, certain of these restrictive covenants will be suspended before the 7.5% Senior Notes mature if at any time no default or event of default exists under the 7.5% Indenture and the 7.5% Senior Notes receive an investment grade rating from at least two ratings agencies. The Indenture also contains customary events of default. The 7.5% Senior Notes are redeemable at the Company’s option (an “Optional Redemption”), in whole or in part, prior to April 30, 2022 at a redemption price equal to 107.5% of the aggregate principal to be redeemed, plus unpaid accrued interest, if any, through the Optional Redemption date. On or after April 30, 2022, the Optional Redemption price will be equal to 100.0% of the aggregate principal amount of the 7.5% Senior Notes to be redeemed, plus unpaid accrued interest, if any, through the Optional Redemption date. The 7.5% Senior Notes are fully and unconditionally guaranteed on a senior unsecured basis by all of Civitas' existing subsidiaries. The 7.5% Senior Notes and 5.0% Senior Notes are recorded at carrying value. There were no discounts or premiums associated with the either issuance. The table below presents the related carrying values as of December 31, 2021 (in thousands): Principal Amount Unamortized Deferred Financing Costs Carrying Value 7.5% Senior Notes $ 100,000 $ — $ 100,000 5.0% Senior Notes $ 400,000 $ 8,290 $ 391,710 Credit Facility In December 2018, the Company entered into a reserve-based revolving facility, as the borrower, with JPMorgan as the administrative agent, and a syndicate of financial institutions, as lenders, that matured on December 7, 2023. The November 2021 redetermination as part of the Amended & Restated Credit Agreement (defined below) resulted in a borrowing base of $1.0 billion, with elected commitments set at $800.0 million. The next scheduled redetermination is set to occur in April 2022. The Credit Facility contains customary representations and affirmative covenants. The Credit Facility also contains customary negative covenants, which, among other things, and subject to certain exceptions, include restrictions on (i) liens, (ii) indebtedness, guarantees and other obligations, (iii) restrictions in agreements on liens and distributions, (iv) mergers or consolidations, (v) asset sales, (vi) restricted payments, (vii) investments, (viii) affiliate transactions, (ix) change of business, (x) foreign operations or subsidiaries, (xi) name changes, (xii) use of proceeds, letters of credit, (xiii) gas imbalances, (xiv) hedging transactions, (xv) additional subsidiaries, (xvi) changes in fiscal year or fiscal quarter, (xvii) operating leases, (xviii) prepayments of certain debt and other obligations, (xix) sales or discounts of receivables, (xx) dividend payment thresholds, and (xi) cash balances. The Credit Parties are subject to certain financial covenants under the Credit Facility, as tested on the last day of each fiscal quarter, including, without limitation, (a) a maximum ratio of the Company's consolidated indebtedness (subject to certain exclusions) to earnings before interest, income taxes, depreciation, depletion, and amortization, exploration expense, and other non-cash charges (“EBITDAX”) and (b) a current ratio, as defined in the agreement, inclusive of the unused commitments then available to be borrowed, to not be less than 1.00 to 1. Under the terms of the Credit Facility, as amended in June 2020 (the “First Amendment”), borrowings bore interest at a per annum rate equal to, at the option of the Company, either (i) a LIBOR, subject to a 0% LIBOR floor plus a margin of 2.00% to 3.00%, based on the utilization of the Credit Facility (the “Eurodollar Rate”) or (ii) a fluctuating interest rate per annum equal to the greatest of (a) the rate of interest publicly announced by JPMorgan Chase Bank, N.A. as its prime rate, (b) the rate of interest published by the Federal Reserve Bank of New York as the federal funds effective rate, (c) the rate of interest published by the Federal Reserve Bank of New York as the overnight bank funding rate, or (d) a LIBOR offered rate for a one-month interest period, subject to a 0% LIBOR floor plus a margin of 1.00% to 2.00%, based on the utilization of the Credit Facility (the “Reference Rate”). Interest on borrowings that bear interest at the Eurodollar Rate shall be payable on the last day of the applicable interest period selected by the Company, which shall be one, two, three, or six months, and interest on borrowings that bear interest at the Reference Rate shall be payable quarterly in arrears. On April 1, 2021, in conjunction with the HighPoint Merger, the Company, together with certain of its subsidiaries, entered into the Second Amendment (the “Second Amendment”) to the Credit Facility (as amended, restated, supplemented or otherwise modified) to, among other things: (i) increase the aggregate maximum commitment amount from $750.0 million to $1.0 billion; (ii) increase the available borrowing base from $260.0 million to $500.0 million; (iii) increase the Eurodollar Rate margin to 3.00% to 4.00%; (iv) increase the Reference Rate margin to 2.00% to 3.00%; (v) increase (A) the LIBOR floor from 0% to .50% and (B) the alternate base rate floor from 0% to 1.50%; (vi) decrease for any fiscal quarter ending on or after April 1, 2021, the maximum permitted net leverage ratio from 3.50 to 3.0; and (viii) amend certain other covenants and provisions. On November 1, 2021, in conjunction with the Transactions, the Company, as borrower, JPMorgan, as the administrative agent, and a syndicate of financial institutions, as lenders, entered into an Amended and Restated Credit Agreement (the “Amended & Restated Agreement”), dated as of November 1, 2021 having an Aggregate Maximum Credit Amount (as defined in the Amended and Restated Credit Agreement) of $2.0 billion. The Amended and Restated Credit Agreement, among other things: (i) increases the aggregate elected commitments to from $400.0 million to $800.0 million, (ii) increases the available borrowing base from $500.0 million to $1.0 billion, (iii) extends the maturity date of the Amended and Restated Credit Agreement to November 1, 2025 and (iv) amends the borrowing base adjustment provisions such that, between borrowing base determinations, downward adjustments related to the incurrence of certain permitted indebtedness will only occur (x) until the occurrence of the April 2022 borrowing base determination, if such indebtedness exceeds $500.0 million and, (y) thereafter, if either (A) such indebtedness exceeds $500.0 million and the Company’s pro-forma leverage ratio is less than or equal to 1.50 to 1, or (B) the Company's pro-forma leverage ratio is greater than 1.50 to 1. Under the Amended and Restated Credit Agreement, the Company’s Credit Facility will be guaranteed by all restricted domestic subsidiaries of the Company including by the Extraction Surviving Corporation, the Crestone Surviving Entity, and all their respective subsidiaries, and will be secured by first priority security interests on substantially all assets, including a mortgage on at least 90% of the total value of the proved oil and natural gas properties evaluated in the most recently delivered reserve reports prior to the amendment effective date, including any engineering reports relating to the oil and natural gas properties of the Extraction Surviving Corporation, the Crestone Surviving Entity, their respective subsidiaries, of each of the Company, all restricted domestic subsidiaries of the Company, the Extraction Surviving Corporation and the Crestone Surviving Entity, in each case, subject to customary exceptions. The Company had zero outstanding on the Credit Facility as of December 31, 2021 and 2020. As of the date of this filing, the outstanding balance was zero. The Company's Credit Facility approximates fair value as the applicable interest rates are floating. In connection with the Second Amendment and the Amended & Restated Credit Agreement, the Company capitalized a total of approximately $3.9 million and $6.8 million, respectively, in deferred financing costs. Of the total post-amortization net capitalized amounts, (i) $7.5 million and $0.7 million as of December 31, 2021 and 2020, respectively, are presented within other noncurrent assets and (ii) $2.7 million and $0.4 million as of December 31, 2021 and 2020, respectively, are presented within prepaid expenses and other line items in the accompanying balance sheets. Interest Expense |
COMMITMENTS AND CONTINGENCIES
COMMITMENTS AND CONTINGENCIES | 12 Months Ended |
Dec. 31, 2021 | |
Commitments and Contingencies Disclosure [Abstract] | |
COMMITMENTS AND CONTINGENCIES | COMMITMENTS AND CONTINGENCIES Legal Proceedings From time to time, the Company is involved in various commercial and regulatory claims, litigation, and other legal proceedings that arise in the ordinary course of its business. The Company assesses these claims in an effort to determine the degree of probability and range of possible loss for potential accrual in its consolidated financial statements. In accordance with authoritative accounting guidance, an accrual is recorded for a loss contingency when its occurrence is probable and damages can be reasonably estimated based on the most likely anticipated outcome or the minimum amount within a range of possible outcomes. Because legal proceedings are inherently unpredictable and unfavorable resolutions could occur, assessing contingencies is highly subjective and requires judgments about uncertain future events. When evaluating contingencies, the Company may be unable to provide a meaningful estimate due to a number of factors, including the procedural status of the matter in question, the presence of complex or novel legal theories, and/or the ongoing discovery and development of information important to the matters. The Company regularly reviews contingencies to determine the adequacy of its accruals and related disclosures. No claims have been made, nor is the Company aware of any material uninsured liability which the Company may have, as it relates to any environmental cleanup, restoration, or the violation of any rules or regulations. Upon closing of the HighPoint, Extraction, and Crestone Peak Mergers, the Company assumed all obligations, whether asserted or unasserted, of HighPoint, Extraction, and Crestone Peak. As of the filing date of this report, there were no probable, material pending, or overtly threatened legal actions against the Company of which it was aware, other than the following: Boulder County. As of the date of this filing, there is active and ongoing litigation between Boulder County and Extraction which could prevent oil and gas operations for the development minerals contained within Boulder County, Colorado. Boulder County initiated suit in District Court for Boulder County, Colorado in case no. 2018CV030925 on September 25, 2018, Extraction prevailed before the district court on all issues in an order dated August 29, 2019. The district court’s order was appealed, has been fully briefed on appeal, and was argued before the Colorado Court of Appeals on December 14, 2021 - Board of County Commissioners of Boulder County v. 8 North and Extraction Oil & Gas , Case No. 2019CA001896 (Colorado Court of Appeals) . On March 3, 2022, the Colorado Court of Appeals issued a unanimous opinion rejecting Boulder County's claims. We await whether Boulder will petition the Colorado Supreme Court for certiorari. This action is primarily a contract case, where the relevant contracts are the CE over the Blue Paintbrush location, Extraction’s SUA for the Blue Paintbrush location, and the leases that Boulder owns within the Blue Paintbrush drilling and spacing unit. Boulder seeks invalidation of these leases in the litigation. Boulder argues that the lease underlying the CE only authorizes the extraction of minerals underneath the CE Property. Boulder takes issue with the planned 32 wells for the location and argues that only the number of wells necessary to extract the minerals underlying the CE property should be allowed. Boulder also argues that Extraction induced a breach of the CE by contracting with the CE property owner for the SUA. Boulder argues that the terms of the SUA violate the CE because the SUA allows for development in excess of that allowed under the underlying lease. Boulder’s argument is based on its assertion that the lease underlying the CE property only allows for the extraction of minerals underneath the CE property and ignores that the lease underlying the CE property explicitly allows for pooling and unitization. Boulder’s remaining claims assert that Extraction breached the terms of leases Boulder owns in the drilling and spacing unit by establishing the Blue Paintbrush drilling and spacing unit. Specifically, Boulder’s leases within the Blue Paintbrush drilling and spacing unit have a clause that states that a unit must be the “minimum size tract on which a well may be drilled under the laws, rules, or regulations in force at the time of such pooling or unitization.” Boulder argues that no drilling and spacing unit including acreage covered by these leases can be greater than 80 acres because COGCC Order 407 established 80-acre drilling and spacing units for the Codell and COGCC Order 407-87 established 80-acre drilling and spacing unit for the Niobrara. In making this argument, Boulder fails to acknowledge that COGCC Rule 318A.l., provides that “…this rule supersedes all prior Commission drilling and spacing orders affecting well location and density requirements of GWA wells. Where the Commission has issued a specific order limiting the number of horizontal wells in a drilling and spacing unit, the well density in such units shall be governed by that order.” An outcome adverse to Extraction, could lead to expiration of our leases in the Blue Paint Brush drilling and spacing unit and impact future, planned locations that include Boulder minerals, result in a decline of our oil and natural gas reserves, or anticipated production volumes. NOAV. Disclosure of certain environmental matters is required when a governmental authority is a party to the proceedings and the proceedings involve potential monetary sanctions that the Company believes could exceed $0.3 million. The Company has received Notices of Alleged Violations (“NOAV”) from the COGCC alleging violations of various Colorado statutes and COGCC regulations governing oil and gas operations. The Company continues to engage in discussions regarding resolution of the alleged violations. As of December 31, 2021, the Company has accrued approximately $1.0 million associated with the NOAVs, as they are probable and reasonably estimable. Commitments Firm Transportation Agreements. As part of the HighPoint Merger, the Company became party to two firm transportation contracts. Both firm transportation contracts required the pipeline to provide a guaranteed outlet for production through July 2021. The Company did not utilize the firm capacity on the natural gas pipelines and incurred deficiency payments totaling $7.7 million for the year ended December 31, 2021, which is included in unused commitments expense in the statements of operations. Additionally, the Company is party to one firm pipeline transportation contract to provide a guaranteed outlet for production on an oil pipeline system. The contract requires the Company to pay minimum volume transportation charges on 8,500 gross barrels per day through April 2022 and 12,500 barrels per day thereafter through April 2025, regardless of the amount of pipeline capacity utilized by the Company. The aggregate financial commitment fee over the remaining term was $47.1 million as of December 31, 2021. The Company expects to utilize most, if not all, of the firm capacity on the oil pipeline system. Minimum Volume Agreement - Oil. The Company is party to a purchase agreement to deliver fixed determinable quantities of crude oil . This agreement includes defined volume commitments over a term ending in 2023. Under the terms of the agreement, the Company is required to make periodic deficiency payments for any shortfalls in delivering minimum gross volume commitments, which are set in six-month periods. The minimum gross volume commitment will increase approximately 3% each year for the remainder of the contract, to a maximum of approximately 16,000 gross barrels per day. The aggregate financial commitment fee over the remaining term is $36.4 million as of December 31, 2021. Upon notifying the purchaser at least twelve months prior to the expiration date of the agreement, the Company may elect to extend the term of the agreement for up to three Minimum Volume Agreement - Gas and Other. The Company is party to a long-term gas gathering and processing agreement (the “Gathering Agreement”) with a third-party midstream provider over a term ending in 2029 with an annual minimum volume commitment of 13.0 Bcf. The Gathering Agreement also includes a commitment to sell take-in-kind NGLs from other processing agreements of 7,500 barrels a day through year seven of the Gathering Agreement with the ability to roll forward up to a 10% shortfall in a given month to the subsequent month. The aggregate financial commitment fee over the remaining term is $151.8 million as of December 31, 2021. The Company has not and does not expect to incur any deficiency payments. Additionally, the Company is also party to a gas gathering and processing agreement with several third-party producers and a third-party midstream provider to deliver to 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 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 December 31, 2021. The Company has not and does not expect to incur any deficiency payments. The Company is also party to two additional gas gathering and processing agreements as well as a minimum volume commitments to purchase fresh water from water suppliers. These commitments require the Company to pay a fee associated with the minimum volumes regardless of the amount delivered. The aggregate financial commitment fee over the remaining term for these contracts was $15.7 million as of December 31, 2021. The minimum annual payments under the these agreements for the next five years as of December 31, 2021 are presented below (in thousands): Firm Transportation Minimum Volume (1) 2022 $ 13,064 $ 58,284 2023 14,600 29,192 2024 14,640 22,298 2025 4,800 20,400 2026 and thereafter — 73,712 Total $ 47,104 $ 203,886 ___________________________ (1) The above calculation is based on the minimum volume commitment schedule (as defined in the relevant agreement) and applicable differential fees. Drilling commitments. The Company is party to a drilling commitment agreement with a third-party midstream provider such that the Company is required to drill a total of 106 horizontal wells, whereby a minimum number of wells out of the total must be drilled by a deadline occurring every 2 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 3 - Leases |
STOCK-BASED COMPENSATION
STOCK-BASED COMPENSATION | 12 Months Ended |
Dec. 31, 2021 | |
Share-based Payment Arrangement [Abstract] | |
STOCK-BASED COMPENSATION | STOCK-BASED COMPENSATION Long Term Incentive Plans In April 2017, the Company adopted the 2017 Long Term Incentive Plan (“2017 LTIP”), which provides for the issuance of restricted stock units, performance stock units, and stock options, and reserved 2,467,430 shares of common stock. In June 2021, the Company adopted the 2021 Long Term Incentive Plan (“2021 LTIP”), which reserved an incremental 700,000 shares of common stock to those previously reserved under the 2017 LTIP. Finally, pursuant to the Extraction Merger Agreement, Civitas assumed the Extraction Equity Plan, which reserved 3,305,080 shares of common stock now issuable by Civitas. The 2017 LTIP, 2021 LTIP, and Extraction Equity Plan are collectively referred to herein as the “LTIP”. In November 2021, the Company adopted a non-employee director compensation program (the “Director Compensation Program”), which provides that non-employee directors will receive grants of deferred stock units (“DSUs”). In connection with the adoption of the Director Compensation Program, the Company adopted a First Amendment to the 2021 LTIP (the “LTIP Amendment”) that, among other things, allows the Company to determine whether dividend rights granted pursuant to the LTIP should be reinvested, paid currently or paid in accordance with the terms of an associated award. The Company records compensation expense associated with the issuance of awards under the LTIP based on the fair value of the awards as of the date of grant within general and administrative expense. The following table outlines the compensation expense recorded by type of award (in thousands): Year Ended December 31, 2021 2020 2019 Restricted and deferred stock units $ 11,895 $ 5,283 $ 5,518 Performance stock units 3,663 748 764 Stock options — 125 604 Total stock-based compensation $ 15,558 $ 6,156 $ 6,886 As of December 31, 2021, 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 $ 9,333 2024 Performance stock units 11,192 2024 Total unrecognized stock-based compensation $ 20,525 Restricted Stock Units ("RSUs") and Deferred Stock Units The Company typically grants RSUs to officers, directors, and employees and DSUs to directors as part of its LTIP. Each RSU and DSU represents a right to receive one share of the Company's common stock upon settlement of the award at the end of the specified vesting period. RSUs generally vest and settle either over a (i) one-year vesting period, with the entire grant vesting and settling on the anniversary date or (ii) three-year vesting period, with one-third of the total grant vesting and settling on each anniversary date. DSUs generally vest in quarterly installments over a one-year period following the grant date. DSUs are settled in shares of the Company's common stock upon the director’s separation of service from the Board. The Company records compensation expense associated with the issuance of RSUs and DSUs on a straight-line basis over the vesting period based on the fair value of the awards as of the date of grant within general and administrative expense. The fair value of RSUs and DSUs is equal to the closing price of the Company’s common stock on the date of the grant. A summary of the status and activity of non-vested RSUs and DSUs for the year ended December 31, 2021 is presented below: RSUs and DSUs Weighted-Average Grant-Date Fair Value Non-vested, beginning of year 550,056 $ 20.30 Granted or assumed 662,748 50.12 Vested (373,696) 25.61 Forfeited (24,046) 17.99 Non-vested, end of year 815,062 $ 42.18 The fair value of the RSUs and DSUs granted under the LTIP during the years ended December 31, 2021, 2020, and 2019 was $33.2 million, $4.9 million, and $5.9 million, respectively. Of the total fair value of the RSUs assumed by the Company as a result of the Extraction Merger, $19.3 million was allocated to consideration transferred. Performance Stock Units ("PSUs") The Company grants PSUs to officers as part of its LTIP. The number of shares of the Company’s common stock issued to settle PSUs ranges from zero to two times the number of PSUs granted and is determined based on performance achievement against certain criteria over a three-year performance period. PSUs generally vest and settle on the third anniversary of the date of the grant. Dual-criteria PSUs. Performance achievement is determined based on two criteria. The first criterion is based on a comparison of the Company’s absolute and relative total shareholder return (“TSR”) for the performance period compared with the TSRs of a group of peer companies for the same performance period. The 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, plus (ii) dividends paid, minus (iii) the volume-weighted average share price for the 30 trading days preceding the beginning of the performance period, by (B) the volume-weighted average share price for the 30 trading days preceding the beginning of the performance period. The second criterion is based on the Company's annual return on average capital employed (“ROCE”) for each year during the three-year performance period. The total number of dual-criteria PSUs granted under the LTIP was split as follows for the relevant grant years: 2021 2020 2019 TSR 100 % 67 % 50 % ROCE — % 33 % 50 % As these awards depend on a combination of performance-based settlement criteria and market-based settlement criteria, compensation expense may be adjusted in future periods as the number of units expected to vest increases or decreases based on the Company’s expected ROCE performance relative to the applicable peer companies. ATSR PSUs. Performance achievement for the PSUs assumed under the Extraction Equity Plan is determined based on a single criterion based on the Company's annualized absolute total stockholder return (“ATSR”). The ATSR is determined based upon the performance of the Company's common stock relative to a baseline price established at the grant date. Of the grant-date fair value, the portion of the PSUs tied to the TSR and ATSR performance required a stochastic process method using a Brownian Motion simulation. A stochastic process is a mathematically defined equation that can create a series of outcomes over time. These outcomes are not deterministic in nature, which means that by iterating the equations multiple times, different results will be obtained for those iterations. In the case of the Company’s PSUs tied to TSR and ATSR performance, the Company could not predict with certainty the path its stock price or the stock prices of its peers would take over the performance period. By using a stochastic simulation, the Company created multiple prospective stock pathways, statistically analyzed these simulations, and ultimately made inferences regarding the most likely path the stock price would take. As such, because future stock prices are stochastic, or probabilistic with some direction in nature, the stochastic method, specifically the Brownian Motion Model, was deemed an appropriate method by which to determine the fair value of the portion of the PSUs tied to the TSR and ATSR. Significant assumptions used in this simulation include the Company’s expected volatility, risk-free interest rate based on U.S. Treasury yield curve rates with maturities consistent with the performance period, as well as the volatilities for each of the Company’s peers. The following table presents the assumptions used to determine the fair value of the PSUs associated with the market-based settlement criteria as granted under the LTIP: Year Ended December 31, 2021 2020 2019 TSR Expected term (in years) 3 3 3 Risk-free interest rate 0.30 % 0.22 % 2.26 % Expected daily volatility 3.8 % 3.5 % 2.6 % ATSR Expected term (in years) 2.2 Risk-free interest rate 0.56 % Expected daily volatility 4.7 % The fair value of the PSUs granted under the LTIP during the years-ended December 31, 2021, 2020, and 2019, was $15.6 million, $1.9 million, and $2.3 million, respectively. Of the total fair value of the PSUs assumed by the Company as a result of the Extraction Merger, $2.9 million was allocated to consideration transferred. The PSUs tied to TSR performance granted in 2019 vested as of December 31, 2021, with 200% distribution of shares to the recipients. The PSUs tied to ROCE performance granted in 2019 expired as of December 31, 2021, with zero distribution of shares to the recipients. A summary of the status and activity of non-vested PSUs for the year ended December 31, 2021 is presented below: PSUs (1) Weighted-Average Grant-Date Fair Value Non-vested, beginning of year 185,588 $ 22.63 Granted or assumed 177,034 88.13 Vested (43,255) 32.68 Non-vested, end of year 319,367 $ 57.58 ___________________________ (1) The number of awards assumes that the associated performance condition is met at the target amount. The final number of shares of the Company’s common stock issued may vary depending on the performance multiplier, which ranges from zero to two, depending on the level of satisfaction of the performance condition. Cash flows resulting from excess tax benefits are to be classified as part of cash flows from operating activities. Excess tax benefits are realized tax benefits from tax deductions for vested stock compensation awards in excess of the deferred tax asset attributable to stock compensation costs for such restricted stock. Excess tax benefits recorded RSUs, DSUs, and PSUs that vested during the year ended December 31, 2021 were $0.7 million. The Company recorded no excess tax benefits for the years ended December 31, 2020 and 2019. Stock Options The LTIP allows for the issuance of stock options to the Company's employees at the sole discretion of the Board. Options expire ten years from the grant date unless otherwise determined by the Board. Compensation expense on the stock options is recognized as general and administrative expense over the vesting period of the award. There were no stock options granted during 2021, 2020, and 2019. Stock options are valued using a Black-Scholes Model where expected volatility is based on an average historical volatility of a peer group selected by management over a period consistent with the expected life assumption on the grant date, the risk-free rate of return is based on the U.S. Treasury constant maturity yield on the grant date with a remaining term equal to the expected term of the awards, and the Company’s expected life of stock option awards is derived from the midpoint of the average vesting time and contractual term of the awards. A summary of the status and activity of non-vested stock options for the year ended December 31, 2021 is presented below: Stock Options Weighted- Weighted-Average Remaining Contractual Term (in years) Aggregate Intrinsic Value (in thousands) Outstanding, beginning of year 72,368 $ 34.36 Exercised (46,309) 34.36 Forfeited (510) 34.36 Outstanding, end of year 25,549 $ 34.36 5.0 $ 373 Options outstanding and exercisable 25,549 $ 34.36 5.0 $ 373 The aggregate intrinsic value of options exercised during the year ended December 31, 2021 was $0.7 million. |
FAIR VALUE MEASUREMENTS
FAIR VALUE MEASUREMENTS | 12 Months Ended |
Dec. 31, 2021 | |
Fair Value Disclosures [Abstract] | |
FAIR VALUE MEASUREMENTS | FAIR VALUE MEASUREMENTS The Company follows authoritative accounting guidance for measuring the fair value of assets and liabilities in its financial statements. This guidance defines fair value as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date. Further, this guidance establishes a hierarchy for inputs used in measuring fair value that maximizes the use of observable inputs and minimizes the use of unobservable inputs by requiring that the most observable inputs be used when available. The fair value hierarchy is broken down into three levels based on the reliability of the inputs as follows: Level 1: Quoted prices in active markets for identical assets or liabilities Level 2: Quoted prices in active markets for similar assets and liabilities, quoted prices for identical or similar instruments in markets that are not active, and model-derived valuations whose inputs are observable or whose significant value drivers are observable Level 3: Significant inputs to the valuation model are unobservable Financial and non-financial assets and liabilities are classified based on the lowest level of input that is significant to the fair value measurement. The Company’s assessment of the significance of a particular input to the fair value measurement requires judgment and may affect the valuation of the fair value of assets and liabilities and their placement within the fair value hierarchy. Derivatives The Company uses Level 2 inputs to measure the fair value of oil, gas, and NGL commodity price derivatives. The fair value of the Company's commodity price derivatives is estimated using industry-standard models that contemplate various inputs including, but not limited to, the contractual price of the underlying position, current market prices, forward commodity price curves, volatility factors, time value of money, and the credit risk of both the Company and its counterparties. We validate our fair value estimate by corroborating the original source of inputs, monitoring changes in valuation methods and assumptions, and reviewing counterparty mark-to-market statements and other supporting documentation. Refer to Note 9 – Derivatives for more information regarding the Company’s derivative instruments. The following tables present the Company’s financial assets and liabilities that were accounted for at fair value on a recurring basis as of December 31, 2021 and 2020 and their classification within the fair value hierarchy (in thousands): As of December 31, 2021 Level 1 Level 2 Level 3 Derivative assets $ — $ 3,393 $ — Derivative liabilities $ — $ 239,763 $ — As of December 31, 2020 Level 1 Level 2 Level 3 Derivative assets $ — $ 7,482 $ — Derivative liabilities $ — $ 7,732 $ — Long-Term Debt The 7.5% Senior Notes and 5.0% Senior Notes are recorded at cost, net of any unamortized deferred financing costs. The fair value as of December 31, 2021 for the 7.5% Senior Notes and 5.0% Senior Notes was $101.0 million and $404.7 million, respectively. These fair values are based on quoted market prices, and as such, are designated as Level 1 within the fair value hierarchy. The recorded value of the Company’s Credit Facility approximates its fair value as it bears interest at a floating rate that approximates a current market rate. Please refer to Note 5 – Long-Term Debt for additional information. Warrants As discussed in Note 2 - Acquisitions and Divestitures , the Company issued warrants in connection with the Extraction Merger. The warrants issued are indexed to the Company’s common stock and are required to be net share settled via a cashless exercise. The Company evaluated the warrants under authoritative accounting guidance and determined that they should be classified as equity instruments. The Company's share price traded below the exercise price of the replacement warrants and therefore were not exercisable during the year ended December 31, 2021. The fair value of the warrants on the issuance date was determined using the Cox-Ross-Rubinstein binomial option pricing model. The warrants were included as a component of merger consideration and are recorded within additional paid-in capital on the accompanying balance sheets at a fair value of $77.5 million, with no recurring fair value measurement required. There have been no changes to the initial carrying amount of the warrants since issuance. Acquisitions and Impairments of Proved Properties We utilize the acquisition method to account for acquisitions of businesses. Pursuant to this method, we allocate the cost of the acquisition, or purchase price, to assets acquired and liabilities assumed based on fair values as of the acquisition date. Proved and unproved properties are valued based on a discounted cash flow approach utilizing Level 3 inputs, including, amongst other things, reserve quantities and classification, pace of drilling plans, future commodity prices, future development and lease operating costs, and discount rates using a market-based weighted average cost of capital determined at the time of the acquisition. When estimating the fair value of unproved properties, additional risk-weighting adjustments are applied to probable and possible reserves. Net derivative liabilities assumed are valued based on Level 2 inputs similar to the Company's other commodity price derivatives. Whenever events or circumstances indicate that the carrying value of proved properties may not be recoverable, the Company uses Level 3 inputs to measure and record impairment at fair value. There were no proved oil and gas property impairments during the years ended December 31, 2021, 2020, and 2019. |
DERIVATIVES
DERIVATIVES | 12 Months Ended |
Dec. 31, 2021 | |
Derivative Instruments and Hedging Activities Disclosure [Abstract] | |
DERIVATIVES | DERIVATIVES The Company periodically enters into commodity price derivative instruments to mitigate a portion of its exposure to potentially adverse market changes in commodity prices for its expected future oil, natural gas, and NGL production and the associated impact on cash flows. These instruments typically include commodity price swaps and collars, as well as, basis differential and roll differential swaps. All commodity price derivative instruments are entered into for other-than-trading purposes. The Company does not designate its commodity price derivative contracts as hedging instruments. In a typical commodity price swap agreement, if the agreed upon published third-party index price is lower than the strike price at the time of settlement, the Company receives the difference between the index price and the agreed upon strike price. If the index price is higher than the agreed upon strike price at the time of settlement, the Company pays the difference. A swaption allows the counterparty, on a specific date, to extend an existing fixed-price swap for a certain period of time or to increase the notional volumes of an existing fixed-price swap. A collar arrangement establishes a floor and ceiling price on future oil and gas production. When the settlement price is above the ceiling price, the Company pays the difference between the settlement price and the ceiling price. When the settlement price is below the floor price, the Company receives the difference between the settlement price and floor price. In the event that the settlement price is between the ceiling and the floor, no payment or receipt occurs. A basis differential swap arrangement guarantees a price differential from a specified delivery point to an agreed upon reference point. The Company receives the difference between the price differential and the stated terms, if the price differential is greater than the stated terms. The Company pays the difference between the price differential and the stated terms, if the stated terms are greater than the price differential. Certain NYMEX calendar month average (“CMA”) settlement contracts contain a “CMA Roll Adjustment,” the calculation of which includes futures prices for contracts deliverable in, at the time, two forward months. The physical trade month average is compared to the prompt month futures contracts and weighted to reflect the amount of time during the delivery month that the forward months traded as the prompt month. The weighted adjustment values are added to the basic calendar month average to arrive at the Roll Adjusted settlement price for the month. “Oil roll swaps” fix the value of the roll adjustment. If the futures curve becomes more backwardated after entering the oil roll swap, we will pay the difference between the CMA Roll Adjustment and the oil roll swap price. If the futures curve becomes more in contango, we will receive the difference between the CMA Roll Adjustment and the oil roll swap price. A put gives the owner the right to sell the underlying commodity at a set price over the term of the contract. If the index settlement price is higher than the put fixed price, the put will expire worthless. If the settlement price is lower than the put fixed price, the Company will exercise the put and receive the difference between the settlement price and the put fixed price. As of December 31, 2021, the Company had entered into the following commodity price derivative contracts: Crude Oil Natural Gas Natural Gas Natural Gas Liquids Bbls/day Weighted Avg. Price per Bbl MMBtu/day Weighted Avg. Price per MMBtu MMBtu/day Weighted Avg. Price per MMBtu Bbls/day Weighted Avg. Price per Bbl 1Q22 Collar 15,700 $43.83/$59.77 — — 20,000 $2.15/$2.75 — — Swap 15,371 $47.39 125,170 $2.90 10,000 $2.13 4,000 $20.22 Oil roll swap (1) 2,000 $0.22 — — — — — — 2Q22 Collar 8,800 $38.09/$67.48 60,375 $2.50/$3.50 20,000 $2.15/$2.75 — — Swap 10,139 $49.84 53,300 $2.77 10,000 $2.13 4,000 $20.22 Oil roll swap (1) 2,000 $0.22 — — — — — — 3Q22 Collar 7,681 $40.35/$69.99 78,420 $2.59/$3.68 — — — — Swap 9,359 $46.88 53,300 $2.77 10,000 $2.13 4,000 $20.22 Oil roll swap (1) 2,000 $0.22 — — — — — — 4Q22 Collar 6,938 $40.75/$70.99 76,929 $2.60/$3.69 — — — — Swap 8,686 $46.77 53,300 $2.77 10,000 $2.13 4,000 $20.22 Oil roll swap (1) 2,000 $0.22 — — — — — — 2023 Collar 260 $40.00/$72.70 2,184 $2.00/$3.25 — — — — Swap 200 $46.05 43,600 $2.51 — — — — 2024 Swap — — 22,309 $2.57 — — — — _______________________________ (1) The weighted average differential represents the amount of reduction to NYMEX WTI prices for the notional volumes covered by the swap contracts. The Company did not enter into any commodity price derivative contracts subsequent to December 31, 2021 through the filing of this report other than those novated from Bison as described in Note 14 - Subsequent Events. Derivative Assets and Liabilities Fair Value The Company’s commodity price derivatives are measured at fair value and are included in the accompanying balance sheets as derivative assets and liabilities. The following table contains a summary of all the Company’s derivative positions reported on the accompanying balance sheets as well as a reconciliation between the gross assets and liabilities and the potential effects of master netting arrangements on the fair value of the Company’s commodity derivative contracts as of December 31, 2021 and 2020 (in thousands): As of December 31, 2021 2020 Derivative Assets: Commodity contracts - current $ 3,393 $ 7,482 Commodity contracts - noncurrent — — Total derivative assets 3,393 7,482 Amounts not offset in the accompanying balance sheets (3,393) (4,758) Total derivative assets, net $ — $ 2,724 Derivative Liabilities: Commodity contracts - current $ (219,804) $ (6,402) Commodity contracts - long-term (19,959) (1,330) Total derivative liabilities (239,763) (7,732) Amounts not offset in the accompanying balance sheets 3,393 4,758 Total derivative liabilities, net $ (236,370) $ (2,974) The following table summarizes the components of the derivative gain (loss) presented on the accompanying statements of operations for the periods below (in thousands): Year Ended December 31, 2021 2020 2019 Derivative cash settlement gain (loss): Oil contracts $ (215,057) $ 50,133 $ 1,185 Gas contracts (51,806) (727) 506 NGL contracts (9,051) — — Total derivative cash settlement gain (loss) (1) (275,914) 49,406 1,691 Change in fair value gain (loss) 215,404 4,056 (38,836) Total derivative gain (loss) (1) $ (60,510) $ 53,462 $ (37,145) ___________________________ (1) Total derivative gain (loss) and total derivative cash settlement gain (loss) for each of the periods presented above is reported in the derivative (gain) loss line item and derivative cash settlements gain (loss) line item in the accompanying statements of cash flows, within the cash flows from operating activities. |
ASSET RETIREMENT OBLIGATIONS
ASSET RETIREMENT OBLIGATIONS | 12 Months Ended |
Dec. 31, 2021 | |
Asset Retirement Obligation Disclosure [Abstract] | |
ASSET RETIREMENT OBLIGATIONS | ASSET RETIREMENT OBLIGATIONS The Company recognizes an estimated liability for future costs associated with the abandonment of its oil and gas properties, including facilities requiring decommissioning. A liability for the fair value of an asset retirement obligation and corresponding increase to the carrying value of the related long-lived asset are recorded at the time a well is drilled or acquired, or a facility is constructed. The increase in carrying value is included in the proved oil and gas properties line item in the accompanying balance sheets. The Company depletes the amount added to proved oil and gas property costs and recognizes expense in connection with the accretion of the discounted liability over the remaining estimated economic lives of the respective long-lived assets. Cash paid to settle asset retirement obligations is included in the cash flows from operating activities section of the accompanying statements of cash flows. The Company’s estimated asset retirement obligation liability is based on historical experience plugging and abandoning wells, estimated economic lives, estimated plugging and abandonment cost, and regulatory requirements. The liability is discounted using the credit-adjusted risk-free rate estimated at the time the liability is incurred or revised. A roll-forward of the Company's asset retirement obligation is as follows (in thousands): Year Ended December 31, 2021 2020 Balance, beginning of year $ 28,699 $ 27,908 Additional liabilities incurred 183,758 357 Accretion expense 3,933 1,004 Liabilities settled (4,221) (2,464) Revisions to estimate 13,146 1,894 Balance, end of year $ 225,315 $ 28,699 Current portion 24,000 — Long-term portion $ 201,315 $ 28,699 Revisions to estimates for the year ended December 31, 2021 |
EARNINGS PER SHARE
EARNINGS PER SHARE | 12 Months Ended |
Dec. 31, 2021 | |
Earnings Per Share [Abstract] | |
EARNINGS PER SHARE | EARNINGS PER SHARE Earnings per basic and diluted share are calculated under the treasury stock method. Basic net income (loss) per common share is calculated by dividing net income (loss) by the basic weighted-average common shares outstanding for the respective period. Diluted net income (loss) per common share is calculated by dividing net income (loss) by the diluted weighted-average common shares outstanding, which includes the effect of potentially dilutive securities. Potentially dilutive securities for this calculation consist of unvested RSUs, DSUs, PSUs as well as outstanding in-the-money stock options and warrants. When the Company recognizes a loss from continuing operations, all potentially dilutive shares are anti-dilutive and are consequently excluded from the calculation of diluted earnings per share. The Company issues RSUs and DSUs, which represent the right to receive, upon vesting, one share of the Company's common stock. The number of potentially dilutive shares related to unvested RSUs and DSUs is based on the number of shares, if any, that would be issuable at the end of the respective reporting period, assuming that date was the end of the vesting period. The Company issues PSUs, which represent the right to receive, upon settlement of the PSUs, a number of shares of the Company's common stock that ranges from zero to two times the number of PSUs granted on the award date. The number of potentially dilutive shares related to PSUs is based on the number of shares, if any, that would be issuable at the end of the respective reporting period, assuming that date was the end of the performance period applicable to such PSUs. The Company has also issued stock options and warrants, which both represent the right to purchase the Company's common stock at a specified exercise price. The number of potentially dilutive shares related to the stock options and warrants is based on the number of shares, if any, that would be exercisable at the end of the respective reporting period, assuming the date was the end of such stock options' or warrants' term. Stock options and warrants are only dilutive when the average price of the common stock during the period exceeds the exercise price. Please refer to Note 7 - Stock-Based Compensation for additional discussion. The following table sets forth the calculations of basic and diluted net income per common share (in thousands, except per share amounts): Year Ended December 31, 2021 2020 2019 Net income $ 178,921 $ 103,528 $ 67,067 Basic net income per common share $ 4.82 $ 4.98 $ 3.25 Diluted net income per common share $ 4.74 $ 4.95 $ 3.24 Weighted-average shares outstanding - basic 37,155 20,774 20,612 Add: dilutive effect of contingent stock awards 591 138 69 Weighted-average shares outstanding - diluted 37,746 20,912 20,681 |
INCOME TAXES
INCOME TAXES | 12 Months Ended |
Dec. 31, 2021 | |
Income Tax Disclosure [Abstract] | |
INCOME TAXES | INCOME TAXES Deferred tax assets and liabilities are measured by applying the provisions of enacted tax laws to determine the amount of taxes payable or refundable currently or in future years related to cumulative temporary differences between the tax basis of assets and liabilities and amounts reported in the accompanying balance sheets. The tax effect of the net change in the cumulative temporary differences during each period in the deferred tax assets and liabilities determines the periodic provision for deferred taxes. The provision for income taxes consists of the following (in thousands): Year Ended December 31, 2021 2020 2019 Current tax expense (benefit) Federal $ — $ (27) $ — State — — — Total current tax expense (benefit) — (27) — Deferred tax expense (benefit) Federal 62,212 (53,784) — State 10,646 (6,736) — Total deferred tax expense (benefit) 72,858 (60,520) — Total income tax expense (benefit) $ 72,858 $ (60,547) $ — Temporary differences between the financial statement carrying amounts and tax basis of assets and liabilities that give rise to the net deferred tax asset result from the following components (in thousands): As of December 31, 2021 2020 Deferred tax liabilities: Oil and gas properties $ 608,829 $ 89,867 Right-of-use assets 8,292 7,306 Total deferred tax liabilities 617,121 97,173 Deferred tax assets: Federal and state tax net operating loss carryforward 482,216 138,372 Derivative instruments 86,958 61 Reclamation costs 51,515 7,058 Stock compensation 7,622 1,653 Inventory 10,108 1,598 Lease liability 8,187 7,384 Property taxes 19,458 — Pending acquisition costs — 1,478 Other long-term assets 21,474 89 Total deferred tax assets 687,538 157,693 Less: Valuation allowance 48,133 — Total deferred tax assets after valuation allowance 639,405 157,693 Total non-current net deferred tax asset $ 22,284 $ 60,520 On April 1, 2021, the Company completed the HighPoint Merger. For federal income tax purposes we acquired carryover tax basis in HighPoint’s assets and liabilities, including $219.0 million of federal net operating loss carryforwards. We recorded a net deferred tax asset of $110.5 million as part of the business combination accounting for HighPoint. The net operating loss carryforwards and other tax attributes will be subject to an annual limitation under Section 382 of the Code of approximately $5.6 million. We determined that a separate valuation allowance of $48.1 million was required to be established through business combination accounting against the deferred tax assets acquired. On November 1, 2021, the Company completed the Extraction Merger. For federal income tax purposes we acquired carryover tax basis in Extraction’s assets and liabilities, including $479.9 million of federal net operating loss carryforwards. We recorded a net deferred tax asset of $49.2 million as part of the business combination accounting for Extraction. The net operating loss carryforwards will be subject to an annual limitation under Section 382 of the Code of approximately $7.0 million. We determined that no separate valuation allowance was required to be established through business combination accounting against the deferred tax assets acquired. On November 1, 2021, the Company completed the Crestone Peak Merger. For federal income tax purposes we acquired carryover tax basis in Crestone Peak’s assets and liabilities, including $555.7 million of federal net operating loss carryforwards. We recorded a net deferred tax liability of $125.1 million as part of the business combination accounting for Crestone Peak. The net operating loss carryforwards will be subject to an annual limitation under Section 382 of the Code of approximately $16.8 million. We determined that no separate valuation allowance was required to be established through business combination accounting against the deferre d tax assets acquired. The Company has $2.0 billion and $579.4 million of net operating loss carryovers for federal income tax purposes as of December 31, 2021 and 2020, respectively. The significant increase in net operating loss carryovers resulted from the HighPoint, Extraction, and Crestone Peak mergers as discussed above. Due to change of ownership provisions of Section 382 of the Code, utilization of these acquired net operating loss carryovers and other tax attributes may be limited. Federal net operating loss carryforwards incurred prior to January 1, 2018 of $696.3 million will begin to expire in 2034. Federal net operating loss carryforwards incurred after December 31, 2017 of $1.3 billion have no expiration and can only be used to offset 80% of taxable income when utilized. 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. On the basis of this evaluation, the Company recorded a valuation allowance of $72.6 million on its net deferred tax assets as of December 31, 2019, which was removed in 2020. During 2021, as a result of the HighPoint Merger, the Company recorded a valuation allowance of $48.1 million against certain acquired net operating losses and other tax attributes due to the limitation on realizability caused by the change of ownership provisions of Section 382 of the Code. The Company will continue to monitor facts and circumstances in the reassessment of the likelihood that the deferred tax assets will be realized. Federal income tax expense differs from the amount that would be provided by applying the statutory United States federal income tax rate of 21% to income before income taxes primarily due to the effect of state income taxes, changes in valuation allowances, rate changes, and other permanent differences, as follows (in thousands): Year Ended December 31, 2021 2020 2019 Federal statutory tax expense $ 52,824 $ 9,026 $ 14,084 Increase (decrease) in tax resulting from: State tax expense net of federal benefit 10,646 1,694 2,537 Prior year true-up 27 292 (579) Stock compensation (1,559) 690 197 Permanent differences 84 36 128 State rate change — 124 — Transaction costs 9,043 — — Section 162(m) limitation 1,793 144 156 Valuation allowance — (72,553) (16,523) Total income tax expense (benefit) $ 72,858 $ (60,547) $ — During the year ended December 31, 2021, the increase in tax rate was primarily due to non-deductible transaction costs incurred in connection with the HighPoint, Extraction, and Crestone Peak mergers, along with net income increasing between the comparable periods. There was $72.9 million of deferred income tax expense in the accompanying statements of operations. During the year ended December 31, 2020, the decrease in tax rate was primarily due to fully removing the valuation allowance against net deferred tax assets and net income decreasing between the comparable periods. There was $60.5 million of deferred income tax benefit in the accompanying statements of operations. The valuation allowance decreased by $72.6 million to zero in 2020 when compared to the same period in 2019 due to both current and forecasted book income. During the year ended December 31, 2019, there were no deferred income tax benefits or expense in the accompanying statements of operations. The valuation allowance decreased by $16.5 million to $72.6 million in 2019 when compared to the same period in 2018. The Company's net income decreased between the comparable periods causing the federal tax benefit to decrease. The Company had no unrecognized tax benefits as of December 31, 2021, 2020, and 2019. The tax returns for 2020, 2019, and 2018 are still subject to audit by the Internal Revenue Service. |
DISCLOSURES ABOUT OIL AND GAS P
DISCLOSURES ABOUT OIL AND GAS PRODUCING ACTIVITIES (UNAUDITED) | 12 Months Ended |
Dec. 31, 2021 | |
Results of Operations, Revenue from Oil and Gas Producing Activities [Abstract] | |
DISCLOSURES ABOUT OIL AND GAS PRODUCING ACTIVITIES (UNAUDITED) | DISCLOSURES ABOUT OIL AND GAS PRODUCING ACTIVITIES (UNAUDITED) The Company’s oil and natural gas activities are located entirely within the United States. Costs incurred in oil and natural gas producing activities are as follows (in thousands): Year Ended December 31, 2021 2020 2019 Acquisition (1) $ 4,861,619 $ 11,296 $ 12,901 Development (2)(3) 315,746 55,934 209,535 Exploration 7,937 595 796 Total $ 5,185,302 $ 67,825 $ 223,232 _________________________ (1) Acquisition costs for unproved properties for the years ended December 31, 2021, 2020, and 2019 were $648.0 million, $2.3 million, and $4.2 million, respectively. There were $4.2 billion, $9.0 million, and $8.7 million in acquisition costs for proved properties for the years ended December 31, 2021, 2020, and 2019, respectively. (2) Development costs include workover costs of $2.2 million, $1.2 million, and $1.4 million charged to lease operating expense for the years ended December 31, 2021, 2020, and 2019, respectively. (3) Includes amounts relating to asset retirement obligations of $13.8 million, $(1.0) million, and $(0.9) million, for the years ended December 31, 2021, 2020, and 2019, respectively. Suspended Well Costs The Company did not incur any exploratory well costs during the years ended December 31, 2021, 2020, and 2019. Reserves The proved reserve estimates were prepared by our third party independent reserve engineers, which were Ryder Scott at December 31, 2021 and 2020 and NSAI for the estimates at December 31, 2019. The estimates of proved reserves are inherently imprecise and are continually subject to revision based on production history, results of additional exploration and development, price changes, and other factors. All of the Company’s oil, natural gas liquids, and natural gas reserves are attributable to properties within the United States. A summary of the Company's changes in quantities of proved oil, natural gas liquids, and natural gas reserves for the years ended December 31, 2021, 2020, and 2019 are as follows: Natural Natural Oil Gas Gas Liquids (MBbl) (MMcf) (MBbl) Balance-December 31, 2018 64,354 165,012 24,930 Extensions, discoveries and infills (1) 8,825 20,604 3,123 Production (5,136) (11,967) (1,431) Sales of minerals in place (52) (110) (18) Removed from capital program (2) (4,926) (11,508) (1,862) Purchases of minerals in place 303 627 102 Revisions to previous estimates (3) 1,045 49,542 (2,683) Balance-December 31, 2019 64,413 212,200 22,161 Extensions, discoveries and infills (1) 9,376 32,172 3,269 Production (5,019) (14,166) (1,858) Removed from capital program (2) (14,120) (33,886) (3,141) Purchases of minerals in place 1,430 5,457 570 Revisions to previous estimates (3) (3,287) 33,951 5,110 Balance-December 31, 2020 52,793 235,728 26,111 Extensions, discoveries and infills (1) 19 103 — Production (4,523) (13,852) (1,763) Removed from capital program (2) (12,249) (43,918) (4,485) Purchases of minerals in place 114,379 767,504 89,797 Revisions to previous estimates (3) (6,840) (57,066) (3,632) Balance-December 31, 2021 143,579 888,499 106,028 Proved developed reserves: December 31, 2019 25,397 105,840 11,566 December 31, 2020 24,320 123,220 14,315 December 31, 2021 104,078 748,762 88,967 Proved undeveloped reserves: December 31, 2019 39,016 106,360 10,595 December 31, 2020 28,473 112,508 11,796 December 31, 2021 39,501 139,737 17,061 ________________________ (1) During the years ended December 31, 2021, 2020, and 2019, horizontal development in the Wattenberg Field resulted in additions in extensions, discoveries, and infills of nominal MMBoe, 18.0 MMBoe, and 15.4 MMBoe, respectively. (2) During the years ended December 31, 2021, 2020, and 2019, proved undeveloped reserves were reduced by 24.1 MMBoe, 22.9 MMBoe, and 8.7 MMBoe respectively, primarily due to the removal of proved undeveloped locations from our five-year drilling program. (3) As of December 31, 2021, the Company revised its proved reserves downward by 20.0 MMBoe primarily driven by 13.1 MMBoe in negative revisions due to changes in well operating cost methodology, 6.9 MMBoe in negative engineering revisions, and 7.1 MMBoe in negative revisions for fuel gas, interest, shrink, and other minor revisions. The commodity prices at December 31, 2021 increased to $66.56 per Bbl WTI and $3.60 per MMBtu HH from $39.57 per Bbl WTI and $1.99 per MMBtu HH at December 31, 2020, resulting in a partially offsetting positive revision of 7.1 MMBoe. As of December 31, 2020, the Company revised its proved reserves upward by 7.5 MMBoe primarily driven by 12.3 MMBoe in positive engineering revisions. The commodity prices at December 31, 2020 decreased to $39.57 per Bbl WTI and $1.99 per MMBtu HH from $55.85 per Bbl WTI and $2.58 per MMBtu HH at December 31, 2019, resulting in a partially offsetting negative revision of 4.8 MMBoe. As of December 31, 2019, the Company revised its proved reserves upward by 6.6 MMBoe. The commodity prices at December 31, 2019 decreased to $55.85 per Bbl WTI and $2.58 per MMBtu HH from $65.56 per Bbl WTI and $3.10 per MMBtu HH at December 31, 2018, resulting in a negative revision of 1.4 MMBoe, offset by 8.1 MMBoe in positive engineering revision. The standardized measure of discounted future net cash flows relating to proved oil and natural gas reserves were prepared in accordance with accounting authoritative guidance. Future cash inflows were computed by applying prices to estimated future production. Future production and development costs are computed by estimating the expenditures to be incurred in developing and producing the proved oil and natural gas reserves at year-end, based on current costs and assuming continuation of existing economic conditions. Future income tax expenses are calculated by applying appropriate year-end tax rates to future pretax net cash flows relating to proved oil and natural gas reserves. Future income tax expenses give effect to permanent differences, tax credits, and loss carryforwards relating to the proved oil and natural gas reserves. Future net cash flows are discounted at a rate of 10% annually to derive the standardized measure of discounted future net cash flows. This calculation procedure does not necessarily result in an estimate of the fair market value or the present value of the Company's oil and natural gas properties. The standardized measure of discounted future net cash flows relating to proved oil and natural gas reserves are as follows (in thousands): Year Ended December 31, 2021 2020 2019 Future cash flows $ 14,401,814 $ 2,230,012 $ 3,827,009 Future production costs (5,054,695) (675,755) (1,029,140) Future development costs (1,107,576) (530,970) (850,327) Future income tax expense (1,465,949) — — Future net cash flows 6,773,594 1,023,287 1,947,542 10% annual discount for estimated timing of cash flows (2,361,490) (586,233) (1,089,395) Standardized measure of discounted future net cash flows $ 4,412,104 $ 437,054 $ 858,147 Future cash flows as shown above were reported without consideration for the effects of derivative transactions outstanding at period end. The changes in the standardized measure of discounted future net cash flows relating to proved oil and natural gas reserves are as follows (in thousands): Year Ended December 31, 2021 2020 2019 Beginning of period $ 437,054 $ 858,147 $ 954,980 Sale of oil and gas produced, net of production costs (773,711) (160,466) (233,677) Net changes in prices and production costs 874,155 (641,137) (372,233) Net changes in extensions, discoveries and improved recoveries 855 (54,269) 45,728 Development costs incurred 108,113 42,325 185,086 Changes in estimated development cost 106,788 220,964 81,358 Purchases of minerals in place 4,484,125 12,372 10,135 Sales of minerals in place — — (309) Revisions of previous quantity estimates (84,126) 60,754 79,637 Net change in income taxes (915,053) — — Accretion of discount 43,705 85,815 95,498 Changes in production rates and other 130,199 12,549 11,944 End of period $ 4,412,104 $ 437,054 $ 858,147 The average wellhead prices used in determining future net revenues related to the standardized measure calculation as of December 31, 2021, 2020, and 2019 were calculated using the twelve-month arithmetic average of first-day-of-the-month prices inclusive of adjustments for quality and location. Year Ended December 31, 2021 2020 2019 Oil (per Bbl) $ 61.60 $ 34.96 $ 51.22 Gas (per Mcf) $ 2.60 $ 0.95 $ 1.44 Natural gas liquids (per Bbl) $ 30.60 $ 6.12 $ 10.07 |
SUBSEQUENT EVENTS
SUBSEQUENT EVENTS | 12 Months Ended |
Dec. 31, 2021 | |
Subsequent Events [Abstract] | |
Subsequent Events | SUBSEQUENT EVENTSOn January 31, 2022, the Company signed definitive agreements to acquire privately held DJ Basin operator Bison Oil & Gas II, LLC (“Bison”) for approximately $346 million of consideration, including the assumption of approximately $176 million in debt and other liabilities. On February 27, 2022, the Company and Bison entered into an amendment to the definitive agreements signed on January 31, 2022 to, among other things, increase the aggregate cash consideration paid to Bison from $45 million to $160 million and eliminate the previously contemplated share consideration. The transaction closed on March 1, 2022. As of March 1, 2022, the following commodity price derivative contracts were novated from Bison: Crude Oil Natural Gas Bbls/day Weighted Avg. Price per Bbl MMBtu/day Weighted Avg. Price per MMBtu 2022 (1) Collar (2, 3) 2,756 $47.85 / $56.71 2,278 $2.67 / $3.39 Swap 873 $47.38 1,582 $2.52 2023 Collar (2, 3) 1,406 $48.62 / $57.71 1,828 $2.36 / $2.98 Swap 208 $46.47 470 $2.51 2024 Collar (2, 3) 143 $45.00 / $56.25 1,337 $2.40 / $3.15 Swap 479 $53.96 — — _______________________________ (1) Represents hedged volumes from the closing date through December 31, 2022. (2) 79%, 100%, and 100% of the 2022, 2023, and 2024 oil collars presented include sold puts at a weighted average price of $38.72, $38.38, and $35.00 per Bbl, respectively (3) 5%, 19%, and 23% of the 2022, 2023, and 2024 gas collars presented include sold puts at a weighted average price of $2.00 per MMBtu, respectively. |
SUMMARY OF SIGNIFICANT ACCOUN_2
SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Policies) | 12 Months Ended |
Dec. 31, 2021 | |
Accounting Policies [Abstract] | |
Basis of Presentation | Basis of Presentation The consolidated financial statements include the accounts of the Company. All significant intercompany balances and transactions have been eliminated in consolidation. The consolidated financial statements included herein were prepared from the records of the Company in accordance with GAAP, the instructions to Form 10-K, and Regulation S-X. Additionally, certain prior period amounts have been reclassified to conform to current period presentation in the accompanying financial statements. During the current year, the Company is separately presenting Production taxes payable on the accompanying balance sheets. Accordingly, prior year amounts have been reclassified from Accounts payable and accrued expenses to conform to current year presentation. In connection with the preparation of the consolidated financial statements, the Company evaluated subsequent events after the balance sheet date of December 31, 2021, through the filing date of this report. |
Use of Estimates | Use of EstimatesThe preparation of the consolidated financial statements in conformity with GAAP requires us to make estimates and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses, as well as the disclosure of contingent assets and liabilities and commitments as of the date of our financial statements. Actual results could differ from those estimates. |
Cash and Cash Equivalents | Cash and Cash Equivalents The Company considers all highly liquid investments with original maturity dates of three months or less to be cash equivalents. The carrying value of cash and cash equivalents approximate fair value due to the short-term nature of these instruments. The Company maintains cash balances in excess of federal deposit insurance limits as of December 31, 2021 and 2020, potentially subjecting the Company to a concentration of credit risk. To mitigate this risk, we maintain our cash and cash equivalents in the form of money market and checking accounts with financial institutions that we believe are creditworthy and are also lenders under our Credit Facility. |
Accounts Receivable | Accounts ReceivableThe Company’s accounts receivable primarily consists of receivables due from purchasers of the Company's oil, natural gas, and NGL production and from joint interest owners on properties the Company operates. The Company is exposed to credit risk in the event of nonpayment by the purchasers of its production and/or joint interest owners on the properties it operates, nearly all of which are concentrated in energy-related industries. The Company continuously evaluates the creditworthiness of the Company's purchasers and joint interest owners on the properties it operates. Generally, the Company’s oil, natural gas, and NGLs receivables are collected within one |
Inventory of Oilfield Equipment | Inventory of Oilfield EquipmentInventory of oilfield equipment consists of material and supplies to be used in connection with the Company’s operations. These inventories are recorded and relieved using the weighted average cost method and are stated at the lower of cost or net realizable value, which approximates fair value. |
Property and Equipment | Property and Equipment Proved Properties. The Company accounts for its oil and natural gas properties under the successful efforts method of accounting. Under this method, the costs of development wells are capitalized to proved properties whether those wells are successful or unsuccessful. Capitalized drilling and completion costs, including lease and well equipment, intangible development costs, and operational support facilities are depleted using the units-of-production method based on estimated proved developed reserves. Proved leasehold costs are also depleted; however, the units-of-production method is based on estimated total proved reserves. The computation of depletion expense takes into consideration restoration, dismantlement, and abandonment costs as well as the anticipated proceeds from salvaging equipment. Because all of our proved properties are currently located in a single field, we apply depletion on a single field basis. During the years ended December 31, 2021, 2020, and 2019, the Company incurred depletion expense of $212.5 million, $82.6 million, and $69.3 million, respectively. The Company assesses proved properties for impairment whenever events or circumstances indicate that their carrying value may not be recoverable. If carrying values exceed undiscounted future net cash flows, impairment is measured and recorded at fair value. Because there usually is a lack of quoted market prices for proved properties, the Company estimates the fair value using valuation techniques that convert estimated future net cash flows to a single discounted amount. Significant inputs and assumptions to this estimation include, but are not limited to, reserves volumes, future operating and development costs, future commodity prices, inclusive of applicable differentials, and a market-based weighted average cost of capital rate. The expected future cash flows used for impairment reviews include future production volumes associated with proved developed producing reserves and risk-adjusted proved undeveloped reserves, and when needed, probable and possible reserves. The partial sale of a proved property within an existing field is accounted for as a normal retirement and no net gain or loss on divestiture activity is recognized as long as such treatment does not significantly affect the units-of-production depletion rate. The sale of a partial interest in an individual proved property is accounted for as a recovery of cost. A net gain or loss on divestiture activity is recognized in the accompanying statements of operations for all other sales of proved properties. As of December 31, 2021, the net book value of the Company's midstream assets was $276.1 million in the accompanying balance sheets. Depreciation on the Company's midstream assets is calculated using the straight-line method over the estimated useful lives of the assets and properties they serve, which is approximately 30 years. Unproved Properties. Unproved properties consist of the costs to acquire undeveloped leases and are not subject to depletion until they are transferred to proved properties. Leasehold costs are transferred to proved properties on an ongoing basis as the properties to which they relate are evaluated and proved reserves established. Additional costs not subject to depletion include costs associated with development wells in progress or awaiting completion at year-end. These costs are transferred into costs subject to depletion on an ongoing basis as these wells are completed and proved reserves are established or confirmed. Unproved properties are routinely evaluated for continued capitalization or impairment. On a quarterly basis, management assesses undeveloped leasehold costs for impairment by considering, among other things, remaining lease terms, future drilling plans and capital availability to execute such plans, commodity price outlooks, recent operational results, reservoir performance and geology, and estimated acreage value based on prices received for similar, recent acreage transactions by the Company or other market participants. Changes in our assumptions of the estimated nonproductive portion of our undeveloped leases could result in additional impairment expense. During the years ended December 31, 2021, 2020, and 2019, the Company incurred $57.3 million, $37.3 million, and $11.2 million, respectively, in abandonment and impairment of unproved properties. The partial sale of unproved property is accounted for as a recovery of cost when there is uncertainty of the ultimate recovery of the cost applicable to the interest retained. Exploratory. Exploratory geological and geophysical, including exploratory seismic studies, and the costs of carrying and retaining unproved acreage are expensed as incurred. Under the successful efforts method of accounting, exploratory well costs are capitalized pending further evaluation of whether economically recoverable reserves have been found. If economically recoverable reserves are found, exploratory well costs will be capitalized as proved properties and will be accounted for following the successful efforts method of accounting described above. If economically recoverable reserves are not found, exploratory well costs are expensed as dry holes. The application of the successful efforts method of accounting requires judgment to determine the proper designation of wells as either development or exploratory, which will ultimately determine the proper accounting treatment of costs of dry holes. Once a well is drilled, the determination that economic proved reserves have been discovered may take considerable time and judgment. Exploratory dry hole costs are included in the cash flows from investing activities section as part of exploration and development of oil and natural gas properties within the accompanying statements of cash flows. Oil and Natural Gas Reserves. The successful efforts method of accounting outlined above inherently relies on the estimation of proved oil and natural gas reserves. Reserve quantities and the related estimates of future net cash flows are critical inputs in our calculation of units-of-production depletion and our evaluation of proved and unproved properties for impairment. The process of estimating and evaluating crude oil and natural gas reserves is complex, requiring the evaluation of available geological, geophysical, engineering and economic data to estimate underground accumulations of oil and natural gas that cannot be precisely measured. Consequently, the Company engages a third-party petroleum consultant to prepare our estimates of oil and natural gas reserves. Significant inputs and engineering assumptions used in developing the estimates of proved oil and natural gas reserves include reserves volumes, future operating and development costs, historical commodity prices, and the Company’s ability to convert proved undeveloped reserves to producing properties within five years of their initial proved booking. The data for a given property may also change substantially over time as a result of numerous factors, including additional development activity, evolving production history and a continual reassessment of the viability of production under changing economic conditions. As a result, revisions in existing reserve estimates occur. We cannot predict the amounts or timing of such future revisions. If such revisions are significant, they could significantly affect future amortization of capitalized costs and result in impairment of proved property. |
Other Property and Equipment | Other Property and Equipment Other property and equipment such as office furniture and equipment, buildings, and computer hardware and software are recorded at cost. Cost of renewals and improvements that substantially extend the useful lives of the assets are capitalized. Maintenance and repair costs are expensed as incurred. Depreciation is calculated using the straight-line method over the estimated useful lives of the assets, which range from three |
Leases | LeasesThe Company determines if an arrangement is representative of a lease at contract inception. Right-of-use (“ROU”) assets represent our right to use the underlying assets for the lease term and the corresponding lease liabilities represent our obligations to make lease payments arising from the leases. Operating and finance lease ROU assets and liabilities are recognized at the lease commencement date based on the present value of the lease payments over the lease term. When evaluating a contract, the Company applies certain judgments to determine, among other factors, lease classification as either operating or financing, lease term, and discount rate. The terms of certain of our leases include options to extend or terminate the lease, only when we can ascertain that it is reasonably certain we will exercise that option, as well as evergreen periods for which the penalties associated with termination are considered to be significant. Leases with an initial term of one year or less are not recorded on the balance sheets. As the Company does not have any leases with an implicit interest rate that can be readily determined, we utilize our incremental borrowing rate based on information available at the lease commencement date in determining the present value of lease payments. We determine our incremental borrowing rate at the lease commencement date using our Credit Facility benchmark rate and make adjustments for facility utilization and lease term. Subsequent measurement, as well as presentation of expenses and cash flows, will depend upon the classification of the lease as either a finance or operating lease. |
Carbon Offsets | Carbon Offsets The Company periodically purchases carbon offsets and renewable energy credits as a means to offset carbon emissions generated by its operations that could not otherwise be reduced or eliminated. Commensurate with their use, purchased carbon offsets and renewable energy credits are initially capitalized at cost as an intangible asset within other noncurrent assets on the accompanying balance sheets. Subsequently, capitalized carbon offsets and renewable energy credits are expensed when applied to the Company's carbon emissions through depletion, depreciation, and amortization expense on the accompanying statements of operations. Purchased carbon offsets and renewable energy credits expected to be utilized within the next 12 months are presented as short-term within prepaid expenses and other on the accompanying balance sheets. |
Deferred Financing Costs | Deferred Financing Costs Deferred financing costs include origination, legal, and other fees incurred to issue debt or amend existing credit facilities. Deferred financing costs related to the Credit Facility are capitalized to prepaid expenses and other and other noncurrent assets on the accompanying balance sheets and amortized to interest expense, net on the accompanying statements of operations on a straight-line basis over the life of the Credit Facility. Deferred financing costs related to senior notes are capitalized within senior notes on the accompanying balance sheets and amortized to interest expense, net on the accompanying statements of operations using the effective interest method over the life of the respective borrowings. |
Asset Retirement Obligations | Asset Retirement Obligations The Company recognizes an asset retirement obligation at fair value based on the present value of costs expected to be incurred in connection with the future abandonment of its oil and natural gas properties, including wells and facilities, in accordance with applicable regulatory requirements. This obligation, and the corresponding capitalized cost recorded to proved properties, is recorded at the time assets are acquired, a well is completed and begins production, or a facility is constructed. The Company recognizes a periodic expense in connection with the accretion of the discounted asset retirement obligation over the remaining estimated economic lives of the respective long-lived assets. The accretion expense is recorded as a component of depreciation, depletion, and amortization in our accompanying statements of operations. If the fair value of the estimated asset retirement obligation changes, an adjustment is recorded to both the asset retirement obligation and the corresponding capitalized cost recorded to proved properties. The recognition of an asset retirement obligation requires management to make various assumptions informed by historical experience and applicable regulatory requirements including estimated plugging and abandonment costs, economic lives, inflation rates, and the Company's credit-adjusted risk-free rate. |
Derivatives | Derivatives The Company periodically enters into commodity price derivative instruments to mitigate a portion of its exposure to potentially adverse market changes in commodity prices for its expected future oil, natural gas, and NGL production and the associated impact on cash flows. These instruments typically include commodity price swaps and collars, as well as, basis differential and roll differential swaps. The oil instruments are indexed to NYMEX WTI prices, natural gas instruments are indexed to NYMEX HH and CIG prices, and NGL instruments are indexed to OPIS prices, all of which have a high degree of historical correlation with actual prices received by the Company, before differentials. Presently, our derivative contracts have been executed with 10 counterparties, all but one of which are members of our Credit Facility syndicate. We enter into contracts with counterparties whom we believe are well capitalized and have certain minimum investment grade senior unsecured debt ratings. However, if our counterparties fail to perform their obligations under the contracts, we could suffer financial loss. Commodity price derivative instruments are measured at fair value and are included in the accompanying balance sheets as derivative assets and liabilities, with the exception of derivative instruments that meet the “normal purchase normal sale” exclusion. All commodity price derivative instruments are entered into for other-than-trading purposes. The Company does not designate its commodity price derivative contracts as hedging instruments. Accordingly, the Company reflects changes in the fair value of its commodity price derivative instruments in its accompanying statements of operations as they occur. We measure the fair value of our commodity price derivative instruments based upon a pricing model that utilizes market-based inputs, including, but not limited to, contractual price of the underlying position, current market prices, crude oil and natural gas forward curves, discount rates, volatility factors, and nonperformance risk. As of December 31, 2021 and 2020, all derivative instruments held by the Company were subject to master netting arrangements with various financial institutions. In general, the terms of the Company’s agreements provide for offsetting of amounts payable or receivable between it and the counterparty, at the election of both parties, for transactions that settle on the same date and in the same currency. The Company’s agreements also provide that in the event of an early termination, the counterparties have the right to offset amounts owed or owing under that and any other agreement with the same counterparty. The Company’s accounting policy is to not offset these positions in its accompanying balance sheets. |
Revenue Recognition | Revenue Recognition Revenue is recognized 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. We consider 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. Oil sales. Under the Company’s crude purchase and marketing contracts, the Company typically delivers production at the wellhead, or other contractually agreed-upon delivery points, and collects an agreed-upon index price, net of pricing differentials. In this scenario, the Company recognizes revenue when control of its oil production transfers to the purchaser at the wellhead, or other contractually agreed-upon delivery point, at the net contracted price received. Natural gas and NGL sales . Under the Company's natural gas processing contracts, the Company delivers natural gas to a midstream processing entity at the wellhead, inlet of the midstream processing entity’s system, or other contractually agreed-upon delivery points. The delivery points are specified within each contract, and the point at which control transfers varies between the inlet and tailgate of the midstream processing facility. The midstream processing entity gathers and processes the natural gas and remits proceeds to the Company for the resulting sales of NGLs and residue gas. For the contracts where the Company maintains control through the tailgate of the midstream processing facility, the Company recognizes revenue on a gross basis, with gathering, transportation, and processing fees presented as an expense in the accompanying statements of operations. Alternatively, for those contracts where the Company relinquishes control at the inlet of the midstream processing facility, the Company recognizes natural gas and NGL revenues based on the contracted amount of the proceeds received from the midstream processing entity and, as a result, the Company recognizes revenue on a net basis. In certain natural gas processing agreements, the Company may elect to take its residue gas and/or NGLs in-kind at the tailgate of the midstream entity’s processing plant and subsequently market the product. Through the marketing process, the Company delivers product to the third-party purchaser at a contractually agreed-upon delivery point and receives a specified index price from the third-party purchaser. In this scenario, the Company recognizes revenue when the control transfers to the third-party purchaser at the delivery point based on the index price received from the third-party purchaser. The gathering and processing expense attributable to the natural gas processing contracts, as well as any transportation expense incurred to deliver the product to the third-party purchaser, are presented as gathering, transportation, and processing expense in the consolidated statements of operations. As noted above, 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. As a result, Company records a revenue accrual based on an estimate of the volumes delivered at estimated prices as determined by the applicable marketing agreements. The Company estimates its sales volumes based on Company-measured volume readings. 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 year ended December 31, 2021, revenue recognized in the reporting period related to performance obligations satisfied in prior reporting periods was insignificant. At December 31, 2021 and 2020, the Company's receivables from contracts with customers were $362.3 million and $32.7 million, respectively. As further described in Note 6 - Commitments and Contingencies , two contracts have an additional aspect of variable consideration related to the minimum volume commitments (“MVCs”) as specified in the agreement. On an on-going basis, the Company performs an analysis of expected risk adjusted production applicable to the agreements based on approved production plans to determine if liquidated damages are probable. As of December 31, 2021, the Company believes that the volumes delivered will be in excess of the MVCs required then and for the upcoming approved production plan. As a result of this analysis, to date, no variable consideration related to potential liquidated damages has been considered in the transaction price for the related agreements. |
Stock-Based Compensation | Stock-Based CompensationThe Company recognizes stock-based compensation based on the grant-date fair value of the equity instruments awarded. Stock-based compensation expense is recognized in the financial statements on a straight-line basis over the requisite service period for the entire award. The Company accounts for forfeitures of stock-based compensation awards as they occur. |
Income Taxes | Income Taxes The Company accounts for income taxes under the asset and liability method, which requires recognition of deferred tax assets and liabilities for the expected future tax consequences of events that have been included in the balance sheet or tax returns. Deferred income tax assets and liabilities are measured using enacted tax rates applicable to the future period when those temporary differences are expected to be recovered or settled. If we determine that it is more likely than not that some portion or all of the deferred income tax assets will not be realized, a valuation allowance is recorded, thereby reducing the deferred income tax assets to what is considered to be realizable. The Company recognizes the tax benefit from an uncertain tax position only if it is more likely than not that the tax position will be sustained on examination by the taxing authorities based on the technical merits of the position. The Company's policy is to recognize interest and penalties related to uncertain tax positions in income tax expense. There were no uncertain tax positions during any period presented. |
Earnings Per Share | Earnings Per ShareThe Company uses the treasury stock method to determine the effect of potentially dilutive instruments. |
Acreage Exchanges | Acreage Exchanges From time to time, we enter into acreage exchanges in order to consolidate our core acreage positions, enabling us to have more control over the timing of development activities, achieve higher working interests and provide us the ability to drill longer lateral length wells within those core areas. We account for our nonmonetary acreage exchanges in accordance with the guidance prescribed by Accounting Standards Codification ( “ ASC ” ) 845, Nonmonetary Transactions . For those exchanges that lack commercial substance, we record the acreage received at the net carrying value of the acreage surrendered to obtain it. For those acreage exchanges that are deemed to have commercial substance, we record the acreage received at fair value, with a related gain or loss recognized in earnings, in accordance with ASC 820, Fair Value Measurement |
Business Combinations | Business CombinationsAs part of our business strategy, we regularly pursue the acquisition of oil and natural gas properties. We utilize the acquisition method to account for acquisitions of businesses. Pursuant to this method, we allocate the cost of the acquisition, or purchase price, to assets acquired and liabilities assumed based on fair values as of the acquisition date. |
Fair Value of Financial Instruments | Fair Value of Financial Instruments The Company’s financial instruments consist of cash and cash equivalents, accounts receivables, and accounts payable are carried at cost, which approximates fair value due to the short-term maturity of these instruments. As discussed above, the Company's commodity price derivative instruments are recorded at fair value. The Company’s Senior Notes, as defined in Note 5 – Long-Term Debt , are recorded at cost, net of any unamortized deferred financing costs, and their respective fair values are disclosed in Note 8 – Fair Value Measurement s. The recorded value of the Company’s Credit Facility approximates its fair value as it bears interest at a floating rate that approximates a current market rate. The Company’s warrants were recorded at fair value upon issuance, with no recurring fair value measurement required. |
Recently Issued and Adopted Accounting Standards | Recently Issued and Adopted Accounting Standards In June 2016, the FASB issued Update No. 2016-13, Financial Instruments - Credit Losses (Topic 326): Measurement of Credit Losses on Financial Instruments . The update changes the impairment model for most financial assets and certain other instruments, including trade and other receivables, and requires entities to use a new forward-looking expected loss model that will result in the earlier recognition of allowances for losses. The amended standard was adopted using a modified retrospective approach on January 1, 2020. The Company considered past events (including historical experience), current economic and industry conditions, reasonable and supportable forecasts, and lives of receivable balances and loss experience. Historically and currently, the Company's credit losses on oil and natural gas sales receivables and joint interest receivables have not been significant, and the adoption of this standard did not have a material impact on its consolidated financial statements. As of December 31, 2021 and 2020 the Company had an allowance of $3.7 million and $0.4 million, respectively, established against joint interest receivables. In August 2018, the FASB issued Update No. 2018-13, Disclosure Framework - Changes to the Disclosure Requirements for Fair Value Measurement . The objective of this update is to improve the effectiveness of fair value measurement disclosures. The new standard was adopted on January 1, 2020. The standard only impacted the form of the Company's disclosures. In March 2020, the FASB issued Update No. 2020-04, Reference Rate Reform (Topic 848), which provides temporary optional guidance to companies impacted by the transition away from the LIBOR. The amendment provides certain expedients and exceptions to applying GAAP in order to lessen the potential accounting burden when contracts, hedging relationships, and other transactions that reference LIBOR as a benchmark rate are modified. Further, in January 2021, the FASB issued Update No. 2021-01, Reference Rate Reform (Topic 848), which clarifies the scope of Topic 848 so that derivatives affected by the discounting transition are explicitly eligible for certain optional expedients and exceptions in Topic 848. These amendments are effective upon issuance and expire on December 31, 2022. The Company is currently assessing the impact of the LIBOR transition on the Company's consolidated financial statements. |
SUMMARY OF SIGNIFICANT ACCOUN_3
SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Tables) | 12 Months Ended |
Dec. 31, 2021 | |
Accounting Policies [Abstract] | |
Schedule of Restricted Cash | The following table provides a reconciliation of cash, cash equivalents, and restricted cash reported within the accompanying balance sheets, which sums to the total of such amounts shown in the accompanying statements of cash flows (in thousands): As of December 31, 2021 2020 2019 Cash and cash equivalents $ 254,454 $ 24,743 $ 11,008 Restricted cash (1) 102 102 87 Total cash, cash equivalents, and restricted cash $ 254,556 $ 24,845 $ 11,095 ____________________________ (1) Included in other noncurrent assets and consists of funds for road maintenance and repairs. |
Schedule of Cash and Cash Equivalents | The following table provides a reconciliation of cash, cash equivalents, and restricted cash reported within the accompanying balance sheets, which sums to the total of such amounts shown in the accompanying statements of cash flows (in thousands): As of December 31, 2021 2020 2019 Cash and cash equivalents $ 254,454 $ 24,743 $ 11,008 Restricted cash (1) 102 102 87 Total cash, cash equivalents, and restricted cash $ 254,556 $ 24,845 $ 11,095 ____________________________ (1) Included in other noncurrent assets and consists of funds for road maintenance and repairs. |
Schedules of Concentrations of Credit Risk and Major Customers | For the periods presented below, the following purchasers of the Company's production accounted for more than 10% of the Company's revenue as follows: Year Ended December 31, 2021 2020 2019 Customer A 43 % 77 % 82 % Customer B 15 % — % — % Customer C 13 % 9 % 6 % |
Schedule of Disaggregation of Revenue | Revenue attributable to each identified revenue stream is disaggregated below (in thousands): Year Ended December 31, 2021 2020 2019 Operating net revenues: Oil sales $ 614,811 $ 174,536 $ 268,865 Natural gas sales 144,708 24,243 28,296 NGL sales 171,095 19,311 16,059 Oil, natural gas, and NGL sales $ 930,614 $ 218,090 $ 313,220 |
ACQUISITIONS AND DIVESTITURES (
ACQUISITIONS AND DIVESTITURES (Tables) | 12 Months Ended |
Dec. 31, 2021 | |
Business Combination and Asset Acquisition [Abstract] | |
Schedule of Merger Consideration and Preliminary Purchase Price Allocations | The following tables present the HighPoint Merger consideration and purchase price allocation of the assets acquired and the liabilities assumed in the HighPoint Merger: Merger Consideration (in thousands, except per share amount) Shares of Civitas Common Stock issued to existing holders of HighPoint Common Stock (1) 488 Shares of Civitas Common Stock issued to existing holders of HighPoint Senior Notes 9,314 Total additional shares of Civitas Common Stock issued as merger consideration 9,802 Closing price per share of Civitas Common Stock (2) $ 38.25 Merger consideration paid in shares of Civitas Common Stock $ 374,933 Aggregate principal amount of the 7.5% Senior Notes 100,000 Total merger consideration $ 474,933 _________________________ (1) Based on the number of shares of HighPoint Common Stock issued and outstanding as of April 1, 2021 and the conversion ratio of 0.11464 per share of Civitas Common Stock. (2) Based on the closing stock price of Civitas Common Stock on April 1, 2021. Purchase Price Allocation (in thousands) Assets Acquired Cash and cash equivalents $ 49,827 Accounts receivable - oil and natural gas sales 26,343 Accounts receivable - joint interest and other 9,161 Prepaid expenses and other 3,608 Inventory of oilfield equipment 4,688 Proved properties 539,820 Other property and equipment, net of accumulated depreciation 2,769 Right-of-use assets 4,010 Deferred income tax assets 110,513 Other noncurrent assets 797 Total assets acquired $ 751,536 Liabilities Assumed Accounts payable and accrued expenses $ 51,088 Oil and natural gas revenue distribution payable 20,786 Lease liability 4,010 Derivative liability 18,500 Current portion of long-term debt 154,000 Ad valorem taxes 3,746 Asset retirement obligations 24,473 Total liabilities assumed 276,603 Net assets acquired $ 474,933 Merger Consideration (in thousands, except per share amount) Shares of Civitas Common Stock issued as merger consideration (1) 31,095 Closing price per share of Civitas Common Stock (2) $ 56.10 Merger consideration paid in shares of Civitas Common Stock $ 1,744,431 Unvested restricted stock compensation expense as merger consideration $ 19,338 Unvested performance restricted stock compensation expense allocated as merger consideration 2,897 Total merger consideration $ 22,235 Tranche A warrants issued as merger consideration $ 52,164 Tranche B warrants issued as merger consideration 25,299 Total warrant merger consideration $ 77,463 Total merger consideration $ 1,844,129 _________________________ (1) Based on the number of shares of Extraction Common Stock issued and outstanding as of November 1, 2021 and the conversion ratio of 1.1711 per share of Civitas Common Stock. (2) Based on the closing stock price of Civitas Common Stock on November 1, 2021. Preliminary Purchase Price Allocation (in thousands) Assets Acquired Cash and cash equivalents $ 106,360 Accounts receivable - oil and natural gas sales 119,585 Accounts receivable - joint interest and other 33,054 Prepaid expenses and other 3,044 Inventory of oilfield equipment 9,291 Derivative assets 5,834 Proved properties 1,876,014 Unproved properties 193,400 Other property and equipment, net of accumulated depreciation 40,068 Right-of-use assets 6,883 Deferred income tax assets 49,194 Other noncurrent assets 4,248 Total assets acquired $ 2,446,975 Liabilities Assumed Accounts payable and accrued expenses $ 90,353 Production taxes payable 63,572 Oil and natural gas revenue distribution payable 170,002 Income tax payable 14,000 Lease liability 6,883 Derivative liability 100,474 Ad valorem taxes 87,071 Asset retirement obligations 68,741 Other noncurrent liabilities 1,750 Total liabilities assumed 602,846 Net assets acquired $ 1,844,129 The following tables present the merger consideration and preliminary purchase price allocation of the assets acquired and the liabilities assumed in the Crestone Peak Merger: Merger Consideration (in thousands, except per share amount) Shares of Civitas Common Stock issued as merger consideration 22,500 Closing price per share of Civitas Common Stock (1) $ 56.10 Merger consideration paid in shares of Civitas Common Stock $ 1,262,250 _________________________ (1) Based on the closing stock price of Civitas Common Stock on November 1, 2021. Preliminary Purchase Price Allocation (in thousands) Assets Acquired Cash and cash equivalents $ 67,505 Accounts receivable - oil and natural gas sales 81,340 Accounts receivable - joint interest and other 9,917 Prepaid expenses and other 2,929 Inventory of oilfield equipment 11,951 Proved properties 1,797,814 Unproved properties 453,321 Other property and equipment, net of accumulated depreciation 7,980 Right-of-use assets 7,934 Total assets acquired $ 2,440,691 Liabilities Assumed Accounts payable and accrued expenses $ 134,791 Production taxes payable 52,435 Oil and natural gas revenue distribution payable 83,950 Lease liability 7,934 Derivative liability 338,383 Credit facility 280,000 Ad valorem taxes 66,913 Deferred income tax liabilities 125,086 Asset retirement obligations 88,949 Total liabilities assumed 1,178,441 Net assets acquired $ 1,262,250 |
Schedule of Pro Forma Financial Information | The following unaudited pro forma financial information (in thousands, except per share amounts) represents a summary of the consolidated results of operations for the year ended December 31, 2021 and 2020, assuming the HighPoint, Extraction, and Crestone Peak mergers had been completed as of January 1, 2020. The pro forma financial information includes certain non-recurring pro forma adjustments that were directly attributable to the business combinations. The pro forma financial information is not necessarily indicative of the results of operations that would have been achieved if the mergers had been effective as of this date, or of future results. Year Ended December 31, 2021 As reported HighPoint (1) Extraction (2) Crestone Peak (2) Civitas Pro Forma Combined Total revenue $ 930,614 $ 72,019 $ 882,255 $ 508,038 $ 2,392,926 Net income (loss) 178,921 (46,657) 944,814 (299,688) 777,390 Net income per common share - basic $ 4.82 $ 9.37 Net income per common share - diluted $ 4.74 $ 9.30 _________________________ (1) Based on a closing date of April 1, 2021. (2) Based on a closing date of November 1, 2021. Year Ended December 31, 2020 As reported HighPoint Extraction Crestone Peak Civitas Pro Forma Combined Total revenue $ 218,090 $ 250,347 $ 557,904 $ 285,426 $ 1,311,767 Net income (loss) 103,528 (1,081,347) (1,335,406) (268,057) (2,581,282) Net income (loss) per common share - basic $ 4.98 $ (28.83) Net income (loss) per common share - diluted $ 4.95 $ (28.83) |
LEASES (Tables)
LEASES (Tables) | 12 Months Ended |
Dec. 31, 2021 | |
Leases [Abstract] | |
Schedule of Balance Sheet Activity, Asset Classes | The Company’s ROU assets and lease liabilities are recognized on the accompanying balance sheets based on the present value of the expected lease payments over the lease term. The following table summarizes the asset classes of the Company's operating and finance leases (in thousands): December 31, 2021 2020 Operating Leases Field equipment (1) $ 29,312 $ 27,537 Corporate leases 9,484 1,481 Vehicles 1,089 468 Total right-of-use asset $ 39,885 $ 29,486 Field equipment (1) $ 29,312 $ 27,537 Corporate leases 9,870 1,900 Vehicles 1,089 468 Total lease liability $ 40,271 $ 29,905 Finance Leases Right of use asset - field equipment (1) $ — $ 219 Lease liability - field equipment (1) $ — $ 117 ____________________________ (1) Includes compressors, certain natural gas processing equipment, and other field equipment. |
Summary of Operating Lease Costs and Summary of Supplemental Cash Flow Information | The following table summarizes the components of the Company's gross lease costs incurred for the periods below consisted of the following (in thousands): Year Ended December 31, 2021 2020 2019 Operating lease cost (1) $ 15,449 $ 13,957 $ 11,330 Finance lease cost Amortization of ROU assets 3 18 — Interest on lease liabilities 1 5 — Short-term lease cost 3,662 2,058 8,169 Variable lease cost (2) 56 (186) 259 Sublease income (3) (367) (358) (348) Total lease cost $ 18,804 $ 15,494 $ 19,410 ___________________________ (1) Includes office rent expense of $2.2 million, $1.1 million, and $1.1 million for the years ended December 31, 2021, 2020, and 2019, respectively. (2) Variable lease cost represents differences between lease obligations and actual costs incurred for certain leases that do not have fixed payments related to both lease and non-lease components. Such incremental costs include lease payment increases or decreases driven by market price fluctuations and leased asset maintenance costs. (3) The Company has subleased a portion of one of its office spaces for the remainder of the office lease term. Supplemental cash flow information related to leases for the periods below consisted of the following (in thousands): Year Ended December 31, 2021 2020 2019 Cash paid for amounts included in the measurement of lease liabilities: Operating cash flows from operating leases $ 14,284 $ 12,768 $ 10,993 Operating cash flows from finance leases 1 5 — Financing cash flows from finance leases 21 102 — Right-of-use assets obtained in exchange for new operating lease obligations $ 25,469 $ 8,306 $ 16,568 Right-of-use assets obtained in exchange for new finance lease obligations — 219 — |
Schedule of Weighted-Average Information | The Company's weighted-average remaining lease terms and discount rates as of December 31, 2021 are as follows: Operating Leases Weighted-average lease term (years) 2.7 Weighted-average discount rate 3.9% |
Schedule of Future Minimum Commitments for Operating Leases | Future commitments by year for the Company's leases with a lease term of one year or more as of December 31, 2021 are presented in the table below. Such commitments are reflected at undiscounted values and are reconciled to the discounted present value recognized on the accompanying balance sheets as follows (in thousands): Operating Leases 2022 $ 20,044 2023 12,980 2024 5,247 2025 1,496 2026 1,178 Thereafter 1,586 Total lease payments 42,531 Less: imputed interest (2,260) Total lease liability $ 40,271 |
OTHER NONCURRENT ASSETS, ACCO_2
OTHER NONCURRENT ASSETS, ACCOUNTS PAYABLE, AND ACCRUED EXPENSES (Tables) | 12 Months Ended |
Dec. 31, 2021 | |
Other Assets [Abstract] | |
Schedule of Other Noncurrent Assets | Other noncurrent assets contain the following (in thousands): As of December 31, 2021 2020 Deferred financing costs $ 7,543 $ 725 Operating bonds 3,485 1,641 Carbon offsets 1,967 — Notes receivable 506 — AMT credit refund 403 403 Restricted cash 102 102 Other 79 — Other noncurrent assets $ 14,085 $ 2,871 |
Schedule of Accounts Payable and Accrued Expenses | Accounts payable and accrued expenses contain the following (in thousands): As of December 31, 2021 2020 Accounts payable trade $ 19,623 $ 1,931 Accrued drilling and completion costs 129,430 453 Accrued lease operating expense 19,077 1,793 Accrued general and administrative expense 21,163 4,942 Accrued merger transaction costs 1,475 2,587 Accrued oil and NGL hedging 26,601 — Accrued interest expense 6,303 322 Accrued settlement 20,791 — Other accrued expenses 1,725 65 Total accounts payable and accrued expenses $ 246,188 $ 12,093 |
LONG-TERM DEBT (Tables)
LONG-TERM DEBT (Tables) | 12 Months Ended |
Dec. 31, 2021 | |
Debt Disclosure [Abstract] | |
Schedule of Long-term Debt Instruments | The table below presents the related carrying values as of December 31, 2021 (in thousands): Principal Amount Unamortized Deferred Financing Costs Carrying Value 7.5% Senior Notes $ 100,000 $ — $ 100,000 5.0% Senior Notes $ 400,000 $ 8,290 $ 391,710 |
COMMITMENTS AND CONTINGENCIES (
COMMITMENTS AND CONTINGENCIES (Tables) | 12 Months Ended |
Dec. 31, 2021 | |
Commitments and Contingencies Disclosure [Abstract] | |
Schedule of Annual Minimum Commitment Payments | The minimum annual payments under the these agreements for the next five years as of December 31, 2021 are presented below (in thousands): Firm Transportation Minimum Volume (1) 2022 $ 13,064 $ 58,284 2023 14,600 29,192 2024 14,640 22,298 2025 4,800 20,400 2026 and thereafter — 73,712 Total $ 47,104 $ 203,886 ___________________________ (1) The above calculation is based on the minimum volume commitment schedule (as defined in the relevant agreement) and applicable differential fees. |
STOCK-BASED COMPENSATION (Table
STOCK-BASED COMPENSATION (Tables) | 12 Months Ended |
Dec. 31, 2021 | |
Share-based Payment Arrangement [Abstract] | |
Summary of Share-Based Compensation Expense | The following table outlines the compensation expense recorded by type of award (in thousands): Year Ended December 31, 2021 2020 2019 Restricted and deferred stock units $ 11,895 $ 5,283 $ 5,518 Performance stock units 3,663 748 764 Stock options — 125 604 Total stock-based compensation $ 15,558 $ 6,156 $ 6,886 |
Summary of Unrecognized Compensation Expense and Vesting Criterion | As of December 31, 2021, 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 $ 9,333 2024 Performance stock units 11,192 2024 Total unrecognized stock-based compensation $ 20,525 2021 2020 2019 TSR 100 % 67 % 50 % ROCE — % 33 % 50 % |
Summary of the Status and Activity of Non-Vested RSUs, DSUs, and Options | A summary of the status and activity of non-vested RSUs and DSUs for the year ended December 31, 2021 is presented below: RSUs and DSUs Weighted-Average Grant-Date Fair Value Non-vested, beginning of year 550,056 $ 20.30 Granted or assumed 662,748 50.12 Vested (373,696) 25.61 Forfeited (24,046) 17.99 Non-vested, end of year 815,062 $ 42.18 A summary of the status and activity of non-vested stock options for the year ended December 31, 2021 is presented below: Stock Options Weighted- Weighted-Average Remaining Contractual Term (in years) Aggregate Intrinsic Value (in thousands) Outstanding, beginning of year 72,368 $ 34.36 Exercised (46,309) 34.36 Forfeited (510) 34.36 Outstanding, end of year 25,549 $ 34.36 5.0 $ 373 Options outstanding and exercisable 25,549 $ 34.36 5.0 $ 373 |
Schedule of Assumptions | The following table presents the assumptions used to determine the fair value of the PSUs associated with the market-based settlement criteria as granted under the LTIP: Year Ended December 31, 2021 2020 2019 TSR Expected term (in years) 3 3 3 Risk-free interest rate 0.30 % 0.22 % 2.26 % Expected daily volatility 3.8 % 3.5 % 2.6 % ATSR Expected term (in years) 2.2 Risk-free interest rate 0.56 % Expected daily volatility 4.7 % |
Summary of the Status and Activity of PSUs | A summary of the status and activity of non-vested PSUs for the year ended December 31, 2021 is presented below: PSUs (1) Weighted-Average Grant-Date Fair Value Non-vested, beginning of year 185,588 $ 22.63 Granted or assumed 177,034 88.13 Vested (43,255) 32.68 Non-vested, end of year 319,367 $ 57.58 ___________________________ (1) The number of awards assumes that the associated performance condition is met at the target amount. The final number of shares of the Company’s common stock issued may vary depending on the performance multiplier, which ranges from zero to two, depending on the level of satisfaction of the performance condition. |
FAIR VALUE MEASUREMENTS (Tables
FAIR VALUE MEASUREMENTS (Tables) | 12 Months Ended |
Dec. 31, 2021 | |
Fair Value Disclosures [Abstract] | |
Schedule of Financial Assets and Liabilities at Fair Value on Recurring Basis | The following tables present the Company’s financial assets and liabilities that were accounted for at fair value on a recurring basis as of December 31, 2021 and 2020 and their classification within the fair value hierarchy (in thousands): As of December 31, 2021 Level 1 Level 2 Level 3 Derivative assets $ — $ 3,393 $ — Derivative liabilities $ — $ 239,763 $ — As of December 31, 2020 Level 1 Level 2 Level 3 Derivative assets $ — $ 7,482 $ — Derivative liabilities $ — $ 7,732 $ — |
DERIVATIVES (Tables)
DERIVATIVES (Tables) | 12 Months Ended |
Dec. 31, 2021 | |
Derivative Instruments and Hedging Activities Disclosure [Abstract] | |
Schedule of Commodity Derivatives | As of December 31, 2021, the Company had entered into the following commodity price derivative contracts: Crude Oil Natural Gas Natural Gas Natural Gas Liquids Bbls/day Weighted Avg. Price per Bbl MMBtu/day Weighted Avg. Price per MMBtu MMBtu/day Weighted Avg. Price per MMBtu Bbls/day Weighted Avg. Price per Bbl 1Q22 Collar 15,700 $43.83/$59.77 — — 20,000 $2.15/$2.75 — — Swap 15,371 $47.39 125,170 $2.90 10,000 $2.13 4,000 $20.22 Oil roll swap (1) 2,000 $0.22 — — — — — — 2Q22 Collar 8,800 $38.09/$67.48 60,375 $2.50/$3.50 20,000 $2.15/$2.75 — — Swap 10,139 $49.84 53,300 $2.77 10,000 $2.13 4,000 $20.22 Oil roll swap (1) 2,000 $0.22 — — — — — — 3Q22 Collar 7,681 $40.35/$69.99 78,420 $2.59/$3.68 — — — — Swap 9,359 $46.88 53,300 $2.77 10,000 $2.13 4,000 $20.22 Oil roll swap (1) 2,000 $0.22 — — — — — — 4Q22 Collar 6,938 $40.75/$70.99 76,929 $2.60/$3.69 — — — — Swap 8,686 $46.77 53,300 $2.77 10,000 $2.13 4,000 $20.22 Oil roll swap (1) 2,000 $0.22 — — — — — — 2023 Collar 260 $40.00/$72.70 2,184 $2.00/$3.25 — — — — Swap 200 $46.05 43,600 $2.51 — — — — 2024 Swap — — 22,309 $2.57 — — — — _______________________________ (1) The weighted average differential represents the amount of reduction to NYMEX WTI prices for the notional volumes covered by the swap contracts. As of March 1, 2022, the following commodity price derivative contracts were novated from Bison: Crude Oil Natural Gas Bbls/day Weighted Avg. Price per Bbl MMBtu/day Weighted Avg. Price per MMBtu 2022 (1) Collar (2, 3) 2,756 $47.85 / $56.71 2,278 $2.67 / $3.39 Swap 873 $47.38 1,582 $2.52 2023 Collar (2, 3) 1,406 $48.62 / $57.71 1,828 $2.36 / $2.98 Swap 208 $46.47 470 $2.51 2024 Collar (2, 3) 143 $45.00 / $56.25 1,337 $2.40 / $3.15 Swap 479 $53.96 — — _______________________________ (1) Represents hedged volumes from the closing date through December 31, 2022. (2) 79%, 100%, and 100% of the 2022, 2023, and 2024 oil collars presented include sold puts at a weighted average price of $38.72, $38.38, and $35.00 per Bbl, respectively (3) 5%, 19%, and 23% of the 2022, 2023, and 2024 gas collars presented include sold puts at a weighted average price of $2.00 per MMBtu, respectively. |
Summary of all the Company's Derivative Positions | 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 December 31, 2021 and 2020 (in thousands): As of December 31, 2021 2020 Derivative Assets: Commodity contracts - current $ 3,393 $ 7,482 Commodity contracts - noncurrent — — Total derivative assets 3,393 7,482 Amounts not offset in the accompanying balance sheets (3,393) (4,758) Total derivative assets, net $ — $ 2,724 Derivative Liabilities: Commodity contracts - current $ (219,804) $ (6,402) Commodity contracts - long-term (19,959) (1,330) Total derivative liabilities (239,763) (7,732) Amounts not offset in the accompanying balance sheets 3,393 4,758 Total derivative liabilities, net $ (236,370) $ (2,974) |
Summary of the Components of the Derivative Gain (Loss) | The following table summarizes the components of the derivative gain (loss) presented on the accompanying statements of operations for the periods below (in thousands): Year Ended December 31, 2021 2020 2019 Derivative cash settlement gain (loss): Oil contracts $ (215,057) $ 50,133 $ 1,185 Gas contracts (51,806) (727) 506 NGL contracts (9,051) — — Total derivative cash settlement gain (loss) (1) (275,914) 49,406 1,691 Change in fair value gain (loss) 215,404 4,056 (38,836) Total derivative gain (loss) (1) $ (60,510) $ 53,462 $ (37,145) ___________________________ (1) Total derivative gain (loss) and total derivative cash settlement gain (loss) for each of the periods presented above is reported in the derivative (gain) loss line item and derivative cash settlements gain (loss) line item in the accompanying statements of cash flows, within the cash flows from operating activities. |
ASSET RETIREMENT OBLIGATIONS (T
ASSET RETIREMENT OBLIGATIONS (Tables) | 12 Months Ended |
Dec. 31, 2021 | |
Asset Retirement Obligation Disclosure [Abstract] | |
Schedule of Asset Retirement Obligation Changes | A roll-forward of the Company's asset retirement obligation is as follows (in thousands): Year Ended December 31, 2021 2020 Balance, beginning of year $ 28,699 $ 27,908 Additional liabilities incurred 183,758 357 Accretion expense 3,933 1,004 Liabilities settled (4,221) (2,464) Revisions to estimate 13,146 1,894 Balance, end of year $ 225,315 $ 28,699 Current portion 24,000 — Long-term portion $ 201,315 $ 28,699 |
EARNINGS PER SHARE (Tables)
EARNINGS PER SHARE (Tables) | 12 Months Ended |
Dec. 31, 2021 | |
Earnings Per Share [Abstract] | |
Schedule of Earnings Per Share | The following table sets forth the calculations of basic and diluted net income per common share (in thousands, except per share amounts): Year Ended December 31, 2021 2020 2019 Net income $ 178,921 $ 103,528 $ 67,067 Basic net income per common share $ 4.82 $ 4.98 $ 3.25 Diluted net income per common share $ 4.74 $ 4.95 $ 3.24 Weighted-average shares outstanding - basic 37,155 20,774 20,612 Add: dilutive effect of contingent stock awards 591 138 69 Weighted-average shares outstanding - diluted 37,746 20,912 20,681 |
INCOME TAXES (Tables)
INCOME TAXES (Tables) | 12 Months Ended |
Dec. 31, 2021 | |
Income Tax Disclosure [Abstract] | |
Schedule of Provision for Income Taxes | The provision for income taxes consists of the following (in thousands): Year Ended December 31, 2021 2020 2019 Current tax expense (benefit) Federal $ — $ (27) $ — State — — — Total current tax expense (benefit) — (27) — Deferred tax expense (benefit) Federal 62,212 (53,784) — State 10,646 (6,736) — Total deferred tax expense (benefit) 72,858 (60,520) — Total income tax expense (benefit) $ 72,858 $ (60,547) $ — |
Schedule of Temporary Differences, Deferred Tax Assets and Liabilities | Temporary differences between the financial statement carrying amounts and tax basis of assets and liabilities that give rise to the net deferred tax asset result from the following components (in thousands): As of December 31, 2021 2020 Deferred tax liabilities: Oil and gas properties $ 608,829 $ 89,867 Right-of-use assets 8,292 7,306 Total deferred tax liabilities 617,121 97,173 Deferred tax assets: Federal and state tax net operating loss carryforward 482,216 138,372 Derivative instruments 86,958 61 Reclamation costs 51,515 7,058 Stock compensation 7,622 1,653 Inventory 10,108 1,598 Lease liability 8,187 7,384 Property taxes 19,458 — Pending acquisition costs — 1,478 Other long-term assets 21,474 89 Total deferred tax assets 687,538 157,693 Less: Valuation allowance 48,133 — Total deferred tax assets after valuation allowance 639,405 157,693 Total non-current net deferred tax asset $ 22,284 $ 60,520 |
Schedule of Amount of Effective Income Tax Rate Reconciliation | Federal income tax expense differs from the amount that would be provided by applying the statutory United States federal income tax rate of 21% to income before income taxes primarily due to the effect of state income taxes, changes in valuation allowances, rate changes, and other permanent differences, as follows (in thousands): Year Ended December 31, 2021 2020 2019 Federal statutory tax expense $ 52,824 $ 9,026 $ 14,084 Increase (decrease) in tax resulting from: State tax expense net of federal benefit 10,646 1,694 2,537 Prior year true-up 27 292 (579) Stock compensation (1,559) 690 197 Permanent differences 84 36 128 State rate change — 124 — Transaction costs 9,043 — — Section 162(m) limitation 1,793 144 156 Valuation allowance — (72,553) (16,523) Total income tax expense (benefit) $ 72,858 $ (60,547) $ — |
DISCLOSURES ABOUT OIL AND GAS_2
DISCLOSURES ABOUT OIL AND GAS PRODUCING ACTIVITIES (UNAUDITED) (Tables) | 12 Months Ended |
Dec. 31, 2021 | |
Results of Operations, Revenue from Oil and Gas Producing Activities [Abstract] | |
Schedule of Costs Incurred in Oil and Natural Gas Producing Activities | Costs incurred in oil and natural gas producing activities are as follows (in thousands): Year Ended December 31, 2021 2020 2019 Acquisition (1) $ 4,861,619 $ 11,296 $ 12,901 Development (2)(3) 315,746 55,934 209,535 Exploration 7,937 595 796 Total $ 5,185,302 $ 67,825 $ 223,232 _________________________ (1) Acquisition costs for unproved properties for the years ended December 31, 2021, 2020, and 2019 were $648.0 million, $2.3 million, and $4.2 million, respectively. There were $4.2 billion, $9.0 million, and $8.7 million in acquisition costs for proved properties for the years ended December 31, 2021, 2020, and 2019, respectively. (2) Development costs include workover costs of $2.2 million, $1.2 million, and $1.4 million charged to lease operating expense for the years ended December 31, 2021, 2020, and 2019, respectively. (3) Includes amounts relating to asset retirement obligations of $13.8 million, $(1.0) million, and $(0.9) million, for the years ended December 31, 2021, 2020, and 2019, respectively. |
Summary of BCEI's Changes in Quantities of Proved Oil, Natural Gas Liquids and Natural Gas Reserves | A summary of the Company's changes in quantities of proved oil, natural gas liquids, and natural gas reserves for the years ended December 31, 2021, 2020, and 2019 are as follows: Natural Natural Oil Gas Gas Liquids (MBbl) (MMcf) (MBbl) Balance-December 31, 2018 64,354 165,012 24,930 Extensions, discoveries and infills (1) 8,825 20,604 3,123 Production (5,136) (11,967) (1,431) Sales of minerals in place (52) (110) (18) Removed from capital program (2) (4,926) (11,508) (1,862) Purchases of minerals in place 303 627 102 Revisions to previous estimates (3) 1,045 49,542 (2,683) Balance-December 31, 2019 64,413 212,200 22,161 Extensions, discoveries and infills (1) 9,376 32,172 3,269 Production (5,019) (14,166) (1,858) Removed from capital program (2) (14,120) (33,886) (3,141) Purchases of minerals in place 1,430 5,457 570 Revisions to previous estimates (3) (3,287) 33,951 5,110 Balance-December 31, 2020 52,793 235,728 26,111 Extensions, discoveries and infills (1) 19 103 — Production (4,523) (13,852) (1,763) Removed from capital program (2) (12,249) (43,918) (4,485) Purchases of minerals in place 114,379 767,504 89,797 Revisions to previous estimates (3) (6,840) (57,066) (3,632) Balance-December 31, 2021 143,579 888,499 106,028 Proved developed reserves: December 31, 2019 25,397 105,840 11,566 December 31, 2020 24,320 123,220 14,315 December 31, 2021 104,078 748,762 88,967 Proved undeveloped reserves: December 31, 2019 39,016 106,360 10,595 December 31, 2020 28,473 112,508 11,796 December 31, 2021 39,501 139,737 17,061 ________________________ (1) During the years ended December 31, 2021, 2020, and 2019, horizontal development in the Wattenberg Field resulted in additions in extensions, discoveries, and infills of nominal MMBoe, 18.0 MMBoe, and 15.4 MMBoe, respectively. (2) During the years ended December 31, 2021, 2020, and 2019, proved undeveloped reserves were reduced by 24.1 MMBoe, 22.9 MMBoe, and 8.7 MMBoe respectively, primarily due to the removal of proved undeveloped locations from our five-year drilling program. (3) As of December 31, 2021, the Company revised its proved reserves downward by 20.0 MMBoe primarily driven by 13.1 MMBoe in negative revisions due to changes in well operating cost methodology, 6.9 MMBoe in negative engineering revisions, and 7.1 MMBoe in negative revisions for fuel gas, interest, shrink, and other minor revisions. The commodity prices at December 31, 2021 increased to $66.56 per Bbl WTI and $3.60 per MMBtu HH from $39.57 per Bbl WTI and $1.99 per MMBtu HH at December 31, 2020, resulting in a partially offsetting positive revision of 7.1 MMBoe. As of December 31, 2020, the Company revised its proved reserves upward by 7.5 MMBoe primarily driven by 12.3 MMBoe in positive engineering revisions. The commodity prices at December 31, 2020 decreased to $39.57 per Bbl WTI and $1.99 per MMBtu HH from $55.85 per Bbl WTI and $2.58 per MMBtu HH at December 31, 2019, resulting in a partially offsetting negative revision of 4.8 MMBoe. As of December 31, 2019, the Company revised its proved reserves upward by 6.6 MMBoe. The commodity prices at December 31, 2019 decreased to $55.85 per Bbl WTI and $2.58 per MMBtu HH from $65.56 per Bbl WTI and $3.10 per MMBtu HH at December 31, 2018, resulting in a negative revision of 1.4 MMBoe, offset by 8.1 MMBoe in positive engineering revision. |
Schedule of Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Natural Gas Reserves | The standardized measure of discounted future net cash flows relating to proved oil and natural gas reserves are as follows (in thousands): Year Ended December 31, 2021 2020 2019 Future cash flows $ 14,401,814 $ 2,230,012 $ 3,827,009 Future production costs (5,054,695) (675,755) (1,029,140) Future development costs (1,107,576) (530,970) (850,327) Future income tax expense (1,465,949) — — Future net cash flows 6,773,594 1,023,287 1,947,542 10% annual discount for estimated timing of cash flows (2,361,490) (586,233) (1,089,395) Standardized measure of discounted future net cash flows $ 4,412,104 $ 437,054 $ 858,147 |
Schedule of Changes in the Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Natural Gas Reserves | The changes in the standardized measure of discounted future net cash flows relating to proved oil and natural gas reserves are as follows (in thousands): Year Ended December 31, 2021 2020 2019 Beginning of period $ 437,054 $ 858,147 $ 954,980 Sale of oil and gas produced, net of production costs (773,711) (160,466) (233,677) Net changes in prices and production costs 874,155 (641,137) (372,233) Net changes in extensions, discoveries and improved recoveries 855 (54,269) 45,728 Development costs incurred 108,113 42,325 185,086 Changes in estimated development cost 106,788 220,964 81,358 Purchases of minerals in place 4,484,125 12,372 10,135 Sales of minerals in place — — (309) Revisions of previous quantity estimates (84,126) 60,754 79,637 Net change in income taxes (915,053) — — Accretion of discount 43,705 85,815 95,498 Changes in production rates and other 130,199 12,549 11,944 End of period $ 4,412,104 $ 437,054 $ 858,147 |
Schedule of Average Wellhead Prices Used in Determining Future Net Revenues Related to Standardized Measure Calculation | The average wellhead prices used in determining future net revenues related to the standardized measure calculation as of December 31, 2021, 2020, and 2019 were calculated using the twelve-month arithmetic average of first-day-of-the-month prices inclusive of adjustments for quality and location. Year Ended December 31, 2021 2020 2019 Oil (per Bbl) $ 61.60 $ 34.96 $ 51.22 Gas (per Mcf) $ 2.60 $ 0.95 $ 1.44 Natural gas liquids (per Bbl) $ 30.60 $ 6.12 $ 10.07 |
SUBSEQUENT EVENTS (Tables)
SUBSEQUENT EVENTS (Tables) | 12 Months Ended |
Dec. 31, 2021 | |
Subsequent Events [Abstract] | |
Schedule of Commodity Derivatives | As of December 31, 2021, the Company had entered into the following commodity price derivative contracts: Crude Oil Natural Gas Natural Gas Natural Gas Liquids Bbls/day Weighted Avg. Price per Bbl MMBtu/day Weighted Avg. Price per MMBtu MMBtu/day Weighted Avg. Price per MMBtu Bbls/day Weighted Avg. Price per Bbl 1Q22 Collar 15,700 $43.83/$59.77 — — 20,000 $2.15/$2.75 — — Swap 15,371 $47.39 125,170 $2.90 10,000 $2.13 4,000 $20.22 Oil roll swap (1) 2,000 $0.22 — — — — — — 2Q22 Collar 8,800 $38.09/$67.48 60,375 $2.50/$3.50 20,000 $2.15/$2.75 — — Swap 10,139 $49.84 53,300 $2.77 10,000 $2.13 4,000 $20.22 Oil roll swap (1) 2,000 $0.22 — — — — — — 3Q22 Collar 7,681 $40.35/$69.99 78,420 $2.59/$3.68 — — — — Swap 9,359 $46.88 53,300 $2.77 10,000 $2.13 4,000 $20.22 Oil roll swap (1) 2,000 $0.22 — — — — — — 4Q22 Collar 6,938 $40.75/$70.99 76,929 $2.60/$3.69 — — — — Swap 8,686 $46.77 53,300 $2.77 10,000 $2.13 4,000 $20.22 Oil roll swap (1) 2,000 $0.22 — — — — — — 2023 Collar 260 $40.00/$72.70 2,184 $2.00/$3.25 — — — — Swap 200 $46.05 43,600 $2.51 — — — — 2024 Swap — — 22,309 $2.57 — — — — _______________________________ (1) The weighted average differential represents the amount of reduction to NYMEX WTI prices for the notional volumes covered by the swap contracts. As of March 1, 2022, the following commodity price derivative contracts were novated from Bison: Crude Oil Natural Gas Bbls/day Weighted Avg. Price per Bbl MMBtu/day Weighted Avg. Price per MMBtu 2022 (1) Collar (2, 3) 2,756 $47.85 / $56.71 2,278 $2.67 / $3.39 Swap 873 $47.38 1,582 $2.52 2023 Collar (2, 3) 1,406 $48.62 / $57.71 1,828 $2.36 / $2.98 Swap 208 $46.47 470 $2.51 2024 Collar (2, 3) 143 $45.00 / $56.25 1,337 $2.40 / $3.15 Swap 479 $53.96 — — _______________________________ (1) Represents hedged volumes from the closing date through December 31, 2022. (2) 79%, 100%, and 100% of the 2022, 2023, and 2024 oil collars presented include sold puts at a weighted average price of $38.72, $38.38, and $35.00 per Bbl, respectively (3) 5%, 19%, and 23% of the 2022, 2023, and 2024 gas collars presented include sold puts at a weighted average price of $2.00 per MMBtu, respectively. |
SUMMARY OF SIGNIFICANT ACCOUN_4
SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES - Cash, Cash Equivalents, and Restricted Cash (Details) - USD ($) $ in Thousands | Dec. 31, 2021 | Dec. 31, 2020 | Dec. 31, 2019 | Dec. 31, 2018 |
Accounting Policies [Abstract] | ||||
Cash and cash equivalents | $ 254,454 | $ 24,743 | $ 11,008 | |
Restricted cash | 102 | 102 | 87 | |
Cash, Cash Equivalents, Restricted Cash and Restricted Cash Equivalents, Total | $ 254,556 | $ 24,845 | $ 11,095 | $ 13,002 |
SUMMARY OF SIGNIFICANT ACCOUN_5
SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES - Narrative (Details) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2021USD ($)contractcounterpartysegment | Dec. 31, 2020USD ($) | Dec. 31, 2019USD ($) | |
Property, Plant and Equipment [Line Items] | |||
Number of operating segments | segment | 1 | ||
Depletion expense | $ 212,500 | $ 82,600 | $ 69,300 |
Proved properties | $ 5,457,213 | 1,056,773 | |
Derivative contracts executed, number of counterparties | counterparty | 10 | ||
Abandonment and impairment of unproved properties | $ 57,260 | 37,343 | $ 11,201 |
Receivables from contracts with customers | $ 362,262 | $ 32,673 | |
Natural Gas and Fresh Water Commitment | Water Suppliers | Natural Gas And Fresh Water | |||
Property, Plant and Equipment [Line Items] | |||
Number of contracts | contract | 2 | ||
Minimum | |||
Property, Plant and Equipment [Line Items] | |||
Receivable collection period | 1 month | ||
Maximum | |||
Property, Plant and Equipment [Line Items] | |||
Receivable collection period | 2 months | ||
Midstream Assets | |||
Property, Plant and Equipment [Line Items] | |||
Proved properties | $ 276,100 | ||
PP&E useful life | 30 years | ||
Property, Plant and Equipment, Other Types | Minimum | |||
Property, Plant and Equipment [Line Items] | |||
PP&E useful life | 3 years | ||
Property, Plant and Equipment, Other Types | Maximum | |||
Property, Plant and Equipment [Line Items] | |||
PP&E useful life | 25 years |
SUMMARY OF SIGNIFICANT ACCOUN_6
SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES - Concentrations of Credit Risk (Details) - Sales - Customer Concentration Risk | 12 Months Ended | ||
Dec. 31, 2021 | Dec. 31, 2020 | Dec. 31, 2019 | |
Customer A | |||
Concentration Risk [Line Items] | |||
Percent of oil and natural gas sales | 43.00% | 77.00% | 82.00% |
Customer B | |||
Concentration Risk [Line Items] | |||
Percent of oil and natural gas sales | 15.00% | 0.00% | 0.00% |
Customer C | |||
Concentration Risk [Line Items] | |||
Percent of oil and natural gas sales | 13.00% | 9.00% | 6.00% |
SUMMARY OF SIGNIFICANT ACCOUN_7
SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES - Disaggregation of Revenue (Details) - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2021 | Dec. 31, 2020 | Dec. 31, 2019 | |
Operating net revenues: | |||
Oil, natural gas, and NGL sales | $ 930,614 | $ 218,090 | $ 313,220 |
Oil sales | |||
Operating net revenues: | |||
Oil, natural gas, and NGL sales | 614,811 | 174,536 | 268,865 |
Natural gas sales | |||
Operating net revenues: | |||
Oil, natural gas, and NGL sales | 144,708 | 24,243 | 28,296 |
NGL sales | |||
Operating net revenues: | |||
Oil, natural gas, and NGL sales | $ 171,095 | $ 19,311 | $ 16,059 |
SUMMARY OF SIGNIFICANT ACCOUN_8
SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES - Recently Issued and Adopted Accounting Standards (Details) - USD ($) $ in Millions | Dec. 31, 2021 | Dec. 31, 2020 |
Accounting Policies [Abstract] | ||
Joint interest receivables, allowance | $ 3.7 | $ 0.4 |
ACQUISITIONS AND DIVESTITURES -
ACQUISITIONS AND DIVESTITURES - Narrative (Details) | Nov. 01, 2021USD ($)$ / sharesshares | Apr. 01, 2021USD ($)$ / sharesshares | Dec. 31, 2021USD ($)$ / shares | Dec. 31, 2020USD ($)$ / shares | Dec. 31, 2019USD ($) |
Business Acquisition [Line Items] | |||||
Common stock, par value (in dollars per share) | $ / shares | $ 0.01 | $ 0.01 | |||
Merger transaction costs | $ 43,555,000 | $ 6,676,000 | $ 0 | ||
HighPoint | |||||
Business Acquisition [Line Items] | |||||
Common stock, par value (in dollars per share) | $ / shares | $ 0.01 | ||||
Exchange ratio | 0.11464 | ||||
Common stock, shares issued (in shares) | shares | 9,802,000 | ||||
Aggregate principal amount | $ 100,000,000 | ||||
Revenue, included in statement of operations | 244,700,000 | ||||
HighPoint | Measurement Input, Discount Rate | Valuation Technique, Discounted Cash Flow | |||||
Business Acquisition [Line Items] | |||||
Proved oil and gas properties, measurement input | 0.13 | ||||
HighPoint | Former HighPoint Stockholders | |||||
Business Acquisition [Line Items] | |||||
Common stock, shares issued (in shares) | shares | 487,952 | ||||
HighPoint | Holders of HighPoint Senior Notes | |||||
Business Acquisition [Line Items] | |||||
Common stock, shares issued (in shares) | shares | 9,314,214 | ||||
HighPoint | Senior Notes | Senior Notes Due 2026, 7.50% | |||||
Business Acquisition [Line Items] | |||||
Aggregate principal amount | $ 100,000,000 | ||||
Interest rate (as a percent) | 7.50% | ||||
HighPoint | HighPoint Resources Corporation | |||||
Business Acquisition [Line Items] | |||||
Common stock, par value (in dollars per share) | $ / shares | $ 0.001 | ||||
HighPoint | HighPoint Operating Company | Senior Notes | Senior Notes Due 2022 and Senior Notes Due 2025 | |||||
Business Acquisition [Line Items] | |||||
Aggregate principal amount | $ 625,000,000 | ||||
HighPoint | HighPoint Operating Company | Senior Notes | Senior Notes Due 2022 | |||||
Business Acquisition [Line Items] | |||||
Interest rate (as a percent) | 7.00% | ||||
HighPoint | HighPoint Operating Company | Senior Notes | Senior Notes Due 2025 | |||||
Business Acquisition [Line Items] | |||||
Interest rate (as a percent) | 8.75% | ||||
Extraction | |||||
Business Acquisition [Line Items] | |||||
Exchange ratio | 1.1711 | ||||
Revenue, included in statement of operations | 172,300,000 | ||||
Extraction | Measurement Input, Discount Rate | Valuation Technique, Discounted Cash Flow | |||||
Business Acquisition [Line Items] | |||||
Proved oil and gas properties, measurement input | 0.10 | ||||
Extraction | Holders of Extraction Common Stock | |||||
Business Acquisition [Line Items] | |||||
Dividend equalization payment (in shares) | shares | 0.017225678 | ||||
Extraction | Stockholders of Extraction, Prior to Crestone Peak Merger | |||||
Business Acquisition [Line Items] | |||||
Stockholders, ownership percentage | 50.00% | ||||
Extraction | Stockholders of Civitas, Prior to Extraction Merger | |||||
Business Acquisition [Line Items] | |||||
Stockholders, ownership percentage | 50.00% | ||||
Extraction | Tranche A Warrants | |||||
Business Acquisition [Line Items] | |||||
Warrants issued (in shares) | shares | 3,400,000 | ||||
Extraction | Tranche B Warrants | |||||
Business Acquisition [Line Items] | |||||
Warrants issued (in shares) | shares | 1,700,000 | ||||
Extraction | Extraction Oil & Gas, Inc. | |||||
Business Acquisition [Line Items] | |||||
Common stock, par value (in dollars per share) | $ / shares | $ 0.01 | ||||
Crestone Peak | |||||
Business Acquisition [Line Items] | |||||
Exchange ratio, collective number of shares | shares | 22,500,000 | ||||
Aggregate payment, cash settlement for outstanding phantom equity awards | $ 1,500,000 | ||||
Revenue, included in statement of operations | $ 114,800,000 | ||||
Crestone Peak | Measurement Input, Discount Rate | Valuation Technique, Discounted Cash Flow | |||||
Business Acquisition [Line Items] | |||||
Proved oil and gas properties, measurement input | 0.10 | ||||
Crestone Peak | Crestone Peak Resources America Inc. | |||||
Business Acquisition [Line Items] | |||||
Common stock, par value (in dollars per share) | $ / shares | $ 0.01 | ||||
Extraction Merger And Crestone Peak Merger | Stockholders of Civitas, Prior to Merger | |||||
Business Acquisition [Line Items] | |||||
Stockholders, ownership percentage | 37.00% | ||||
Extraction Merger And Crestone Peak Merger | Stockholders of Extraction, Prior to Merger | |||||
Business Acquisition [Line Items] | |||||
Stockholders, ownership percentage | 37.00% | ||||
Extraction Merger And Crestone Peak Merger | Stockholders of Crestone, Prior to Merger | |||||
Business Acquisition [Line Items] | |||||
Stockholders, ownership percentage | 26.00% |
ACQUISITIONS AND DIVESTITURES_2
ACQUISITIONS AND DIVESTITURES - Merger Consideration (Details) $ / shares in Units, $ in Thousands | Nov. 01, 2021USD ($)$ / sharesshares | Apr. 01, 2021USD ($)$ / sharesshares |
HighPoint | ||
Business Acquisition [Line Items] | ||
Common stock, shares issued (in shares) | shares | 9,802,000 | |
Closing price per share of Civitas Common Stock (in dollars per share) | $ / shares | $ 38.25 | |
Merger consideration paid in shares of Civitas Common Stock | $ 374,933 | |
Aggregate principal amount of the 7.5% Senior Notes | 100,000 | |
Total merger consideration | $ 474,933 | |
Exchange ratio | 0.11464 | |
HighPoint | Senior Notes Due 2026, 7.50% | Senior Notes | ||
Business Acquisition [Line Items] | ||
Interest rate (as a percent) | 7.50% | |
HighPoint | Existing holders of HighPoint Common Stock | ||
Business Acquisition [Line Items] | ||
Common stock, shares issued (in shares) | shares | 488,000 | |
HighPoint | Existing holders of HighPoint Senior Notes | ||
Business Acquisition [Line Items] | ||
Common stock, shares issued (in shares) | shares | 9,314,214 | |
Extraction | ||
Business Acquisition [Line Items] | ||
Total merger consideration | $ 1,844,129 | |
Exchange ratio | 1.1711 | |
Extraction | Common Stock | ||
Business Acquisition [Line Items] | ||
Common stock, shares issued (in shares) | shares | 31,095,000 | |
Closing price per share of Civitas Common Stock (in dollars per share) | $ / shares | $ 56.10 | |
Merger consideration paid in shares of Civitas Common Stock | $ 1,744,431 | |
Extraction | Restricted Stock and Performance Restricted Stock as Share-Based Compensation, of Acquiree | ||
Business Acquisition [Line Items] | ||
Merger consideration paid in shares of Civitas Common Stock | 22,235 | |
Extraction | Restricted Stock as Share-Based Compensation, of Acquiree | ||
Business Acquisition [Line Items] | ||
Merger consideration paid in shares of Civitas Common Stock | 19,338 | |
Extraction | Performance Restricted Stock as Share-Based Compensation, of Acquiree | ||
Business Acquisition [Line Items] | ||
Merger consideration paid in shares of Civitas Common Stock | 2,897 | |
Extraction | Tranche A and Tranche B Warrants | ||
Business Acquisition [Line Items] | ||
Merger consideration paid in shares of Civitas Common Stock | 77,463 | |
Extraction | Tranche A Warrants | ||
Business Acquisition [Line Items] | ||
Merger consideration paid in shares of Civitas Common Stock | 52,164 | |
Extraction | Tranche B Warrants | ||
Business Acquisition [Line Items] | ||
Merger consideration paid in shares of Civitas Common Stock | $ 25,299 | |
Crestone Peak | Common Stock | ||
Business Acquisition [Line Items] | ||
Common stock, shares issued (in shares) | shares | 22,500,000 | |
Closing price per share of Civitas Common Stock (in dollars per share) | $ / shares | $ 56.10 | |
Merger consideration paid in shares of Civitas Common Stock | $ 1,262,250 |
ACQUISITIONS AND DIVESTITURES_3
ACQUISITIONS AND DIVESTITURES - Purchase Price Allocation (Details) - USD ($) $ in Thousands | Nov. 01, 2021 | Apr. 01, 2021 |
HighPoint | ||
Assets Acquired | ||
Cash and cash equivalents | $ 49,827 | |
Accounts receivable - oil and natural gas sales | 26,343 | |
Accounts receivable - joint interest and other | 9,161 | |
Prepaid expenses and other | 3,608 | |
Inventory of oilfield equipment | 4,688 | |
Proved properties | 539,820 | |
Other property and equipment, net of accumulated depreciation | 2,769 | |
Right-of-use assets | 4,010 | |
Deferred income tax assets | 110,513 | |
Other noncurrent assets | 797 | |
Total assets acquired | 751,536 | |
Liabilities Assumed | ||
Accounts payable and accrued expenses | 51,088 | |
Oil and natural gas revenue distribution payable | 20,786 | |
Lease liability | 4,010 | |
Derivative liability | 18,500 | |
Current portion of long-term debt | 154,000 | |
Ad valorem taxes | 3,746 | |
Asset retirement obligations | 24,473 | |
Total liabilities assumed | 276,603 | |
Net assets acquired | $ 474,933 | |
Extraction | ||
Assets Acquired | ||
Cash and cash equivalents | $ 106,360 | |
Accounts receivable - oil and natural gas sales | 119,585 | |
Accounts receivable - joint interest and other | 33,054 | |
Prepaid expenses and other | 3,044 | |
Inventory of oilfield equipment | 9,291 | |
Derivative assets | 5,834 | |
Proved properties | 1,876,014 | |
Unproved properties | 193,400 | |
Other property and equipment, net of accumulated depreciation | 40,068 | |
Right-of-use assets | 6,883 | |
Deferred income tax assets | 49,194 | |
Other noncurrent assets | 4,248 | |
Total assets acquired | 2,446,975 | |
Liabilities Assumed | ||
Accounts payable and accrued expenses | 90,353 | |
Production taxes payable | 63,572 | |
Oil and natural gas revenue distribution payable | 170,002 | |
Income tax payable | 14,000 | |
Lease liability | 6,883 | |
Derivative liability | 100,474 | |
Ad valorem taxes | 87,071 | |
Asset retirement obligations | 68,741 | |
Other noncurrent liabilities | 1,750 | |
Total liabilities assumed | 602,846 | |
Net assets acquired | 1,844,129 | |
Crestone Peak | ||
Assets Acquired | ||
Cash and cash equivalents | 67,505 | |
Accounts receivable - oil and natural gas sales | 81,340 | |
Accounts receivable - joint interest and other | 9,917 | |
Prepaid expenses and other | 2,929 | |
Inventory of oilfield equipment | 11,951 | |
Proved properties | 1,797,814 | |
Unproved properties | 453,321 | |
Other property and equipment, net of accumulated depreciation | 7,980 | |
Right-of-use assets | 7,934 | |
Total assets acquired | 2,440,691 | |
Liabilities Assumed | ||
Accounts payable and accrued expenses | 134,791 | |
Production taxes payable | 52,435 | |
Oil and natural gas revenue distribution payable | 83,950 | |
Lease liability | 7,934 | |
Derivative liability | 338,383 | |
Credit facility | 280,000 | |
Ad valorem taxes | 66,913 | |
Deferred income tax liabilities | 125,086 | |
Asset retirement obligations | 88,949 | |
Total liabilities assumed | 1,178,441 | |
Net assets acquired | $ 1,262,250 |
ACQUISITIONS AND DIVESTITURES_4
ACQUISITIONS AND DIVESTITURES - Pro Forma Information (Details) - USD ($) $ / shares in Units, $ in Thousands | 12 Months Ended | ||
Dec. 31, 2021 | Dec. 31, 2020 | Dec. 31, 2019 | |
As reported | |||
Total revenue | $ 930,614 | $ 218,090 | $ 313,220 |
Net income (loss) | $ 178,921 | $ 103,528 | $ 67,067 |
Basic net income (loss) per common share (in dollars per share) | $ 4.82 | $ 4.98 | $ 3.25 |
Diluted net income (loss) per common share (in dollars per share) | $ 4.74 | $ 4.95 | $ 3.24 |
Total revenue | $ 2,392,926 | $ 1,311,767 | |
Net income (loss) | $ 777,390 | $ (2,581,282) | |
Net income (loss) per common share - basic (in dollars per share) | $ 9.37 | $ (28.83) | |
Net income (loss) per common share - diluted (in dollars per share) | $ 9.30 | $ (28.83) | |
HighPoint | |||
As reported | |||
Total revenue | $ 72,019 | $ 250,347 | |
Net income (loss) | (46,657) | (1,081,347) | |
Extraction | |||
As reported | |||
Total revenue | 882,255 | 557,904 | |
Net income (loss) | 944,814 | (1,335,406) | |
Crestone Peak | |||
As reported | |||
Total revenue | 508,038 | 285,426 | |
Net income (loss) | $ (299,688) | $ (268,057) |
LEASES - Assets and Liabilities
LEASES - Assets and Liabilities (Details) - USD ($) $ in Thousands | Dec. 31, 2021 | Dec. 31, 2020 |
Operating Leases | ||
Total right-of-use asset | $ 39,885 | $ 29,486 |
Operating Lease, Right-of-Use Asset, Statement of Financial Position [Extensible Enumeration] | Right-of-use assets | Right-of-use assets |
Total lease liability | $ 40,271 | $ 29,905 |
Field equipment | ||
Operating Leases | ||
Total right-of-use asset | 29,312 | 27,537 |
Total lease liability | 29,312 | 27,537 |
Finance Leases | ||
Right-of-use asset - field equipment | 0 | 219 |
Lease liability - field equipment | 0 | 117 |
Corporate leases | ||
Operating Leases | ||
Total right-of-use asset | 9,484 | 1,481 |
Total lease liability | 9,870 | 1,900 |
Vehicles | ||
Operating Leases | ||
Total right-of-use asset | 1,089 | 468 |
Total lease liability | $ 1,089 | $ 468 |
LEASES - Lease Cost (Details)
LEASES - Lease Cost (Details) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2021USD ($)office_space | Dec. 31, 2020USD ($) | Dec. 31, 2019USD ($) | |
Leases [Abstract] | |||
Operating lease cost | $ 15,449 | $ 13,957 | $ 11,330 |
Finance lease cost | |||
Amortization of ROU assets | 3 | 18 | 0 |
Interest on lease liabilities | 1 | 5 | 0 |
Short-term lease cost | 3,662 | 2,058 | 8,169 |
Variable lease cost | 56 | (186) | 259 |
Sublease Income | (367) | (358) | (348) |
Total lease cost | 18,804 | 15,494 | 19,410 |
Office rent expense | $ 2,200 | $ 1,100 | $ 1,100 |
Number of office spaces subleased | office_space | 1 |
LEASES - Weighted-Average and D
LEASES - Weighted-Average and Discount Rate Information (Details) | Dec. 31, 2021 |
Operating Leases | |
Weighted-average lease term (years) | 2 years 8 months 12 days |
Weighted-average discount rate | 3.90% |
LEASES - Supplemental Cash Flow
LEASES - Supplemental Cash Flow Information (Details) - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2021 | Dec. 31, 2020 | Dec. 31, 2019 | |
Cash paid for amounts included in the measurement of lease liabilities: | |||
Operating cash flows from operating leases | $ 14,284 | $ 12,768 | $ 10,993 |
Operating cash flows from finance leases | 1 | 5 | 0 |
Financing cash flows from finance leases | 21 | 102 | 0 |
Right-of-use assets obtained in exchange for new operating lease obligations | 25,469 | 8,306 | 16,568 |
Right-of-use assets obtained in exchange for new finance lease obligations | $ 0 | $ 219 | $ 0 |
LEASES - Lease Maturities (Deta
LEASES - Lease Maturities (Details) - USD ($) $ in Thousands | Dec. 31, 2021 | Dec. 31, 2020 |
Operating Leases | ||
2022 | $ 20,044 | |
2023 | 12,980 | |
2024 | 5,247 | |
2025 | 1,496 | |
2026 | 1,178 | |
Thereafter | 1,586 | |
Total lease payments | 42,531 | |
Less: imputed interest | (2,260) | |
Total lease liability | $ 40,271 | $ 29,905 |
OTHER NONCURRENT ASSETS, ACCO_3
OTHER NONCURRENT ASSETS, ACCOUNTS PAYABLE, AND ACCRUED EXPENSES - Schedule of Other Noncurrent Assets (Details) - USD ($) $ in Thousands | Dec. 31, 2021 | Dec. 31, 2020 | Dec. 31, 2019 |
Other Assets [Abstract] | |||
Deferred financing costs | $ 7,543 | $ 725 | |
Operating bonds | 3,485 | 1,641 | |
Carbon offsets | 1,967 | 0 | |
Notes receivable | 506 | 0 | |
AMT credit refund | 403 | 403 | |
Restricted cash | 102 | 102 | $ 87 |
Other | 79 | 0 | |
Other noncurrent assets | $ 14,085 | $ 2,871 |
OTHER NONCURRENT ASSETS, ACCO_4
OTHER NONCURRENT ASSETS, ACCOUNTS PAYABLE, AND ACCRUED EXPENSES - Accounts Payable and Accrued Expenses (Details) - USD ($) $ in Thousands | Dec. 31, 2021 | Dec. 31, 2020 |
Other Assets [Abstract] | ||
Accounts payable trade | $ 19,623 | $ 1,931 |
Accrued drilling and completion costs | 129,430 | 453 |
Accrued lease operating expense | 19,077 | 1,793 |
Accrued general and administrative expense | 21,163 | 4,942 |
Accrued merger transaction costs | 1,475 | 2,587 |
Accrued oil and NGL hedging | 26,601 | 0 |
Accrued interest expense | 6,303 | 322 |
Accrued settlement | 20,791 | 0 |
Other accrued expenses | 1,725 | 65 |
Total accounts payable and accrued expenses | $ 246,188 | $ 12,093 |
LONG-TERM DEBT - Narrative (Det
LONG-TERM DEBT - Narrative (Details) | Nov. 01, 2021USD ($) | Oct. 13, 2021USD ($)agency | Apr. 01, 2021USD ($)agency | Mar. 31, 2021USD ($) | Jun. 30, 2020 | Dec. 31, 2021USD ($) | Dec. 31, 2020USD ($) | Dec. 31, 2019USD ($) | Mar. 08, 2022USD ($) |
LONG-TERM DEBT | |||||||||
Interest expense | $ 16,000,000 | $ 3,800,000 | $ 5,100,000 | ||||||
Capitalized interest | 6,300,000 | 1,800,000 | $ 2,400,000 | ||||||
Revolver | |||||||||
LONG-TERM DEBT | |||||||||
Minimum current ratio covenant | 1 | ||||||||
Credit facility outstanding | 0 | 0 | |||||||
Revolver | Subsequent Event | |||||||||
LONG-TERM DEBT | |||||||||
Credit facility outstanding | $ 0 | ||||||||
Revolver | LIBOR | Minimum | |||||||||
LONG-TERM DEBT | |||||||||
Basis spread on variable rate | 0.00% | ||||||||
Revolver | Eurodollar | Minimum | |||||||||
LONG-TERM DEBT | |||||||||
Basis spread on variable rate | 2.00% | ||||||||
Revolver | Eurodollar | Maximum | |||||||||
LONG-TERM DEBT | |||||||||
Basis spread on variable rate | 3.00% | ||||||||
Revolver | Reference Rate | Minimum | |||||||||
LONG-TERM DEBT | |||||||||
Basis spread on variable rate | 1.00% | ||||||||
Revolver | Reference Rate | Maximum | |||||||||
LONG-TERM DEBT | |||||||||
Basis spread on variable rate | 2.00% | ||||||||
Amended Credit Agreement | Revolver | |||||||||
LONG-TERM DEBT | |||||||||
Elected commitments | $ 800,000,000 | $ 400,000,000 | |||||||
Maximum borrowing capacity | $ 2,000,000,000 | ||||||||
Maximum pro-forma leverage ratio, criteria one, if circumstances met | 1.50 | ||||||||
Minimum pro-forma leverage ratio, criteria two, if circumstances met | 1.50 | ||||||||
Covenant, minimum percentage of mortgage on total value of certain proved oil and gas properties | 90.00% | ||||||||
Amended Credit Agreement | HighPoint | Revolver | |||||||||
LONG-TERM DEBT | |||||||||
Borrowing base amount | $ 1,000,000,000 | 500,000,000 | $ 260,000,000 | ||||||
Maximum borrowing capacity | $ 1,000,000,000 | $ 750,000,000 | |||||||
Maximum net leverage ratio | 3 | 3.50 | |||||||
Borrowing requirement, maximum cash balance | $ 500,000,000 | ||||||||
Unamortized deferred financing costs | 3,900,000 | 6,800,000 | |||||||
Amended Credit Agreement | HighPoint | Revolver | Other Noncurrent Assets | |||||||||
LONG-TERM DEBT | |||||||||
Unamortized deferred financing costs | 7,500,000 | 700,000 | |||||||
Amended Credit Agreement | HighPoint | Revolver | Prepaid Expenses and Other Current Assets | |||||||||
LONG-TERM DEBT | |||||||||
Unamortized deferred financing costs | $ 2,700,000 | $ 400,000 | |||||||
Amended Credit Agreement | HighPoint | Revolver | LIBOR | Minimum | |||||||||
LONG-TERM DEBT | |||||||||
Basis spread on variable rate | 0.50% | 0.00% | |||||||
Amended Credit Agreement | HighPoint | Revolver | Eurodollar | |||||||||
LONG-TERM DEBT | |||||||||
Basis spread on variable rate | 4.00% | 3.00% | |||||||
Amended Credit Agreement | HighPoint | Revolver | Reference Rate | |||||||||
LONG-TERM DEBT | |||||||||
Basis spread on variable rate | 3.00% | 2.00% | |||||||
Amended Credit Agreement | HighPoint | Revolver | Base Rate | Minimum | |||||||||
LONG-TERM DEBT | |||||||||
Basis spread on variable rate | 0.00% | ||||||||
Amended Credit Agreement | HighPoint | Revolver | Base Rate | Maximum | |||||||||
LONG-TERM DEBT | |||||||||
Basis spread on variable rate | 1.50% | ||||||||
Senior Notes | Senior Notes Due 2026, 5.0% | |||||||||
LONG-TERM DEBT | |||||||||
Interest rate (as a percent) | 5.00% | ||||||||
Aggregate principal amount | $ 400,000,000 | ||||||||
Covenant, investment-grade rating, number of ratings agencies (at least) | agency | 2 | ||||||||
Unamortized deferred financing costs | $ 8,290,000 | ||||||||
Senior Notes | Senior Notes Due 2026, 5.0%, Indenture | |||||||||
LONG-TERM DEBT | |||||||||
Interest rate (as a percent) | 5.00% | ||||||||
Senior Notes | Senior Notes Due 2026, 7.50% | HighPoint | |||||||||
LONG-TERM DEBT | |||||||||
Interest rate (as a percent) | 7.50% | ||||||||
Aggregate principal amount | $ 100,000,000 | ||||||||
Unamortized deferred financing costs | $ 0 | ||||||||
Senior Notes | Senior Notes Due 2026, 7.50%, Indenture | |||||||||
LONG-TERM DEBT | |||||||||
Covenant, investment-grade rating, number of ratings agencies (at least) | agency | 2 | ||||||||
Senior Notes | Senior Notes Due 2026, 7.50%, Indenture | HighPoint | |||||||||
LONG-TERM DEBT | |||||||||
Interest rate (as a percent) | 7.50% | ||||||||
Senior Notes | Debt Instrument, Redemption, Period One | Senior Notes Due 2026, 5.0% | |||||||||
LONG-TERM DEBT | |||||||||
Percentage of principal amount redeemed (up to) | 35.00% | ||||||||
Redemption period, after date of closing of equity offering | 180 days | ||||||||
Senior Notes | Debt Instrument, Redemption, Period One | Senior Notes Due 2026, 7.50% | HighPoint | |||||||||
LONG-TERM DEBT | |||||||||
Redemption price, percentage | 107.50% | ||||||||
Senior Notes | Debt Instrument, Redemption, Period Two | Senior Notes Due 2026, 5.0% | |||||||||
LONG-TERM DEBT | |||||||||
Redemption price, percentage | 102.50% | ||||||||
Percentage of principal amount not redeemed | 65.00% | ||||||||
Senior Notes | Debt Instrument, Redemption, Period Two | Senior Notes Due 2026, 7.50% | HighPoint | |||||||||
LONG-TERM DEBT | |||||||||
Redemption price, percentage | 100.00% | ||||||||
Senior Notes | Debt Instrument, Redemption, Period Three | Senior Notes Due 2026, 5.0% | |||||||||
LONG-TERM DEBT | |||||||||
Redemption price, percentage | 101.25% | ||||||||
Senior Notes | Debt Instrument, Redemption, Period Four | Senior Notes Due 2026, 5.0% | |||||||||
LONG-TERM DEBT | |||||||||
Redemption price, percentage | 100.00% | ||||||||
Senior Notes | Debt Instrument, Redemption, Period Five | Senior Notes Due 2026, 5.0% | |||||||||
LONG-TERM DEBT | |||||||||
Redemption price, percentage | 105.00% |
LONG-TERM DEBT - Schedule of Ca
LONG-TERM DEBT - Schedule of Carrying Value (Details) - Senior Notes - USD ($) | Oct. 13, 2021 | Apr. 01, 2021 |
Senior Notes Due 2026, 7.50% | HighPoint | ||
LONG-TERM DEBT | ||
Principal Amount | $ 100,000,000 | |
Unamortized Deferred Financing Costs | 0 | |
Carrying Value | $ 100,000,000 | |
Interest rate (as a percent) | 7.50% | |
Senior Notes Due 2026, 5.0% | ||
LONG-TERM DEBT | ||
Principal Amount | $ 400,000,000 | |
Unamortized Deferred Financing Costs | 8,290,000 | |
Carrying Value | $ 391,710,000 | |
Interest rate (as a percent) | 5.00% |
COMMITMENTS AND CONTINGENCIES -
COMMITMENTS AND CONTINGENCIES - Narrative (Details) $ in Thousands | 12 Months Ended | |||||
Dec. 31, 2023 | Dec. 31, 2022 | Dec. 31, 2021USD ($)aclaimhorizontal_wellwellcontractplantbblBcfMMcf | Dec. 31, 2020USD ($) | Dec. 31, 2019USD ($) | Apr. 01, 2021contractbbl / d | |
Loss Contingencies [Line Items] | ||||||
Number of claims | claim | 0 | |||||
Unused commitments | $ 7,692 | $ 0 | $ 0 | |||
Firm Transportation | ||||||
Loss Contingencies [Line Items] | ||||||
Financial commitment | $ 47,104 | |||||
Crude Oil | Crude Oil Commitment | ||||||
Loss Contingencies [Line Items] | ||||||
Optional extended term (up to) | 3 years | |||||
Natural Gas And Fresh Water | Natural Gas and Fresh Water Commitment | ||||||
Loss Contingencies [Line Items] | ||||||
Financial commitment | $ 0 | |||||
NGL Crude Logistics | Crude Oil | Crude Oil Commitment | ||||||
Loss Contingencies [Line Items] | ||||||
Financial commitment | $ 36,400 | |||||
Periodic deficiency payment, incremental payment period | 6 months | |||||
Purchase commitment, volume required annual increase | 3.00% | 3.00% | ||||
Maximum volume requirement | bbl | 16,000 | |||||
Notification period, prior to agreement expiration date, optional extended term (at least) | 12 months | |||||
NGL Crude Logistics | Scenario, Forecast | Crude Oil | Crude Oil Commitment | ||||||
Loss Contingencies [Line Items] | ||||||
Purchase commitment, volume required annual increase | 3.00% | 3.00% | ||||
Third-Party Midstream Provider | ||||||
Loss Contingencies [Line Items] | ||||||
Horizontal well drilling, number of wells required to be drilled | horizontal_well | 106 | |||||
Horizontal well drilling, minimum number of wells required to be drilled, period ending December 31, 2026 | 2 years | |||||
Third-Party Midstream Provider | Gas contracts | Natural Gas Commitment and Take-In-Kind Natural Gas Liquids Commitment | ||||||
Loss Contingencies [Line Items] | ||||||
Financial commitment | $ 151,800 | |||||
Third-Party Midstream Provider | Gas contracts | Natural Gas Commitment | ||||||
Loss Contingencies [Line Items] | ||||||
Annual minimum volume requirement | Bcf | 13 | |||||
Third-Party Midstream Provider | Gas contracts | Take-In-Kind Natural Gas Liquids Commitment | ||||||
Loss Contingencies [Line Items] | ||||||
Daily sales commitment requirement, through year seven | bbl | 7,500 | |||||
Monthly roll forward shortfall requirement, percent (up to) | 10.00% | |||||
Third-Party Producers And A Third-Party Midstream Provider | Gas contracts | Natural Gas Commitment | ||||||
Loss Contingencies [Line Items] | ||||||
Number of different plants | plant | 2 | |||||
Daily baseline volume requirement | MMcf | 65 | |||||
Daily baseline volume requirement, term | 7 years | |||||
Third-Party Producers And A Third-Party Midstream Provider | Gas contracts | Natural Gas Commitment | Minimum | ||||||
Loss Contingencies [Line Items] | ||||||
Daily incremental volume requirement | MMcf | 51.5 | |||||
Third-Party Producers And A Third-Party Midstream Provider | Gas contracts | Natural Gas Commitment | Maximum | ||||||
Loss Contingencies [Line Items] | ||||||
Daily incremental volume requirement | MMcf | 20.6 | |||||
Water Suppliers | Natural Gas And Fresh Water | Natural Gas and Fresh Water Commitment | ||||||
Loss Contingencies [Line Items] | ||||||
Number of contracts | contract | 2 | |||||
Financial commitment | $ 15,700 | |||||
HighPoint | Firm Transportation | ||||||
Loss Contingencies [Line Items] | ||||||
Number of contracts | contract | 2 | |||||
Unused commitments | 7,700 | |||||
HighPoint | Pipeline Transportation Commitment | ||||||
Loss Contingencies [Line Items] | ||||||
Number of contracts | contract | 1 | |||||
Minimum volume transportation charges, gross barrels per day requirement through April 2022 | bbl / d | 8,500 | |||||
Minimum volume transportation charges, gross barrels per day requirement thereafter through April 2025 | bbl / d | 12,500 | |||||
Financial commitment | $ 47,100 | |||||
Board of County Commissioners of Boulder County Litigation | Pending Litigation | Extraction | ||||||
Loss Contingencies [Line Items] | ||||||
Number of planned wells | well | 32 | |||||
Drilling and spacing units, maximum acres | a | 80 | |||||
Sterling Energy Investments LLC Versus HighPoint Operating Corporation Litigation | Pending Litigation | HighPoint | ||||||
Loss Contingencies [Line Items] | ||||||
Accrued litigation liability | $ 1,000 |
COMMITMENTS AND CONTINGENCIES_2
COMMITMENTS AND CONTINGENCIES - Schedule of Purchase Obligations (Details) $ in Thousands | Dec. 31, 2021USD ($) |
Firm Transportation | |
Long-term Purchase Commitment [Line Items] | |
2022 | $ 13,064 |
2023 | 14,600 |
2024 | 14,640 |
2025 | 4,800 |
2026 and thereafter | 0 |
Total | 47,104 |
NGL sales | |
Long-term Purchase Commitment [Line Items] | |
2022 | 58,284 |
2023 | 29,192 |
2024 | 22,298 |
2025 | 20,400 |
2026 and thereafter | 73,712 |
Total | $ 203,886 |
STOCK-BASED COMPENSATION - Narr
STOCK-BASED COMPENSATION - Narrative (Details) | Nov. 01, 2021USD ($)shares | Dec. 31, 2021USD ($)performance_criteriashares | Dec. 31, 2020USD ($)shares | Dec. 31, 2019USD ($)shares | Sep. 30, 2021shares | Dec. 31, 2017shares |
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ||||||
Excess tax benefit for vested awards | $ | $ 700,000 | $ 0 | $ 0 | |||
Extraction | Restricted Stock as Share-Based Compensation, of Acquiree | ||||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ||||||
Fair value allocated to consideration transferred | $ | $ 19,338,000 | |||||
Extraction | Performance Restricted Stock as Share-Based Compensation, of Acquiree | ||||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ||||||
Fair value allocated to consideration transferred | $ | $ 2,897,000 | |||||
LTIP | ||||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ||||||
Aggregate intrinsic value, options exercised | $ | 700,000 | |||||
LTIP | Restricted Stock Units (RSUs) and Deferred Stock Units (DSUs) | Non-executive Board Members | ||||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ||||||
Fair value of units granted | $ | $ 33,200,000 | $ 4,900,000 | $ 5,900,000 | |||
LTIP | Restricted Stock Units (RSUs) | ||||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ||||||
Number of shares released upon vesting (in shares) | 1 | |||||
LTIP | Restricted Stock Units (RSUs) | Vesting Period One | ||||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ||||||
Vesting period | 1 year | |||||
LTIP | Restricted Stock Units (RSUs) | Vesting Period Two | ||||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ||||||
Vesting period | 3 years | |||||
LTIP | Restricted Stock Units (RSUs) | Vesting Period Two, Anniversary One | ||||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ||||||
Vesting percent of shares | 33.00% | |||||
LTIP | Restricted Stock Units (RSUs) | Vesting Period Two, Anniversary Two | ||||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ||||||
Vesting percent of shares | 33.00% | |||||
LTIP | Restricted Stock Units (RSUs) | Vesting Period Two, Anniversary Three | ||||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ||||||
Vesting percent of shares | 33.00% | |||||
LTIP | Deferred Stock Units (DSUs) | ||||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ||||||
Number of shares released upon vesting (in shares) | 1 | |||||
LTIP | Deferred Stock Units (DSUs) | Vesting Period One | ||||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ||||||
Vesting period | 1 year | |||||
LTIP | Stock options | ||||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ||||||
Expiration period | 10 years | |||||
Options granted (in shares) | 0 | 0 | 0 | |||
LTIP | Performance Stock Units (PSUs) | Minimum | ||||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ||||||
Ratio at which award holders get common stock of the company | 0 | |||||
LTIP | Performance Stock Units (PSUs) | Maximum | ||||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ||||||
Ratio at which award holders get common stock of the company | 2 | |||||
LTIP | Performance Stock Units (PSUs) | Officers | ||||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ||||||
Vesting period | 3 years | |||||
Fair value of units granted | $ | $ 15,600,000 | $ 1,900,000 | $ 2,300,000 | |||
Performance achievement, number of criteria | performance_criteria | 2 | |||||
Number of trading days | 30 days | |||||
LTIP | Performance Stock Units (PSUs) | Officers | Minimum | ||||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ||||||
Ratio at which award holders get common stock of the company | 0 | |||||
LTIP | Performance Stock Units (PSUs) | Officers | Maximum | ||||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ||||||
Ratio at which award holders get common stock of the company | 2 | |||||
LTIP | Performance Stock Units (PSUs), TSR | Officers | ||||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ||||||
Distribution of shares to recipients (as a percentage) | 200.00% | |||||
LTIP | ROCE | Officers | ||||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ||||||
Distribution of shares to recipients (in shares) | 0 | |||||
2017 LTIP | ||||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ||||||
Shares reserved for future issuance (in shares) | 2,467,430 | |||||
2021 LTIP | ||||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ||||||
Shares reserved for future issuance (in shares) | 700,000 | |||||
Extraction Equity Plan | ||||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ||||||
Shares reserved for future issuance (in shares) | 3,305,080 | |||||
Extraction Equity Plan | Performance Stock Units (PSUs) | Officers | ||||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ||||||
Performance achievement, number of criteria | performance_criteria | 1 |
STOCK-BASED COMPENSATION - Sche
STOCK-BASED COMPENSATION - Schedule of Expenses (Details) - LTIP - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2021 | Dec. 31, 2020 | Dec. 31, 2019 | |
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||
Total stock-based compensation | $ 15,558 | $ 6,156 | $ 6,886 |
Restricted and deferred stock units | |||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||
Total stock-based compensation | 11,895 | 5,283 | 5,518 |
Performance stock units | |||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||
Total stock-based compensation | 3,663 | 748 | 764 |
Stock options | |||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||
Total stock-based compensation | $ 0 | $ 125 | $ 604 |
STOCK-BASED COMPENSATION - Unre
STOCK-BASED COMPENSATION - Unrecognized Compensation Expense (Details) - LTIP $ in Thousands | Dec. 31, 2021USD ($) |
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |
Total unrecognized stock-based compensation | $ 20,525 |
Restricted and deferred stock units | |
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |
Total unrecognized stock-based compensation | 9,333 |
Performance stock units | |
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |
Total unrecognized stock-based compensation | $ 11,192 |
STOCK-BASED COMPENSATION - Acti
STOCK-BASED COMPENSATION - Activity of Non-Option Awards (Details) - LTIP | 12 Months Ended |
Dec. 31, 2021$ / sharesshares | |
RSUs and DSUs | |
Stock Units | |
Non-vested, beginning of year (in shares) | shares | 550,056 |
Granted (in shares) | shares | 662,748 |
Vested (in shares) | shares | (373,696) |
Forfeited (in shares) | shares | (24,046) |
Non-vested, end of year (in shares) | shares | 815,062 |
Weighted-Average Grant-Date Fair Value | |
Non-vested, beginning of year (in dollars per share) | $ / shares | $ 20.30 |
Granted (in dollars per share) | $ / shares | 50.12 |
Vested (in dollars per share) | $ / shares | 25.61 |
Forfeited (in dollars per share) | $ / shares | 17.99 |
Non-vested, end of year (in dollars per share) | $ / shares | $ 42.18 |
PSUs | |
Stock Units | |
Non-vested, beginning of year (in shares) | shares | 185,588 |
Granted (in shares) | shares | 177,034 |
Vested (in shares) | shares | (43,255) |
Non-vested, end of year (in shares) | shares | 319,367 |
Weighted-Average Grant-Date Fair Value | |
Non-vested, beginning of year (in dollars per share) | $ / shares | $ 22.63 |
Granted (in dollars per share) | $ / shares | 88.13 |
Vested (in dollars per share) | $ / shares | 32.68 |
Non-vested, end of year (in dollars per share) | $ / shares | $ 57.58 |
PSUs | Minimum | |
Weighted-Average Grant-Date Fair Value | |
Ratio at which award holders get common stock of the company | 0 |
PSUs | Maximum | |
Weighted-Average Grant-Date Fair Value | |
Ratio at which award holders get common stock of the company | 2 |
STOCK-BASED COMPENSATION - Othe
STOCK-BASED COMPENSATION - Other Than Options Split Criteria (Details) - LTIP - Officers | 12 Months Ended | ||
Dec. 31, 2021 | Dec. 31, 2020 | Dec. 31, 2019 | |
TSR | 2021 | |||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||
Total number of dual-criteria PSUs granted, percent | 100.00% | ||
TSR | 2020 | |||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||
Total number of dual-criteria PSUs granted, percent | 67.00% | ||
TSR | 2019 | |||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||
Total number of dual-criteria PSUs granted, percent | 50.00% | ||
ROCE | 2021 | |||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||
Total number of dual-criteria PSUs granted, percent | 0.00% | ||
ROCE | 2020 | |||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||
Total number of dual-criteria PSUs granted, percent | 33.00% | ||
ROCE | 2019 | |||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||
Total number of dual-criteria PSUs granted, percent | 50.00% |
STOCK-BASED COMPENSATION - Valu
STOCK-BASED COMPENSATION - Valuation Assumptions (Details) - Officers | 12 Months Ended | ||
Dec. 31, 2021 | Dec. 31, 2020 | Dec. 31, 2019 | |
LTIP | TSR | |||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||
Expected term (in years) | 3 years | 3 years | 3 years |
Risk-free interest rate | 0.30% | 0.22% | 2.26% |
Expected daily volatility | 3.80% | 3.50% | 2.60% |
Extraction Equity Plan | ATSR | |||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||
Expected term (in years) | 2 years 2 months 12 days | ||
Risk-free interest rate | 0.56% | ||
Expected daily volatility | 4.70% |
STOCK-BASED COMPENSATION - Ac_2
STOCK-BASED COMPENSATION - Activity of Stock Options (Details) - LTIP | 12 Months Ended |
Dec. 31, 2021USD ($)$ / sharesshares | |
Stock Options | |
Outstanding, beginning of year (shares) | shares | 72,368 |
Exercised (shares) | shares | (46,309) |
Forfeited (shares) | shares | (510) |
Outstanding, end of year (shares) | shares | 25,549 |
Options outstanding and exercisable (shares) | shares | 25,549 |
Weighted- Average Exercise Price | |
Outstanding, beginning of year (in dollars per share) | $ / shares | $ 34.36 |
Exercised (in dollars per share) | $ / shares | 34.36 |
Forfeited (in dollars per share) | $ / shares | 34.36 |
Outstanding, end of year (in dollars per share) | $ / shares | 34.36 |
Options outstanding and exercisable (in dollars per share) | $ / shares | $ 34.36 |
Additional Information | |
Weighted-Average Remaining Contractual Term (in years) | 5 years |
Options outstanding and exercisable, Weighted-Average Remaining Contractual Term (in years) | 5 years |
Aggregate Intrinsic Value (in thousands) | $ | $ 373,000 |
Options outstanding and exercisable, Aggregate Intrinsic Value (in thousands) | $ | $ 373,000 |
FAIR VALUE MEASUREMENTS - Sched
FAIR VALUE MEASUREMENTS - Schedule of Non-financial Assets and Liabilities (Details) - Estimate of Fair Value Measurement - USD ($) $ in Thousands | Dec. 31, 2021 | Dec. 31, 2020 |
Level 1 | ||
Financial assets and liabilities accounted for at fair value | ||
Derivative assets | $ 0 | $ 0 |
Derivative liabilities | 0 | 0 |
Level 2 | ||
Financial assets and liabilities accounted for at fair value | ||
Derivative assets | 3,393 | 7,482 |
Derivative liabilities | 239,763 | 7,732 |
Level 3 | ||
Financial assets and liabilities accounted for at fair value | ||
Derivative assets | 0 | 0 |
Derivative liabilities | $ 0 | $ 0 |
FAIR VALUE MEASUREMENTS - Narra
FAIR VALUE MEASUREMENTS - Narrative (Details) - USD ($) | Nov. 01, 2021 | Apr. 01, 2021 | Dec. 31, 2021 | Dec. 31, 2020 | Dec. 31, 2019 | Oct. 13, 2021 |
Financial assets and liabilities accounted for at fair value | ||||||
Proved oil and gas property impairments | $ 0 | $ 0 | $ 0 | |||
Senior Notes Due 2026, 5.0% | Senior Notes | ||||||
Financial assets and liabilities accounted for at fair value | ||||||
Interest rate (as a percent) | 5.00% | |||||
Senior Notes Due 2026, 5.0% | Senior Notes | Level 1 | ||||||
Financial assets and liabilities accounted for at fair value | ||||||
Long-term debt, fair value | 404,700,000 | |||||
HighPoint | ||||||
Financial assets and liabilities accounted for at fair value | ||||||
Fair value allocated to consideration transferred | $ 374,933,000 | |||||
HighPoint | Senior Notes Due 2026, 7.50% | Senior Notes | ||||||
Financial assets and liabilities accounted for at fair value | ||||||
Interest rate (as a percent) | 7.50% | |||||
HighPoint | Senior Notes Due 2026, 7.50% | Senior Notes | Level 1 | ||||||
Financial assets and liabilities accounted for at fair value | ||||||
Long-term debt, fair value | $ 101,000,000 | |||||
Extraction | Tranche A and Tranche B Warrants | ||||||
Financial assets and liabilities accounted for at fair value | ||||||
Fair value allocated to consideration transferred | $ 77,463,000 |
DERIVATIVES - Commodity Derivat
DERIVATIVES - Commodity Derivatives (Details) - Subsequent Event - Scenario, Forecast | 3 Months Ended | 12 Months Ended | ||||
Dec. 31, 2022MMBTU$ / bbl$ / MMBTUbbl | Sep. 30, 2022MMBTU$ / bbl$ / MMBTUbbl | Jun. 30, 2022MMBTU$ / MMBTU$ / bblbbl | Mar. 31, 2022MMBTU$ / bbl$ / MMBTUbbl | Dec. 31, 2024MMBTU$ / MMBTU | Dec. 31, 2023MMBTU$ / bbl$ / MMBTUbbl | |
Crude Oil (NYMEX WTI) | Collar | ||||||
Derivative [Line Items] | ||||||
Notional amount (in unit per day) | bbl | 6,938 | 7,681 | 8,800 | 15,700 | 260 | |
Crude Oil (NYMEX WTI) | Collar | Minimum | ||||||
Derivative [Line Items] | ||||||
Weighted Avg. Price (in dollars per unit) | $ / bbl | 40.75 | 40.35 | 38.09 | 43.83 | 40 | |
Crude Oil (NYMEX WTI) | Collar | Maximum | ||||||
Derivative [Line Items] | ||||||
Weighted Avg. Price (in dollars per unit) | $ / bbl | 70.99 | 69.99 | 67.48 | 59.77 | 72.70 | |
Crude Oil (NYMEX WTI) | Swap | ||||||
Derivative [Line Items] | ||||||
Notional amount (in unit per day) | bbl | 8,686 | 9,359 | 10,139 | 15,371 | 200 | |
Weighted Avg. Price (in dollars per unit) | $ / bbl | 46.77 | 46.88 | 49.84 | 47.39 | 46.05 | |
Crude Oil (NYMEX WTI) | Oil roll Swap | ||||||
Derivative [Line Items] | ||||||
Notional amount (in unit per day) | bbl | 2,000 | 2,000 | 2,000 | 2,000 | ||
Weighted Avg. Price (in dollars per unit) | $ / bbl | 0.22 | 0.22 | 0.22 | 0.22 | ||
Natural Gas (NYMEX Henry Hub) | Collar | ||||||
Derivative [Line Items] | ||||||
Natural Gas, notional amount (in MMBtu per day) | MMBTU | 76,929 | 78,420 | 60,375 | 2,184 | ||
Natural Gas (NYMEX Henry Hub) | Collar | Minimum | ||||||
Derivative [Line Items] | ||||||
Weighted Average Price (in dollars per MMBtu) | 2.60 | 2.59 | 2.50 | 2 | ||
Natural Gas (NYMEX Henry Hub) | Collar | Maximum | ||||||
Derivative [Line Items] | ||||||
Weighted Average Price (in dollars per MMBtu) | 3.69 | 3.68 | 3.50 | 3.25 | ||
Natural Gas (NYMEX Henry Hub) | Swap | ||||||
Derivative [Line Items] | ||||||
Natural Gas, notional amount (in MMBtu per day) | MMBTU | 53,300 | 53,300 | 53,300 | 125,170 | 22,309 | 43,600 |
Weighted Average Price (in dollars per MMBtu) | 2.77 | 2.77 | 2.77 | 2.90 | 2.57 | 2.51 |
Natural Gas (CIG) | Collar | ||||||
Derivative [Line Items] | ||||||
Natural Gas, notional amount (in MMBtu per day) | MMBTU | 20,000 | 20,000 | ||||
Natural Gas (CIG) | Collar | Minimum | ||||||
Derivative [Line Items] | ||||||
Weighted Average Price (in dollars per MMBtu) | 2.15 | 2.15 | ||||
Natural Gas (CIG) | Collar | Maximum | ||||||
Derivative [Line Items] | ||||||
Weighted Average Price (in dollars per MMBtu) | 2.75 | 2.75 | ||||
Natural Gas (CIG) | Swap | ||||||
Derivative [Line Items] | ||||||
Natural Gas, notional amount (in MMBtu per day) | MMBTU | 10,000 | 10,000 | 10,000 | 10,000 | ||
Weighted Average Price (in dollars per MMBtu) | 2.13 | 2.13 | 2.13 | 2.13 | ||
Natural Gas Liquids (OPIS) | Swap | ||||||
Derivative [Line Items] | ||||||
Notional amount (in unit per day) | bbl | 4,000 | 4,000 | 4,000 | 4,000 | ||
Weighted Avg. Price (in dollars per unit) | $ / bbl | 20.22 | 20.22 | 20.22 | 20.22 |
DERIVATIVES - Derivative Positi
DERIVATIVES - Derivative Positions (Details) - Commodity - USD ($) $ in Thousands | Dec. 31, 2021 | Dec. 31, 2020 |
Derivative Assets: | ||
Total derivative assets | $ 3,393 | $ 7,482 |
Amounts not offset in the accompanying balance sheets | (3,393) | (4,758) |
Total derivative assets, net | 0 | 2,724 |
Derivative Liabilities: | ||
Total derivative liabilities | (239,763) | (7,732) |
Amounts not offset in the accompanying balance sheets | 3,393 | 4,758 |
Total derivative liabilities, net | (236,370) | (2,974) |
Commodity contracts - current | ||
Derivative Assets: | ||
Total derivative assets | 3,393 | 7,482 |
Commodity contracts - noncurrent | ||
Derivative Assets: | ||
Total derivative assets | 0 | 0 |
Commodity contracts - current | ||
Derivative Liabilities: | ||
Total derivative liabilities | (219,804) | (6,402) |
Commodity contracts - long-term | ||
Derivative Liabilities: | ||
Total derivative liabilities | $ (19,959) | $ (1,330) |
DERIVATIVES - Derivative Gains
DERIVATIVES - Derivative Gains (Details) - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2021 | Dec. 31, 2020 | Dec. 31, 2019 | |
Components of the derivative gain (loss) | |||
Total derivative gain (loss) | $ (60,510) | $ 53,462 | $ (37,145) |
Commodity derivative | |||
Components of the derivative gain (loss) | |||
Total derivative cash settlement gain (loss) | (275,914) | 49,406 | 1,691 |
Change in fair value gain (loss) | 215,404 | 4,056 | (38,836) |
Total derivative gain (loss) | (60,510) | 53,462 | (37,145) |
Commodity derivative | Oil contracts | |||
Components of the derivative gain (loss) | |||
Total derivative cash settlement gain (loss) | (215,057) | 50,133 | 1,185 |
Commodity derivative | Gas contracts | |||
Components of the derivative gain (loss) | |||
Total derivative cash settlement gain (loss) | (51,806) | (727) | 506 |
Commodity derivative | NGL sales | |||
Components of the derivative gain (loss) | |||
Total derivative cash settlement gain (loss) | $ (9,051) | $ 0 | $ 0 |
ASSET RETIREMENT OBLIGATIONS -
ASSET RETIREMENT OBLIGATIONS - Schedule of Roll-Forward Activity (Details) - USD ($) $ in Thousands | 12 Months Ended | |
Dec. 31, 2021 | Dec. 31, 2020 | |
Change in asset retirement obligations | ||
Balance, beginning of year | $ 28,699 | $ 27,908 |
Additional liabilities incurred | 183,758 | 357 |
Accretion expense | 3,933 | 1,004 |
Liabilities settled | (4,221) | (2,464) |
Revisions to estimate | 13,146 | 1,894 |
Balance, end of year | 225,315 | 28,699 |
Current portion | 24,000 | 0 |
Long-term portion | $ 201,315 | $ 28,699 |
EARNINGS PER SHARE - Narrative
EARNINGS PER SHARE - Narrative (Details) | 12 Months Ended | ||
Dec. 31, 2021shares | Dec. 31, 2020shares | Dec. 31, 2019shares | |
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||
Antidilutive securities excluded from EPS calculation (in shares) | 178,051 | 248,744 | 269,208 |
LTIP | Restricted Stock Units (RSUs) | |||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||
Number of shares released upon vesting (in shares) | 1 | ||
LTIP | Deferred Stock Units (DSUs) | |||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||
Number of shares released upon vesting (in shares) | 1 | ||
LTIP | Minimum | Performance stock units | |||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||
Ratio at which award holders get common stock of the company | 0 | ||
LTIP | Maximum | Performance stock units | |||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||
Ratio at which award holders get common stock of the company | 2 |
EARNINGS PER SHARE - Schedule o
EARNINGS PER SHARE - Schedule of Earnings Per Share (Details) - USD ($) $ / shares in Units, shares in Thousands, $ in Thousands | 12 Months Ended | ||
Dec. 31, 2021 | Dec. 31, 2020 | Dec. 31, 2019 | |
Earnings Per Share [Abstract] | |||
Net income | $ 178,921 | $ 103,528 | $ 67,067 |
Basic net income per common share (in dollars per share) | $ 4.82 | $ 4.98 | $ 3.25 |
Diluted net income per common share (in dollars per share) | $ 4.74 | $ 4.95 | $ 3.24 |
Weighted-average shares outstanding - basic (in shares) | 37,155 | 20,774 | 20,612 |
Add: dilutive effect of contingent stock awards (in shares) | 591 | 138 | 69 |
Weighted-average shares outstanding - diluted (in shares) | 37,746 | 20,912 | 20,681 |
INCOME TAXES - Provision For In
INCOME TAXES - Provision For Income Taxes (Details) - USD ($) | 12 Months Ended | ||
Dec. 31, 2021 | Dec. 31, 2020 | Dec. 31, 2019 | |
Current tax expense (benefit) | |||
Federal | $ 0 | $ (27,000) | $ 0 |
State | 0 | 0 | 0 |
Total current tax expense (benefit) | 0 | (27,000) | 0 |
Deferred tax expense (benefit) | |||
Federal | 62,212,000 | (53,784,000) | 0 |
State | 10,646,000 | (6,736,000) | 0 |
Total deferred tax expense (benefit) | 72,858,000 | (60,520,000) | 0 |
Total income tax expense (benefit) | $ 72,858,000 | $ (60,547,000) | $ 0 |
INCOME TAXES - Deferred Tax Ass
INCOME TAXES - Deferred Tax Assets and Liabilities (Details) - USD ($) | Dec. 31, 2021 | Dec. 31, 2020 | Dec. 31, 2019 |
Deferred tax liabilities: | |||
Oil and gas properties | $ 608,829,000 | $ 89,867,000 | |
Right-of-use assets | 8,292,000 | 7,306,000 | |
Total deferred tax liabilities | 617,121,000 | 97,173,000 | |
Deferred tax assets: | |||
Federal and state tax net operating loss carryforward | 482,216,000 | 138,372,000 | |
Derivative instruments | 86,958,000 | 61,000 | |
Reclamation costs | 51,515,000 | 7,058,000 | |
Stock compensation | 7,622,000 | 1,653,000 | |
Inventory | 10,108,000 | 1,598,000 | |
Lease liability | 8,187,000 | 7,384,000 | |
Property taxes | 19,458,000 | 0 | |
Pending acquisition costs | 0 | 1,478,000 | |
Other long-term assets | 21,474,000 | 89,000 | |
Total deferred tax assets | 687,538,000 | 157,693,000 | |
Less: Valuation allowance | 48,133,000 | 0 | $ 72,600,000 |
Total deferred tax assets after valuation allowance | 639,405,000 | 157,693,000 | |
Total non-current net deferred tax asset | $ 22,284,000 | $ 60,520,000 |
INCOME TAXES - Narrative (Detai
INCOME TAXES - Narrative (Details) - USD ($) | 12 Months Ended | ||||||
Dec. 31, 2021 | Dec. 31, 2020 | Dec. 31, 2019 | Nov. 01, 2021 | Apr. 01, 2021 | Jan. 01, 2018 | Dec. 31, 2017 | |
Tax Credit Carryforward [Line Items] | |||||||
Net operating loss carryovers for federal income tax purposes | $ 2,000,000,000 | $ 579,400,000 | |||||
Net operating loss carryovers for federal income tax purposes, not benefited for financial statement purposes | $ 1,300,000,000 | $ 696,300,000 | |||||
Deferred tax assets, valuation allowance | 48,133,000 | 0 | $ 72,600,000 | ||||
Deferred income tax expense (benefit) | 72,858,000 | (60,520,000) | 0 | ||||
Decrease in valuation allowance | 0 | 72,553,000 | 16,523,000 | ||||
Unrecognized tax benefits | 0 | 0 | 0 | ||||
Total income tax expense (benefit) | 72,858,000 | $ (60,547,000) | $ 0 | ||||
HighPoint | |||||||
Tax Credit Carryforward [Line Items] | |||||||
Deferred tax assets, net operating loss carryforwards, federal | $ 219,000,000 | ||||||
Net deferred tax assets | 110,513,000 | ||||||
Deferred tax assets, net operating loss carryforwards annual limit, federal | 5,600,000 | ||||||
Deferred tax assets, valuation allowance | $ 48,100,000 | $ 48,100,000 | |||||
Extraction | |||||||
Tax Credit Carryforward [Line Items] | |||||||
Deferred tax assets, net operating loss carryforwards, federal | $ 479,900,000 | ||||||
Net deferred tax assets | 49,194,000 | ||||||
Deferred tax assets, net operating loss carryforwards annual limit, federal | 7,000,000 | ||||||
Crestone Peak | |||||||
Tax Credit Carryforward [Line Items] | |||||||
Deferred tax assets, net operating loss carryforwards, federal | 555,700,000 | ||||||
Deferred tax assets, net operating loss carryforwards annual limit, federal | 16,800,000 | ||||||
Net deferred tax liability | $ 125,086,000 |
INCOME TAXES - Effective Income
INCOME TAXES - Effective Income Tax Reconciliation (Details) - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2021 | Dec. 31, 2020 | Dec. 31, 2019 | |
Income Tax Disclosure [Abstract] | |||
Federal statutory tax expense | $ 52,824 | $ 9,026 | $ 14,084 |
Increase (decrease) in tax resulting from: | |||
State tax expense net of federal benefit | 10,646 | 1,694 | 2,537 |
Prior year true-up | 27 | 292 | (579) |
Stock compensation | (1,559) | 690 | 197 |
Permanent differences | 84 | 36 | 128 |
State rate change | 0 | 124 | 0 |
Transaction costs | 9,043 | 0 | 0 |
Section 162(m) limitation | 1,793 | 144 | 156 |
Valuation allowance | 0 | (72,553) | (16,523) |
Total income tax expense (benefit) | $ 72,858 | $ (60,547) | $ 0 |
DISCLOSURES ABOUT OIL AND GAS_3
DISCLOSURES ABOUT OIL AND GAS PRODUCING ACTIVITIES (UNAUDITED) - Costs Incurred in Oil and Natural Gas Producing Activities (Details) - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2021 | Dec. 31, 2020 | Dec. 31, 2019 | |
Results of Operations, Revenue from Oil and Gas Producing Activities [Abstract] | |||
Acquisition | $ 4,861,619 | $ 11,296 | $ 12,901 |
Development | 315,746 | 55,934 | 209,535 |
Exploration | 7,937 | 595 | 796 |
Total | 5,185,302 | 67,825 | 223,232 |
Acquisition costs for unproved properties | 648,000 | 2,300 | 4,200 |
Proved property acquisitions | 4,200,000 | 9,000 | 8,700 |
Workover costs charged to lease operating expense | 2,200 | 1,200 | 1,400 |
Increase (decrease) in ARO | $ 13,800 | $ (1,000) | $ (900) |
DISCLOSURES ABOUT OIL AND GAS_4
DISCLOSURES ABOUT OIL AND GAS PRODUCING ACTIVITIES (UNAUDITED) - Change in Quantities of Proved Oil, Natural Gas Liquids, and Natural Gas Reserves (Details) bbl in Thousands, Mcf in Thousands, MBoe in Millions, Boe in Millions | 12 Months Ended | |||
Dec. 31, 2021BoeMBoe$ / MMBTU$ / bblbblMcf | Dec. 31, 2020BoeMBoe$ / bbl$ / MMBTUbblMcf | Dec. 31, 2019Boe$ / bbl$ / MMBTUbblMcf | Dec. 31, 2018$ / MMBTU$ / bblbblMcf | |
Proved reserves demoted to non-proved | ||||
Changes in quantities of proved oil, natural gas liquids and natural gas reserves | ||||
Proved developed and undeveloped reserve, revision upward (reduction) of previous estimate (energy) | Boe | (24.1) | (22.9) | (8.7) | |
Proved developed and undeveloped reserve, drilling program, term | 5 years | |||
Wattenberg Field, Rocky Mountain Region | ||||
Changes in quantities of proved oil, natural gas liquids and natural gas reserves | ||||
Proved developed and undeveloped reserve, revision upward (reduction) of previous estimate (energy) | Boe | (20) | 7.5 | 6.6 | |
Revisions to previous estimates - increase (decrease) | Boe | (1.4) | |||
Wattenberg Field, Rocky Mountain Region | Changes in Well Operating Cost Methodology | ||||
Changes in quantities of proved oil, natural gas liquids and natural gas reserves | ||||
Proved developed and undeveloped reserve, revision upward (reduction) of previous estimate (energy) | Boe | (13.1) | |||
Wattenberg Field, Rocky Mountain Region | Engineering Revisions | ||||
Changes in quantities of proved oil, natural gas liquids and natural gas reserves | ||||
Proved developed and undeveloped reserve, revision upward (reduction) of previous estimate (energy) | Boe | (6.9) | 12.3 | 8.1 | |
Revisions to previous estimates - increase (decrease) | MBoe | 7.1 | (4.8) | ||
Wattenberg Field, Rocky Mountain Region | Fuel, Gas, Interest, and Other Negative Revisions | ||||
Changes in quantities of proved oil, natural gas liquids and natural gas reserves | ||||
Proved developed and undeveloped reserve, revision upward (reduction) of previous estimate (energy) | Boe | (7.1) | |||
Horizontal development | Wattenberg Field, Rocky Mountain Region | ||||
Changes in quantities of proved oil, natural gas liquids and natural gas reserves | ||||
Extensions and discoveries | Boe | 0 | 18 | 15.4 | |
Oil contracts | ||||
Changes in quantities of proved oil, natural gas liquids and natural gas reserves | ||||
Balance at the beginning of the period | 52,793 | 64,413 | 64,354 | |
Extensions, discoveries and infills | 19 | 9,376 | 8,825 | |
Production | (4,523) | (5,019) | (5,136) | |
Sales of minerals in place | (52) | |||
Removed from capital program | (12,249) | (14,120) | (4,926) | |
Purchases of minerals in place | 114,379 | 1,430 | 303 | |
Revisions to previous estimates | (6,840) | (3,287) | 1,045 | |
Balance at the end of the period | 143,579 | 52,793 | 64,413 | 64,354 |
Proved developed reserves | 104,078 | 24,320 | 25,397 | |
Proved undeveloped reserves | 39,501 | 28,473 | 39,016 | |
Oil and gas commodity price (in dollars per share) | $ / bbl | 55.85 | |||
Oil contracts | Wattenberg Field, Rocky Mountain Region | ||||
Changes in quantities of proved oil, natural gas liquids and natural gas reserves | ||||
Oil and gas commodity price (in dollars per share) | $ / bbl | 66.56 | 39.57 | 55.85 | 65.56 |
Gas contracts | ||||
Changes in quantities of proved oil, natural gas liquids and natural gas reserves | ||||
Balance at the beginning of the period | Mcf | 235,728 | 212,200 | 165,012 | |
Extensions, discoveries and infills | Mcf | 103 | 32,172 | 20,604 | |
Production | Mcf | (13,852) | (14,166) | (11,967) | |
Sales of minerals in place | Mcf | (110) | |||
Removed from capital program | Mcf | (43,918) | (33,886) | (11,508) | |
Purchases of minerals in place | Mcf | 767,504 | 5,457 | 627 | |
Revisions to previous estimates | Mcf | (57,066) | 33,951 | 49,542 | |
Balance at the end of the period | Mcf | 888,499 | 235,728 | 212,200 | 165,012 |
Proved developed reserves | Mcf | 748,762 | 123,220 | 105,840 | |
Proved undeveloped reserves | Mcf | 139,737 | 112,508 | 106,360 | |
Oil and gas commodity price (in dollars per share) | $ / MMBTU | 2.58 | |||
Gas contracts | Wattenberg Field, Rocky Mountain Region | ||||
Changes in quantities of proved oil, natural gas liquids and natural gas reserves | ||||
Oil and gas commodity price (in dollars per share) | $ / MMBTU | 3.60 | 1.99 | 2.58 | 3.10 |
Natural gas liquids (per Bbl) | ||||
Changes in quantities of proved oil, natural gas liquids and natural gas reserves | ||||
Balance at the beginning of the period | 26,111 | 22,161 | 24,930 | |
Extensions, discoveries and infills | 0 | 3,269 | 3,123 | |
Production | (1,763) | (1,858) | (1,431) | |
Sales of minerals in place | (18) | |||
Removed from capital program | (4,485) | (3,141) | (1,862) | |
Purchases of minerals in place | 89,797 | 570 | 102 | |
Revisions to previous estimates | (3,632) | 5,110 | (2,683) | |
Balance at the end of the period | 106,028 | 26,111 | 22,161 | 24,930 |
Proved developed reserves | 88,967 | 14,315 | 11,566 | |
Proved undeveloped reserves | 17,061 | 11,796 | 10,595 |
DISCLOSURES ABOUT OIL AND GAS_5
DISCLOSURES ABOUT OIL AND GAS PRODUCING ACTIVITIES (UNAUDITED) - Discounted Future Net Cash Flows Relating to Proved Oil and Natural Gas Reserves (Details) - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2021 | Dec. 31, 2020 | Dec. 31, 2019 | |
Results of Operations, Revenue from Oil and Gas Producing Activities [Abstract] | |||
Future net cash flow discount rate | 10.00% | ||
Standardized measure of discounted future net cash flows relating to proved oil and natural gas reserves | |||
Future cash flows | $ 14,401,814 | $ 2,230,012 | $ 3,827,009 |
Future production costs | (5,054,695) | (675,755) | (1,029,140) |
Future development costs | (1,107,576) | (530,970) | (850,327) |
Future income tax expense | (1,465,949) | 0 | 0 |
Future net cash flows | 6,773,594 | 1,023,287 | 1,947,542 |
10% annual discount for estimated timing of cash flows | (2,361,490) | (586,233) | (1,089,395) |
Standardized measure of discounted future net cash flows | 4,412,104 | 437,054 | 858,147 |
Changes in the standardized measure of discounted future net cash flows relating to proved oil and natural gas reserves | |||
Beginning of period | 437,054 | 858,147 | 954,980 |
Sale of oil and gas produced, net of production costs | (773,711) | (160,466) | (233,677) |
Net changes in prices and production costs | 874,155 | (641,137) | (372,233) |
Net changes in extensions, discoveries and improved recoveries | 855 | (54,269) | 45,728 |
Development costs incurred | 108,113 | 42,325 | 185,086 |
Changes in estimated development cost | 106,788 | 220,964 | 81,358 |
Purchases of minerals in place | 4,484,125 | 12,372 | 10,135 |
Sales of minerals in place | 0 | 0 | (309) |
Revisions of previous quantity estimates | (84,126) | 60,754 | 79,637 |
Net change in income taxes | (915,053) | 0 | 0 |
Accretion of discount | 43,705 | 85,815 | 95,498 |
Changes in production rates and other | 130,199 | 12,549 | 11,944 |
End of period | $ 4,412,104 | $ 437,054 | $ 858,147 |
DISCLOSURES ABOUT OIL AND GAS_6
DISCLOSURES ABOUT OIL AND GAS PRODUCING ACTIVITIES (UNAUDITED) - Average Wellhead Prices Used in Determining Future Net Revenues (Details) | 12 Months Ended | ||
Dec. 31, 2021$ / bbl$ / MMcf | Dec. 31, 2020$ / bbl$ / MMcf | Dec. 31, 2019$ / MMcf$ / bbl | |
Oil contracts | |||
Oil and Gas, Average Sale Price and Production Cost Per Unit [Line Items] | |||
Average sales price (in dollars per Bbl for oil and dollars per Mcf for gas) | 61.60 | 34.96 | 51.22 |
Gas contracts | |||
Oil and Gas, Average Sale Price and Production Cost Per Unit [Line Items] | |||
Average sales price (in dollars per Bbl for oil and dollars per Mcf for gas) | $ / MMcf | 2.60 | 0.95 | 1.44 |
Natural gas liquids (per Bbl) | |||
Oil and Gas, Average Sale Price and Production Cost Per Unit [Line Items] | |||
Average sales price (in dollars per Bbl for oil and dollars per Mcf for gas) | 30.60 | 6.12 | 10.07 |
SUBSEQUENT EVENTS (Details)
SUBSEQUENT EVENTS (Details) - Subsequent Event - Bison - USD ($) $ in Millions | Mar. 01, 2022 | Jan. 31, 2022 |
Subsequent Event [Line Items] | ||
Consideration transferred | $ 346 | |
Debt and other liabilities assumed | 176 | |
Proposed cash consideration | $ 45 | |
Cash consideration | $ 160 |
SUBSEQUENT EVENTS - Commodity D
SUBSEQUENT EVENTS - Commodity Derivatives (Details) - Subsequent Event - Scenario, Forecast | 3 Months Ended | 12 Months Ended | |||||
Dec. 31, 2022MMBTU$ / bbl$ / MMBTUbbl | Sep. 30, 2022MMBTU$ / bbl$ / MMBTUbbl | Jun. 30, 2022MMBTU$ / bbl$ / MMBTUbbl | Mar. 31, 2022MMBTU$ / bbl$ / MMBTUbbl | Dec. 31, 2024MMBTU$ / bbl$ / MMBTUbbl | Dec. 31, 2023MMBTU$ / bbl$ / MMBTUbbl | Dec. 31, 2022MMBTU$ / bbl$ / MMBTUbbl | |
Crude Oil (NYMEX WTI) | Collar | |||||||
Derivative [Line Items] | |||||||
Notional amount (in unit per day) | bbl | 6,938 | 7,681 | 8,800 | 15,700 | 260 | ||
Crude Oil (NYMEX WTI) | Collar | Bison | |||||||
Derivative [Line Items] | |||||||
Notional amount (in unit per day) | bbl | 143 | 1,406 | 2,756 | ||||
Crude Oil (NYMEX WTI) | Collar | Minimum | |||||||
Derivative [Line Items] | |||||||
Weighted Avg. Price (in dollars per unit) | $ / bbl | 40.75 | 40.35 | 38.09 | 43.83 | 40 | 40.75 | |
Crude Oil (NYMEX WTI) | Collar | Minimum | Bison | |||||||
Derivative [Line Items] | |||||||
Weighted Avg. Price (in dollars per unit) | $ / bbl | 47.85 | 45 | 48.62 | 47.85 | |||
Crude Oil (NYMEX WTI) | Collar | Maximum | |||||||
Derivative [Line Items] | |||||||
Weighted Avg. Price (in dollars per unit) | $ / bbl | 70.99 | 69.99 | 67.48 | 59.77 | 72.70 | 70.99 | |
Crude Oil (NYMEX WTI) | Collar | Maximum | Bison | |||||||
Derivative [Line Items] | |||||||
Weighted Avg. Price (in dollars per unit) | $ / bbl | 56.71 | 56.25 | 57.71 | 56.71 | |||
Crude Oil (NYMEX WTI) | Sold Put Options Included in Collar | Bison | |||||||
Derivative [Line Items] | |||||||
Weighted Avg. Price (in dollars per unit) | $ / bbl | 38.72 | 35 | 38.38 | 38.72 | |||
Weighted Avg. Price, Oil, Percent | 79.00% | 100.00% | 100.00% | 79.00% | |||
Crude Oil (NYMEX WTI) | Swap | |||||||
Derivative [Line Items] | |||||||
Notional amount (in unit per day) | bbl | 8,686 | 9,359 | 10,139 | 15,371 | 200 | ||
Weighted Avg. Price (in dollars per unit) | $ / bbl | 46.77 | 46.88 | 49.84 | 47.39 | 46.05 | 46.77 | |
Crude Oil (NYMEX WTI) | Swap | Bison | |||||||
Derivative [Line Items] | |||||||
Notional amount (in unit per day) | bbl | 479 | 208 | 873 | ||||
Weighted Avg. Price (in dollars per unit) | $ / bbl | 47.38 | 53.96 | 46.47 | 47.38 | |||
Natural Gas (NYMEX Henry Hub) | Collar | |||||||
Derivative [Line Items] | |||||||
Natural Gas, notional amount (in MMBtu per day) | MMBTU | 76,929 | 78,420 | 60,375 | 2,184 | |||
Natural Gas (NYMEX Henry Hub) | Collar | Bison | |||||||
Derivative [Line Items] | |||||||
Natural Gas, notional amount (in MMBtu per day) | MMBTU | 1,337 | 1,828 | 2,278 | ||||
Natural Gas (NYMEX Henry Hub) | Collar | Minimum | |||||||
Derivative [Line Items] | |||||||
Weighted Average Price (in dollars per MMBtu) | $ / MMBTU | 2.60 | 2.59 | 2.50 | 2 | 2.60 | ||
Natural Gas (NYMEX Henry Hub) | Collar | Minimum | Bison | |||||||
Derivative [Line Items] | |||||||
Weighted Average Price (in dollars per MMBtu) | $ / MMBTU | 2.67 | 2.40 | 2.36 | 2.67 | |||
Natural Gas (NYMEX Henry Hub) | Collar | Maximum | |||||||
Derivative [Line Items] | |||||||
Weighted Average Price (in dollars per MMBtu) | $ / MMBTU | 3.69 | 3.68 | 3.50 | 3.25 | 3.69 | ||
Natural Gas (NYMEX Henry Hub) | Collar | Maximum | Bison | |||||||
Derivative [Line Items] | |||||||
Weighted Average Price (in dollars per MMBtu) | $ / MMBTU | 3.39 | 3.15 | 2.98 | 3.39 | |||
Natural Gas (NYMEX Henry Hub) | Sold Put Options Included in Collar | Bison | |||||||
Derivative [Line Items] | |||||||
Weighted Average Price (in dollars per MMBtu) | $ / MMBTU | 2 | 2 | 2 | 2 | |||
Weighted Avg. Price, Gas, Percent | 5.00% | 23.00% | 19.00% | 5.00% | |||
Natural Gas (NYMEX Henry Hub) | Swap | |||||||
Derivative [Line Items] | |||||||
Natural Gas, notional amount (in MMBtu per day) | MMBTU | 53,300 | 53,300 | 53,300 | 125,170 | 22,309 | 43,600 | |
Weighted Average Price (in dollars per MMBtu) | $ / MMBTU | 2.77 | 2.77 | 2.77 | 2.90 | 2.57 | 2.51 | 2.77 |
Natural Gas (NYMEX Henry Hub) | Swap | Bison | |||||||
Derivative [Line Items] | |||||||
Natural Gas, notional amount (in MMBtu per day) | MMBTU | 470 | 1,582 | |||||
Weighted Average Price (in dollars per MMBtu) | $ / MMBTU | 2.52 | 2.51 | 2.52 |