Cover
Cover - USD ($) $ in Billions | 12 Months Ended | ||
Dec. 31, 2021 | Feb. 22, 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 | 001-35380 | ||
Entity Registrant Name | Laredo Petroleum, Inc. | ||
Entity Incorporation, State or Country Code | DE | ||
Entity Tax Identification Number | 45-3007926 | ||
Entity Address, Address Line One | 15 W. Sixth Street | ||
Entity Address, Address Line Two | Suite 900 | ||
Entity Address, City or Town | Tulsa | ||
Entity Address, State or Province | OK | ||
Entity Address, Postal Zip Code | 74119 | ||
City Area Code | 918 | ||
Local Phone Number | 513-4570 | ||
Title of 12(b) Security | Common stock, $0.01 par value per share | ||
Trading Symbol | LPI | ||
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 | false | ||
ICFR Auditor Attestation Flag | true | ||
Entity Shell Company | false | ||
Entity Public Float | $ 1.2 | ||
Entity Common Stock, Shares Outstanding | 17,304,100 | ||
Documents Incorporated by Reference | Portions of the registrant's definitive proxy statement for its 2022 Annual Meeting of Stockholders, which will be filed with the Securities and Exchange Commission within 120 days of December 31, 2021, are incorporated by reference into Part III of this report for the year ended December 31, 2021. | ||
Entity Central Index Key | 0001528129 | ||
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 | GRANT THORNTON LLP |
Auditor Location | Tulsa, Oklahoma |
Auditor Firm ID | 248 |
Consolidated balance sheets
Consolidated balance sheets - USD ($) $ in Thousands | Dec. 31, 2021 | Dec. 31, 2020 |
Current assets: | ||
Cash and cash equivalents | $ 56,798 | $ 48,757 |
Accounts receivable, net | 151,807 | 63,976 |
Derivatives | 4,346 | 7,893 |
Other current assets | 22,906 | 15,964 |
Total current assets | 235,857 | 136,590 |
Oil and natural gas properties, full cost method: | ||
Evaluated properties | 8,968,668 | 7,874,932 |
Unevaluated properties not being depleted | 170,033 | 70,020 |
Less: accumulated depletion and impairment | (7,019,670) | (6,817,949) |
Oil and natural gas properties, net | 2,119,031 | 1,127,003 |
Midstream service assets, net | 96,528 | 112,697 |
Other fixed assets, net | 34,590 | 32,011 |
Property and equipment, net | 2,250,149 | 1,271,711 |
Derivatives | 32,963 | 0 |
Operating lease right-of-use assets | 11,514 | 17,973 |
Other noncurrent assets, net | 21,341 | 16,336 |
Total assets | 2,551,824 | 1,442,610 |
Current liabilities: | ||
Accounts payable and accrued liabilities | 71,386 | 38,279 |
Accrued capital expenditures | 50,585 | 28,275 |
Undistributed revenue and royalties | 117,920 | 24,728 |
Derivatives | 179,809 | 31,826 |
Operating lease liabilities | 7,742 | 11,721 |
Other current liabilities | 99,471 | 62,766 |
Total current liabilities | 526,913 | 197,595 |
Long-term debt, net | 1,425,858 | 1,179,266 |
Derivatives | 0 | 12,051 |
Asset retirement obligations | 69,057 | 64,775 |
Operating lease liabilities | 5,726 | 8,918 |
Other noncurrent liabilities | 10,490 | 1,448 |
Total liabilities | 2,038,044 | 1,464,053 |
Commitments and contingencies | ||
Stockholders' equity: | ||
Preferred stock, $0.01 par value, 50,000,000 shares authorized and zero issued as of December 31, 2021 and 2020 | 0 | 0 |
Common stock, $0.01 par value, 22,500,000 shares authorized and 17,074,516 and 12,020,164 issued and outstanding as of December 31, 2021 and 2020, respectively | 171 | 120 |
Additional paid-in capital | 2,788,628 | 2,398,464 |
Accumulated deficit | (2,275,019) | (2,420,027) |
Total stockholders' equity | 513,780 | (21,443) |
Total liabilities and stockholders' equity | $ 2,551,824 | $ 1,442,610 |
Consolidated balance sheets (Pa
Consolidated balance sheets (Parenthetical) - $ / shares | Dec. 31, 2021 | Dec. 31, 2020 |
Statement of Financial Position [Abstract] | ||
Preferred stock, par value (USD per share) | $ 0.01 | $ 0.01 |
Preferred stock authorized (shares) | 50,000,000 | 50,000,000 |
Preferred stock issued (shares) | 0 | 0 |
Common stock, par value (USD per share) | $ 0.01 | $ 0.01 |
Common stock authorized (shares) | 22,500,000 | 22,500,000 |
Common stock issued (shares) | 17,074,516 | 12,020,164 |
Common stock outstanding (shares) | 17,074,516 | 12,020,164 |
Consolidated statements of oper
Consolidated statements of operations - USD ($) shares in Thousands, $ in Thousands | 12 Months Ended | ||
Dec. 31, 2021 | Dec. 31, 2020 | Dec. 31, 2019 | |
Revenues: | |||
Total revenues | $ 1,394,075 | $ 677,192 | $ 837,281 |
Costs and expenses: | |||
Lease operating expenses | 101,994 | 82,020 | 90,786 |
Production and ad valorem taxes | 68,742 | 33,050 | 40,712 |
General and administrative | 62,801 | 50,534 | 54,729 |
Organizational restructuring expenses | 9,800 | 4,200 | 16,371 |
Depletion, depreciation and amortization | 215,355 | 217,101 | 265,746 |
Impairment expense | 1,613 | 899,039 | 620,889 |
Other operating expenses | 4,233 | 4,430 | 4,118 |
Total costs and expenses | 767,222 | 1,538,925 | 1,245,872 |
Gain on sale of oil and natural gas properties, net | 93,482 | 0 | 0 |
Operating income (loss) | 720,335 | (861,733) | (408,591) |
Non-operating income (expense): | |||
Gain (loss) on derivatives, net | (452,175) | 80,114 | 79,151 |
Interest expense | (113,385) | (105,009) | (61,547) |
Litigation settlement | 0 | 0 | 42,500 |
Gain on extinguishment of debt, net | 0 | 8,989 | 0 |
Loss on disposal of assets, net | (8,931) | (963) | (248) |
Write-off of debt issuance costs | 0 | (1,103) | (935) |
Other income, net | 2,809 | 1,586 | 4,623 |
Total non-operating income (expense), net | (571,682) | (16,386) | 63,544 |
Income (loss) before income taxes | 148,653 | (878,119) | (345,047) |
Income tax (expense) benefit: | |||
Current | (1,324) | 0 | 0 |
Deferred | (2,321) | 3,946 | 2,588 |
Total income tax (expense) benefit | (3,645) | 3,946 | 2,588 |
Net income (loss) | $ 145,008 | $ (874,173) | $ (342,459) |
Net income (loss) per common share: | |||
Basic (USD per share) | $ 10.18 | $ (74.92) | $ (29.61) |
Diluted (USD per share) | $ 10.03 | $ (74.92) | $ (29.61) |
Weighted-average common shares outstanding: | |||
Basic (shares) | 14,240 | 11,668 | 11,565 |
Diluted (shares) | 14,464 | 11,668 | 11,565 |
Oil sales | |||
Revenues: | |||
Total revenues | $ 805,448 | $ 367,792 | $ 572,918 |
NGL sales | |||
Revenues: | |||
Total revenues | 191,591 | 78,246 | 100,330 |
Natural gas sales | |||
Revenues: | |||
Total revenues | 150,104 | 50,317 | 33,300 |
Midstream service revenues | |||
Revenues: | |||
Total revenues | 6,629 | 8,249 | 11,928 |
Costs and expenses: | |||
Costs of goods and services sold | 3,707 | 3,762 | 4,486 |
Sales of purchased oil | |||
Revenues: | |||
Total revenues | 240,303 | 172,588 | 118,805 |
Costs and expenses: | |||
Costs of goods and services sold | 251,061 | 194,862 | 122,638 |
Transportation and marketing expenses | |||
Costs and expenses: | |||
Costs of goods and services sold | $ 47,916 | $ 49,927 | $ 25,397 |
Consolidated statements of stoc
Consolidated statements of stockholders' equity - USD ($) shares in Thousands, $ in Thousands | Total | Common stock | Additional paid-in capital | Treasury stock (at cost) | Accumulated deficit |
Balance at beginning of year (shares) at Dec. 31, 2018 | 11,697 | 0 | |||
Balance at beginning of year at Dec. 31, 2018 | $ 1,174,230 | $ 2,339 | $ 2,375,286 | $ 0 | $ (1,203,395) |
Increase (Decrease) in Stockholders' Equity | |||||
Restricted stock awards (shares) | 381 | ||||
Restricted stock awards | 0 | $ 76 | (76) | ||
Restricted stock forfeitures (shares) | (178) | ||||
Restricted stock forfeitures | 0 | $ (35) | 35 | ||
Stock exchanged for tax withholding (shares) | 35 | ||||
Stock exchanged for tax withholding | (2,657) | $ (2,657) | |||
Stock exchanged for cost of exercise of stock options (shares) | 1 | ||||
Stock exchanged for cost of exercise of stock options | (76) | $ (76) | |||
Retirement of treasury stock (shares) | (36) | (36) | |||
Retirement of treasury stock | 0 | $ (7) | (2,726) | $ 2,733 | |
Exercise of stock options (shares) | 1 | ||||
Exercise of stock options | 76 | 76 | |||
Share-settled equity-based compensation | 12,760 | 12,760 | |||
Net income (loss) | (342,459) | (342,459) | |||
Balance at end of year (shares) at Dec. 31, 2019 | 11,865 | 0 | |||
Balance at end of year at Dec. 31, 2019 | 841,874 | $ 2,373 | 2,385,355 | $ 0 | (1,545,854) |
Increase (Decrease) in Stockholders' Equity | |||||
Reverse stock split | 0 | $ (2,277) | 2,277 | ||
Restricted stock awards (shares) | 238 | ||||
Restricted stock awards | 0 | $ 31 | (31) | ||
Restricted stock forfeitures (shares) | (48) | ||||
Restricted stock forfeitures | 0 | $ (2) | 2 | ||
Stock exchanged for tax withholding (shares) | 35 | ||||
Stock exchanged for tax withholding | (779) | $ (779) | |||
Retirement of treasury stock (shares) | (35) | (35) | |||
Retirement of treasury stock | 0 | $ (5) | (774) | $ 779 | |
Share-settled equity-based compensation | 11,635 | 11,635 | |||
Net income (loss) | (874,173) | (874,173) | |||
Balance at end of year (shares) at Dec. 31, 2020 | 12,020 | 0 | |||
Balance at end of year at Dec. 31, 2020 | (21,443) | $ 120 | 2,398,464 | $ 0 | (2,420,027) |
Increase (Decrease) in Stockholders' Equity | |||||
Restricted stock awards (shares) | 237 | ||||
Restricted stock awards | 0 | $ 2 | (2) | ||
Restricted stock forfeitures (shares) | (42) | ||||
Restricted stock forfeitures | 0 | ||||
Stock exchanged for tax withholding (shares) | 53 | ||||
Stock exchanged for tax withholding | (2,596) | $ (2,596) | |||
Retirement of treasury stock (shares) | (53) | (53) | |||
Retirement of treasury stock | 0 | $ 0 | (2,596) | $ 2,596 | |
Exercise of stock options (shares) | 2 | ||||
Exercise of stock options | 173 | 173 | |||
Share-settled equity-based compensation | 9,258 | 9,258 | |||
Issuance of common stock, net of costs (in shares) | 1,438 | ||||
Issuance of common stock, net of costs | 72,492 | $ 14 | 72,478 | ||
Equity issued for acquisition of oil and natural gas properties (in shares) | 3,467 | ||||
Equity issued for acquisitions of oil and natural gas properties | 310,888 | $ 35 | 310,853 | ||
Performance share conversion (in shares) | 6 | ||||
Net income (loss) | 145,008 | 145,008 | |||
Balance at end of year (shares) at Dec. 31, 2021 | 17,075 | 0 | |||
Balance at end of year at Dec. 31, 2021 | $ 513,780 | $ 171 | $ 2,788,628 | $ 0 | $ (2,275,019) |
Consolidated statements of cash
Consolidated statements of cash flows - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2021 | Dec. 31, 2020 | Dec. 31, 2019 | |
Cash flows from operating activities: | |||
Net income (loss) | $ 145,008 | $ (874,173) | $ (342,459) |
Adjustments to reconcile net income (loss) to net cash provided by operating activities: | |||
Share-settled equity-based compensation, net | 7,675 | 8,217 | 8,290 |
Depletion, depreciation and amortization | 215,355 | 217,101 | 265,746 |
Impairment expense | 1,613 | 899,039 | 620,889 |
Gain on sale of oil and natural gas properties, net | (93,482) | 0 | 0 |
Mark-to-market on derivatives: | |||
(Gain) loss on derivatives, net | 452,175 | (80,114) | (79,151) |
Settlements (paid) received for matured derivatives, net | (320,868) | 228,221 | 63,221 |
Settlements received (paid) for early-terminated commodity derivatives, net | 0 | 6,340 | (5,409) |
Premiums received (paid) for commodity derivatives | 9,041 | (51,070) | (9,063) |
Amortization of debt issuance costs | 5,146 | 4,321 | 3,341 |
Amortization of operating lease right-of-use assets | 13,609 | 13,070 | 14,563 |
Gain on extinguishment of debt, net | 0 | (8,989) | 0 |
Deferred income tax expense (benefit) | 2,321 | (3,946) | (2,588) |
Other, net | 13,564 | 5,332 | 3,887 |
Changes in operating assets and liabilities: | |||
Accounts receivable, net | (87,831) | 21,117 | 8,924 |
Other current assets | (8,767) | 6,275 | (14,059) |
Other noncurrent assets, net | (8,782) | (6,768) | 2,327 |
Accounts payable and accrued liabilities | 31,387 | (2,242) | (28,983) |
Undistributed revenue and royalties | 81,201 | (8,395) | (16,037) |
Other current liabilities | 33,331 | 19,944 | (13,968) |
Other noncurrent liabilities | 4,975 | (9,890) | (4,397) |
Net cash provided by operating activities | 496,671 | 383,390 | 475,074 |
Cash flows from investing activities: | |||
Acquisitions of oil and natural gas properties, net | (763,411) | (35,786) | (199,284) |
Capital expenditures: | |||
Oil and natural gas properties | (418,362) | (347,359) | (458,985) |
Midstream service assets | (2,849) | (3,171) | (7,910) |
Other fixed assets | (5,931) | (4,259) | (2,433) |
Proceeds from dispositions of capital assets, net of selling costs | 393,742 | 1,337 | 6,901 |
Net cash used in investing activities | (796,811) | (389,238) | (661,711) |
Cash flows from financing activities: | |||
Borrowings on Senior Secured Credit Facility | 570,000 | 80,000 | 275,000 |
Payments on Senior Secured Credit Facility | (720,000) | (200,000) | (90,000) |
Extinguishment of debt | 0 | (846,994) | 0 |
Proceeds from issuance of common stock, net of offering costs | 72,492 | 0 | 0 |
Stock exchanged for tax withholding | (2,596) | (779) | (2,657) |
Payments for debt issuance costs | (14,686) | (18,479) | 0 |
Other | 2,971 | 0 | 0 |
Net cash provided by financing activities | 308,181 | 13,748 | 182,343 |
Net increase (decrease) in cash and cash equivalents | 8,041 | 7,900 | (4,294) |
Cash and cash equivalents, beginning of period | 48,757 | 40,857 | 45,151 |
Cash and cash equivalents, end of period | 56,798 | 48,757 | 40,857 |
January 2025 Notes & January 2028 Notes | |||
Cash flows from financing activities: | |||
Issuance of Notes | 0 | 1,000,000 | 0 |
July 2029 Notes | |||
Cash flows from financing activities: | |||
Issuance of Notes | $ 400,000 | $ 0 | $ 0 |
Organization
Organization | 12 Months Ended |
Dec. 31, 2021 | |
Organization, Consolidation and Presentation of Financial Statements [Abstract] | |
Organization | Note 1 Organization |
Basis of presentation and signi
Basis of presentation and significant accounting policies | 12 Months Ended |
Dec. 31, 2021 | |
Accounting Policies [Abstract] | |
Basis of presentation and significant accounting policies | Note 2 Basis of presentation and significant accounting policies a. Basis of presentation The accompanying consolidated financial statements were derived from the historical accounting records of the Company and reflect the historical financial position, results of operations and cash flows for the periods described herein. The accompanying consolidated financial statements have been prepared in accordance with accounting principles generally accepted in the United States of America ("GAAP"). All material intercompany transactions and account balances have been eliminated in the consolidation of accounts. b. Use of estimates in the preparation of consolidated financial statements The preparation of the accompanying consolidated financial statements in conformity with GAAP requires management to make estimates and assumptions about future events. These estimates and the underlying assumptions affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Although management believes these estimates are reasonable, actual results could differ. Significant estimates include, but are not limited to, (i) volumes of the Company's reserves of oil, natural gas liquids ("NGL") and natural gas, (ii) future cash flows from oil and natural gas properties, (iii) depletion, depreciation and amortization, (iv) impairments, (v) asset retirement obligations, (vi) equity-based compensation, (vii) deferred income taxes, (viii) fair values of assets acquired and liabilities assumed in an acquisition, (ix) fair values of derivatives and deferred premiums and (x) contingent assets or liabilities. As fair value is a market-based measurement, it is determined based on the assumptions that would be used by market participants. These estimates and assumptions are based on management's best judgment. Management evaluates its estimates and assumptions on an ongoing basis using historical experience and other factors, including the current economic environment. Such estimates and assumptions are adjusted when facts and circumstances dictate. Illiquid credit markets and volatile equity and energy markets may increase the uncertainty inherent in such estimates and assumptions. Management believes its estimates and assumptions to be reasonable under the circumstances. As future events and their effects cannot be determined with precision, actual values and results could differ from these estimates. Any changes in estimates resulting from future changes in the economic environment will be reflected in the financial statements in future periods. c. Cash and cash equivalents The Company defines cash and cash equivalents to include cash on hand, cash in bank accounts and highly liquid investments with original maturities of three months or less. The Company maintains cash and cash equivalents in bank deposit accounts and money market funds that may not be federally insured. The Company has not experienced any losses in such accounts and believes it is not exposed to any significant credit risk on such accounts. See Note 14 for discussion regarding the Company's exposure to credit risk. d. Accounts receivable The Company sells its produced oil, NGL and natural gas and purchased oil to various customers and participates with other parties in the development and operation of oil and natural gas properties. The Company maintains an allowance for expected credit losses inherent in its accounts receivable portfolio. In establishing the required allowance, management considers significant factors such as historical losses, current receivables aging, the debtors' current ability to pay its obligation to the Company and existing industry and economic data. Account balances are charged off against the allowance after all means of collection have been exhausted and the potential for recovery is remote, and payments subsequently received on such balances are credited to the allowance. See Note 14 for discussion regarding the Company's exposure to credit risk. Accounts receivable consisted of the following components as of the dates presented: (in thousands) December 31, 2021 December 31, 2020 Oil, NGL and natural gas sales (1) $ 135,560 $ 46,714 Joint operations, net (2) 11,491 2,753 Sales of purchased oil and other products 4,756 5,083 Derivatives and other — 9,426 Total accounts receivable, net $ 151,807 $ 63,976 _____________________________________________________________________________ (1) For purchasers that the Company has netting arrangements with, the amounts presented include the net positions. (2) Accounts receivable for joint operations are presented net of an allowance for expected credit losses of $0.4 million as of both December 31, 2021 and 2020. As the operator of the majority of its wells, the Company has the ability to realize some or all of these receivables through the netting of revenues. e. Derivatives Derivatives are recorded at fair value and are presented on a net basis in "Derivatives" on the consolidated balance sheets as assets and/or liabilities. The Company records the fair value of derivatives, net by counterparty where the right of offset exists. The Company determines the fair value of its derivatives using fair value hierarchy level inputs to its valuation techniques. The Company's derivatives were not designated as hedges for accounting purposes, and the Company does not enter into such instruments for speculative trading purposes. Accordingly, the changes in fair value are recognized in "Gain (loss) on derivatives, net" under "Non-operating income (expense)" on the consolidated statements of operations. See Notes 10 and 11.a for additional discussion of derivatives and their fair value measurement on a recurring basis, respectively. f. Other current assets and liabilities Other current assets consisted of the following components as of the dates presented: (in thousands) December 31, 2021 December 31, 2020 Prepaid expenses and other $ 12,746 $ 12,768 Inventory (1) 10,160 3,196 Total other current assets $ 22,906 $ 15,964 ______________________________________________________________________________ (1) See Note 2.i for discussion of the Company's types of inventory. Other current liabilities consisted of the following components as of the dates presented: (in thousands) December 31, 2021 December 31, 2020 Accrued interest payable $ 56,468 $ 42,401 Accrued compensation and benefits 14,434 16,687 Other accrued liabilities 28,569 3,678 Total other current liabilities $ 99,471 $ 62,766 g. Oil and natural gas properties The Company uses the full cost method of accounting for its oil and natural gas properties. Under this method, all acquisition, exploration and development costs, including certain employee-related costs, incurred for the purpose of acquiring, exploring for or developing oil and natural gas properties, are capitalized and, once evaluated, depleted on a composite unit-of-production method based on estimates of proved oil, NGL and natural gas reserves. The depletion base includes estimated future development costs and dismantlement, restoration and abandonment costs, net of estimated salvage values. Capitalized costs include the cost of drilling and equipping productive wells, dry hole costs, lease acquisition costs, delay rentals and other costs related to such activities. Costs, including employee-related costs, associated with production and general corporate activities are expensed in the period incurred. The Company excludes unevaluated property acquisition costs and exploration costs from the depletion calculation until it is determined whether or not proved reserves can be assigned to the properties. The Company capitalizes a portion of its interest costs to its unevaluated properties and such costs become subject to depletion when proved reserves can be assigned to the associated properties. All items classified as unevaluated properties are assessed on a quarterly basis for possible impairment. The assessment includes consideration of the following factors, among others: intent to drill, remaining lease term, geological and geophysical evaluations, drilling results and activity, the assignment of proved reserves and the economic viability of development if proved reserves are assigned. During any period in which these factors indicate an impairment, the cumulative drilling incurred capital expenditures to date for such property and all or a portion of the associated leasehold costs are transferred to the full cost pool and are then subject to depletion. Sales of oil and natural gas properties, whether or not being depleted currently, are accounted for as adjustments of capitalized costs, with no gain or loss recognized, unless such adjustments would significantly alter the relationship between capitalized costs and proved reserves of oil, NGL and natural gas. See Note 4.a for discussion of the Company's sale of oil and natural gas properties and the resulting gain recognized during the year ended December 31, 2021. See Note 6 for additional discussion of the Company's oil and natural gas properties and other property and equipment. h. Leases The Company recognizes operating lease right-of-use assets and operating lease liabilities on the consolidated balance sheets for operating leases with an initial term greater than 12 months. The Company determines whether a contract is or contains a lease at inception of the contract, based on answers to a series of questions that address whether an identified asset exists and whether the Company has the right to obtain substantially all of the benefit of the asset and to control its use over the full term of the agreement. When available, the Company uses the rate implicit in the lease to discount lease payments to present value; however, most of the Company's leases do not provide a readily determinable implicit rate. In such cases, the Company is required to use its incremental borrowing rate ("IBR"). The Company determines its IBR using both a "credit notching" approach and a "recovery method" approach. The results of these approaches are then weighted equally and averaged in order to determine the concluded IBR. This concluded IBR is utilized to discount the lease payments based on information available at lease commencement. There are no material residual value guarantees, nor any restrictions or covenants included in the Company's lease agreements. Mineral leases, including oil and natural gas leases granting the right to explore for those natural resources and rights to use the land in which those natural resources are contained, are not included in the scope of Accounting Standards Codification ("ASC") 842, Leases . The Company has recognized operating lease right-of-use assets and operating lease liabilities on the consolidated balance sheets for leases of commercial real estate with lease terms extending into 2027 and drilling, completion, production and other equipment leases with lease terms extending into 2022. The Company has various other drilling, completion and production equipment leases on a short-term basis which are reflected in short-term lease costs. The Company's lease costs include those that are recognized in net income (loss) during the period and capitalized as part of the cost of another asset in accordance with other GAAP. The lease costs related to drilling, completion and production activities are reflected at the Company's net ownership, which is consistent with the principals of proportional consolidation, and lease commitments are reflected on a gross basis. As of December 31, 2021, the Company had an average working interest of 96% in wells associated with Laredo's active drilling program over the next 12 months. Certain of the Company's leases include provisions for variable payments. These variable payments are typically determined based on a measure of throughput, actual days or another measure of usage. For our drilling rigs, the variable lease costs include the payments that depend on the performance or usage of the underlying asset, the costs to move and the costs to repair the drilling rigs. For certain of our commercial office buildings, utilities and common area, the variable lease costs are the variable maintenance charges. For our equipment leases, the variable lease costs are the amounts incurred under our contracts that are beyond the minimum rental fee, inclusive of maintenance. The Company subleases certain office space to third parties but remains the primary obligor under the head lease. The lease terms on those subleases each contain renewal options that do not extend past the term of the head lease. The subleases do not contain residual value guarantees. Sublease income is recognized based on the contract terms and is included as a reduction of lease expense under the head lease. Certain of the Company's operating lease right-of-use asset classes include options to renew on a month-to-month basis. The Company considers contract-based, asset-based, market-based and entity-based factors to determine the term over which it is reasonably certain to extend the lease in determining its right-of-use assets and liabilities. The Company's material leases do not include options to purchase the leased property. See Note 5 for further discussion of the Company's leases. i. Inventory The Company has the following types of inventory: (i) materials and supplies inventory used in production activities of oil and natural gas properties and midstream service assets, (ii) frac pit water inventory used in developing oil and natural gas properties and (iii) line-fill in third-party pipelines, which is the minimum volume of product in a pipeline system that enables the system to operate, and is generally not available to be withdrawn from the pipeline until the expiration of the transportation contract. All inventory is carried at the lower of cost or net realizable value ("NRV"), with cost determined using the weighted-average cost method, and is included in "Other current assets" and "Other noncurrent assets, net" on the consolidated balance sheets. The NRV for materials and supplies inventory and frac pit water inventory is estimated utilizing a replacement cost approach (Level 2). The NRV for line-fill in third-party pipelines is estimated utilizing a quoted market price adjusted for regional price differentials (Level 2). See Note 11.b for discussion of the Company's inventory impairments. j. Debt issuance costs Debt issuance costs, which are recorded at cost, net of amortization, are amortized over the life of the respective debt agreements utilizing the straight-line method. See Note 7.e for additional discussion of the Company's debt issuance costs. k. Asset retirement obligations Asset retirement obligations associated with the retirement of tangible long-lived assets are recognized as a liability in the period in which they are incurred and become determinable. The associated asset retirement costs are part of the carrying amount of the long-lived asset. Subsequently, the asset retirement cost included in the carrying amount of the related long-lived asset is expensed through depletion, or for midstream service assets through depreciation. Changes in the liability due to the passage of time are recognized as an increase in the carrying amount of the liability and accretion expense. The fair value of additions to the asset retirement obligation liability is measured using valuation techniques consistent with the income approach, which converts future cash flows into a single discounted amount. Significant inputs to the valuation include: (i) estimated plug and abandonment or removal and remediation cost per well or midstream service asset based on Company experience, if any, in accordance with applicable state laws, (ii) estimated remaining life per well or midstream service asset, (iii) future inflation factors and (iv) the Company's average credit-adjusted risk-free rate. Inherent in the fair value calculation of asset retirement obligations are numerous assumptions and judgments including, in addition to those noted above, the ultimate settlement of these amounts, the ultimate timing of such settlement and changes in technology, regulatory, political, environmental, safety and public relations matters. To the extent future revisions to these assumptions impact the fair value of the existing asset retirement obligation liability, an adjustment will be made to the asset balance. The Company is obligated by contractual and regulatory requirements to remove certain midstream service assets and perform other remediation of the sites where such midstream service assets are located upon the retirement of those assets. However, the fair value of the asset retirement obligation cannot currently be reasonably estimated because the settlement dates are indeterminate. The Company will record an asset retirement obligation for midstream service assets in the periods in which settlement dates are reasonably determinable. The following table reconciles the Company's asset retirement obligation liability associated with tangible long-lived assets for the periods presented: Years ended December 31, (in thousands) 2021 2020 Liability at beginning of year $ 68,326 $ 62,718 Liabilities added due to acquisitions, drilling, midstream service asset construction and other 14,610 2,252 Accretion expense (1) 4,233 4,430 Liabilities settled due to plugging and abandonment or removed due to sale (15,186) (1,074) Revision of estimates 20 — Liability at end of year $ 72,003 $ 68,326 ______________________________________________________________________________ (1) Accretion expense is included in "Other operating expenses" on the consolidated statements of operations. l. Fair value measurements The carrying amounts reported on the consolidated balance sheets for cash and cash equivalents, accounts receivable, accounts payable, accrued capital expenditures, undistributed revenue and royalties and other accrued assets and liabilities approximate their fair values. See Note 2.i for the fair value assumptions used in estimating the NRV of inventory, which is used to determine the necessity for any inventory impairment. See Note 4 for the fair value assumptions used in estimating the fair values of assets acquired and liabilities assumed in the Company's acquisitions. See Note 11 for further discussion of fair value measurements. m. Treasury stock Treasury stock is recorded at cost, which includes incremental direct transaction costs, and is retired upon acquisition as a result of (i) stock exchanged to satisfy tax withholding that arises upon the lapse of restrictions on share-settled equity-based awards at the awardee's election or (ii) stock exchanged for the cost of exercise of stock options at the awardee's election. n. Revenue recognition Oil, NGL and natural gas sales and sales of purchased oil are generally recognized at the point in time that control of the product is transferred to the customer. Midstream service revenues are recognized over time as the customer benefits from services when provided. Oil sales and sales of purchased oil Under its oil sales contracts, the Company sells produced or purchased oil at the delivery point specified in the contract and collects an agreed-upon index price, net of pricing differentials. The delivery point may be at the wellhead, the inlet of the purchaser's pipeline or nominated pipeline or the Company's truck unloading facility. At the delivery point, the purchaser typically takes custody, title and risk of loss of the product and, therefore, control as defined under ASC 606, Revenue from Contracts with Customers , typically passes at the delivery point. The Company recognizes revenue at the net price received when control transfers to the purchaser. The Company engages in transactions in which it sells oil at the lease and subsequently repurchases the same volume of oil from that customer at a downstream delivery point under a separate agreement ("Repurchase Agreement") for use in the sale to the final customer. The commercial reasoning for such transactions may vary. Where a Repurchase Agreement exists, the Company must evaluate whether the customer obtains control of the oil at the lease and therefore whether it is appropriate to recognize revenue for the lease sale. Where the Company has an obligation or a right to repurchase the oil, the customer does not obtain control of the oil because it is limited in its ability to direct the use of, and obtain substantially all of the remaining benefits from the oil even though it may have physical possession of the oil. If the Company repurchases the oil for less than the original selling price, such a transaction will be classified as a lease. If the Company repurchases the oil for equal to or more than the original selling price, then the transaction represents a financing arrangement unless there is only a short passage of time between the sale and repurchase, in which case any excess amount paid represents an expense associated with the sale of oil to the final customer. The Company recognizes such repurchase expense and any transportation expenses incurred for the delivery of the oil to the final customer in the "Transportation and marketing expenses" line item in the accompanying consolidated statements of operations. In certain situations, the Company enters into purchase and sale transactions of oil inventory with the same counterparty in contemplation with one another, and these transactions are presented on the consolidated statements of operations on a net basis in accordance with ASC 845, Nonmonetary Transactions . The following table presents the net effect of these transactions for the periods presented: Years ended December 31, (in thousands) 2021 2020 2019 Sales of purchased oil inventory $ 327,839 $ 17,026 $ — Purchased oil inventory 326,625 16,918 — Net effect on earnings (1) $ 1,214 $ 108 $ — ______________________________________________________________________________ (1) Amounts presented are recorded in "Sales of purchased oil" in the consolidated statements of operations. Under certain of its customer contracts, the Company is subject to contractual penalties if it fails to deliver contractual minimum volumes to its customers. Such amounts are recorded as a reduction to the transaction price as these amounts do not represent payments to the customer for distinct goods or services and instead relate specifically to the failure to perform under the specific customer contract. Such amounts are recorded as a reduction to the transaction price when payment is determined as probable, typically when such a deficiency occurs. NGL and natural gas sales Under its natural gas processing contracts, the Company delivers produced natural gas to a midstream processing entity at the wellhead or the inlet of the processing entity's system. The processing entity processes the natural gas, sells the resulting NGL and residue gas to third parties and pays the Company for the NGL and residue gas with deductions that may include gathering, compression, processing and transportation fees. In these scenarios, the Company evaluates whether it is the principal or the agent in the transaction. For existing contracts, the Company has concluded that it is the agent in the ultimate sale to the third party and the midstream processing entity is the principal and that the Company has transferred control of unprocessed natural gas to the midstream processing entity; therefore, the Company recognizes revenue based on the net amount of the proceeds received from the midstream processing entity who represents the Company's customer. If for future contracts the Company was to conclude that it was the principal with the ultimate third party being the customer, the Company would recognize revenue for those contracts on a gross basis, with gathering, compression, processing, and transportation fees presented as an expense. Midstream service revenues Revenue from oil throughput agreements is recognized based on a rate per barrel for volumes transported. Under the Company's oil throughput agreements, a volumetric deduction is taken from customer oil as a pipeline loss allowance. While these amounts represent non-cash consideration under ASC 606, such deductions are immaterial. Revenue from natural gas throughput agreements is recognized based on a rate per MMbtu for volumes transported. Revenue from water delivery, recycling and takeaway is recognized based on the volumes of water for which the services are provided at the applicable contractual rate. Imbalances The Company recognizes revenue for all oil, NGL and natural gas sold to purchasers regardless of whether the sales are proportionate to the Company's ownership interest in the property. Production imbalances are recognized as a liability to the extent an imbalance on a specific property exceeds the Company's share of remaining proved oil, NGL and natural gas reserves. The Company is also subject to natural gas pipeline imbalances, which are recorded as accounts receivable or payable at values consistent with contractual arrangements with the owner of the pipeline. The Company did not have any producer or pipeline imbalance positions as of December 31, 2021 or 2020. Significant judgments The Company engages in various types of transactions in which unaffiliated midstream entities process the Company's liquids-rich natural gas and, in some scenarios, subsequently market resulting NGL and residue gas to third-party customers on the Company's behalf. These types of transactions require judgment to determine whether the Company is the principal or the agent in the contract and, as a result, whether revenues are recorded gross or net. For existing contracts, the Company has determined that it serves as the agent in the sale of products under certain natural gas processing and marketing agreements with unaffiliated midstream entities in accordance with the control model in ASC 606, Revenue from Contracts with Customers . As a result, the Company presents revenue on a net basis for amounts expected to be received from third-party customers through the marketing process, with expenses and deductions incurred subsequent to control of the product(s) transferring to the unaffiliated midstream entity being netted against revenue. Transaction price allocated to remaining performance obligations A significant number of the Company's product sales are short-term in nature with a contract term of one year or less. For those contracts, the Company has utilized the practical expedient in ASC 606-10-50-14 that exempts the Company from disclosure of the transaction price allocated to remaining performance obligations if the performance obligation is part of a contract that has an original expected duration of one year or less. For the Company's product sales that have a contract term greater than one year and for its Midstream Services, the Company has utilized the practical expedient in ASC 606-10-50-14A that states that it is not required to disclose the transaction price allocated to remaining performance obligations if the variable consideration is allocated entirely to a wholly unsatisfied performance obligation. Under the Company's product sales contracts, each unit of product generally represents a separate performance obligation; therefore, future volumes are wholly unsatisfied. Under the Midstream Services contracts each unit of service represents a separate performance obligation and therefore performance obligations in respect of future services are wholly unsatisfied. Contract balances Under the Company's customer contracts, invoicing occurs once the Company's performance obligations have been satisfied, at which point payment is unconditional. Accordingly, the Company's contracts do not give rise to contract assets or liabilities under ASC 606, Revenue from Contracts with Customers . Prior-period performance obligations For sales of oil, NGL, natural gas and purchased oil, the Company records revenue in the month production is delivered to the purchaser. However, settlement statements and payment may not be received for 30 to 90 days after the date production is delivered and, as a result, the Company is required to estimate the amount of production that was delivered to the purchaser and the price that will be received for the sale of the product. The Company records the differences between estimates and the actual amounts received for product sales once payment is received from the purchaser. Such differences have historically not been significant. The Company uses knowledge of its properties, its properties' historical performance, spot market prices and other factors as the basis for these estimates. For the years ended December 31, 2021, 2020 and 2019, revenue recognized related to performance obligations satisfied in prior reporting periods was not material. o. Fees received for the operation of jointly-owned oil and natural gas properties The Company receives fees for the operation of jointly-owned oil and natural gas properties and records such reimbursements as a reduction of general and administrative expenses. The following table presents the fees received for the operation of jointly-owned oil and natural gas properties for the periods presented: Years ended December 31, (in thousands) 2021 2020 2019 Fees received for the operation of jointly-owned oil and natural gas properties $ 876 $ 464 $ 468 p. Equity-based compensation awards Equity-based compensation expense is included in "General and administrative" on the consolidated statements of operations, and includes expense for (i) restricted stock awards, stock option awards, performance share awards and the outperformance share award, which are accounted for as equity awards and are generally based on the awards' grant date or modification date fair value less an expected forfeiture rate and (ii) performance unit awards and phantom unit awards, which are accounted for as liability awards and are re-measured at each quarterly reporting period until settlement. The Company capitalizes a portion of equity-based compensation for employees who are directly involved in the acquisition, exploration and development of its oil and natural gas properties into the full cost pool. Capitalized equity-based compensation is included in "Evaluated properties" on the consolidated balance sheets. See Note 9.a for further discussion of the Company's Equity Incentive Plan. q. Income taxes Income taxes are accounted for under the asset and liability method. Deferred tax assets and liabilities are recognized for the future tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax bases and operating losses and tax credit carryforwards. Under this method, deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which those temporary differences are expected to be recovered or settled. The effect on deferred tax assets and liabilities of a change in tax rates is recognized in income (loss) in the period that includes the enactment date. The Company evaluates uncertain tax positions for recognition and measurement in the consolidated financial statements. To recognize a tax position, the Company determines whether it is more likely than not that the tax position will be sustained upon examination, including resolution of any related appeals or litigation, based on the technical merits of the position. A tax position that meets the more-likely-than-not threshold is measured to determine the amount of benefit to be recognized in the consolidated financial statements. The amount of tax benefit recognized with respect to any tax position is measured as the largest amount of benefit that is greater than 50 percent likely of being realized upon settlement. The Company has no unrecognized tax benefits related to uncertain tax positions in the consolidated financial statements at December 31, 2021 or 2020. See Note 13 for additional information regarding the Company's income taxes. r. Supplemental cash flow and non-cash information The following table presents supplemental cash flow and non-cash information for the periods presented: Years ended December 31, (in thousands) 2021 2020 2019 Supplemental cash flow information: Cash paid for interest, net of $5,866, $3,019 and $805 of capitalized in |
New accounting standards
New accounting standards | 12 Months Ended |
Dec. 31, 2021 | |
Accounting Standards Update and Change in Accounting Principle [Abstract] | |
New accounting standards | Note 3 New accounting standards The Company considered the applicability and impact of all accounting standard updates ("ASU") issued by the Financial Accounting Standards Board ("FASB") to the Accounting Standards Codification ("ASC") and has determined there are no ASUs that are not yet adopted and meaningful to disclose as of December 31, 2021. Additionally, the Company did not adopt any new ASUs during the year ended December 31, 2021. |
Acquisitions and divestitures
Acquisitions and divestitures | 12 Months Ended |
Dec. 31, 2021 | |
Business Combination and Asset Acquisition [Abstract] | |
Acquisitions and divestitures | Note 4 Acquisitions and divestitures a. 2021 Asset acquisitions and divestiture Pioneer Acquisition On September 17, 2021, the Company entered into a purchase and sale agreement (the "Pioneer PSA") with Pioneer Natural Resources USA, Inc ("PXD"), DE Midland III, LLC ("DEM"), Parsley Minerals, LLC ("PM") and Parsley Energy, L.P. ("PE" and collectively with PXD, DEM, and PM, "the Seller") pursuant to which the Company agreed to purchase (the "Pioneer Acquisition"), effective as of July 1, 2021, certain oil and natural gas properties in the Midland Basin, including approximately 20,000 net acres, and approximately 135 gross (121 net) operated locations, located in western Glasscock County, Texas, as well as related assets and contracts (the "Pioneer Assets"). On October 18, 2021 ("Pioneer Closing Date"), the Company closed the Pioneer Acquisition for an aggregate purchase price of $205.6 million, comprised of (i) $131.6 million in cash, (ii) 959,691 shares of the Company's common stock, par value $0.01 per share (the "common stock"), based upon the share price as of the Pioneer Closing Date and (iii) $3.0 million in transaction related expenses, inclusive of customary closing adjustments, subject to post-closing adjustments. The Company determined that the Pioneer Acquisition was an asset acquisition, as substantially all of the gross assets acquired are concentrated in a group of similar identifiable assets. Accordingly, the consideration paid was allocated to the individual assets acquired and liabilities assumed based on their relative fair values and all transaction costs associated were capitalized. The following table presents components of the purchase price, inclusive of customary closing adjustments: (in thousands, except for share and share price data) As of October 18, 2021 Shares of Company common stock 959,691 Company common stock price at the Pioneer Closing Date $ 73.90 Value of Company common stock consideration $ 70,921 Cash consideration $ 131,633 Transaction costs 3,013 Total purchase price $ 205,567 The following table presents the allocation of the purchase price to the assets acquired and liabilities assumed, based on their relative fair values, on the Pioneer Closing Date: (in thousands) As of October 18, 2021 Evaluated properties $ 139,360 Unevaluated properties 73,929 Revenue suspense liabilities assumed (7,722) Allocated purchase price $ 205,567 The Company funded the cash portion of the aggregate purchase price and related transaction costs with respect to the Pioneer Acquisition with cash on hand and borrowings under its Senior Secured Credit Facility. During the year ended December 31, 2021, in connection with the Pioneer Acquisition, the Company acquired additional interests in the Pioneer Assets through additional sellers that exercised their "tag-along" sales rights, for total cash consideration of $2.9 million, excluding customary purchase price adjustments. These acquisitions were accounted for as asset acquisitions. Sabalo/Shad Acquisition On May 7, 2021, the Company entered into two separate purchase and sale agreements, one (the "Sabalo PSA") with Sabalo Energy, LLC and its subsidiary, Sabalo Operating, LLC (collectively, "Sabalo"), and the other (the "Shad PSA" and together with the Sabalo PSA, the "Sabalo/Shad PSAs") with Shad Permian, LLC ("Shad") to acquire certain Midland Basin oil and natural gas properties, including approximately 21,000 net acres and approximately 120 gross (109 net) operated locations and approximately 150 gross (18 net) non-operated locations, located in Howard and Borden Counties, Texas, (collectively, the "Sabalo/Shad Acquisition"). Sabalo and Shad are unaffiliated, but owned interest in the same assets. On July 1, 2021 ("Sabalo/Shad Closing Date"), the Company closed the Sabalo/Shad Acquisition, effective April 1, 2021, for an aggregate purchase price of $863.1 million, comprised of (i) $606.1 million in cash (ii) 2,506,964 shares of the Company's common stock, based upon the share price as of the Sabalo/Shad Closing Date, and (iii) $17.0 million in transaction related expenses, inclusive of customary closing adjustments, subject to post-closing adjustments. The Sabalo/Shad Acquisition was accounted for as a single transaction because the Sabalo PSA and Shad PSA were entered into at the same time and in contemplation of one another to form a single transaction designed to achieve an overall economic effect. The Company determined that the Sabalo/Shad Acquisition was an asset acquisition, as substantially all of the gross assets acquired are concentrated in a group of similar identifiable assets. Accordingly, the consideration paid was allocated to the individual assets acquired and liabilities assumed based on their relative fair values and all transaction costs associated were capitalized. The following table presents components of the purchase price, inclusive of customary closing adjustments: (in thousands, except for share and share price data) As of July 1, 2021 Shares of Company common stock 2,506,964 Company common stock price at the Sabalo/Shad Closing Date $ 95.72 Value of Company common stock consideration $ 239,967 Cash consideration $ 606,126 Transaction costs 17,020 Total purchase price $ 863,113 The following table presents the allocation of the purchase price to the assets acquired and liabilities assumed, based on their relative fair values, on the Sabalo/Shad Closing Date: (in thousands) As of July 1, 2021 Evaluated properties $ 503,005 Unevaluated properties 362,977 Revenue suspense liabilities assumed (4,269) Inventory 1,400 Allocated purchase price $ 863,113 The Company funded the cash portion of the aggregate purchase price and related transaction costs with respect to the Sabalo/Shad Acquisition with proceeds from borrowings under its Senior Secured Credit Facility (as defined below) and the Working Interest Sale described below. Working Interest Sale On May 7, 2021, the Company entered into a purchase and sale agreement (the "Sixth Street PSA") with Piper Investments Holdings, LLC, an affiliate of Sixth Street Partners, LLC ("Sixth Street"), to sell 37.5% of the Company's working interest in certain producing wellbores and the related properties primarily located within Glasscock and Reagan Counties, Texas, subject to certain excluded assets and title diligence procedures (the "Working Interest Sale"). On July 1, 2021 (the "Sixth Street Closing Date") the Company closed the Working Interest Sale for cash proceeds of $405.0 million. In addition to such proceeds, the Sixth Street PSA also provided the Company with the right to receive up to a maximum of $93.7 million in additional cash consideration if certain cash flow targets related to divested oil and natural gas property operations are met ("Sixth Street Contingent Consideration"). The Sixth Street Contingent Consideration is made up of quarterly payments through June 2027 totaling up to $38.7 million and a potential balloon payment of $55.0 million in June 2027. On the Sixth Street Closing Date, the fair value of the Sixth Street Contingent Consideration was determined to be $33.8 million. The Sixth Street Contingent Consideration is accounted for as a contingent consideration derivative, with all gains and losses as a result of changes in the fair value of the contingent consideration derivative recognized in earnings in the period in which the changes occur. See Notes 10.c and 11.a for further discussion of the Sixth Street Contingent Consideration. Subsequent to the Sixth Street Closing Date, the Company continues to own and operate its remaining working interest in the properties sold to Sixth Street; however, the results of operations and cash flows related to the 37.5% working interests sold were eliminated from the Company's financial statements. This divestiture did not represent a strategic shift and will not have a major effect on the Company's future operations or financial results. Pursuant to the rules governing full cost accounting, the Company recorded a gain on the Working Interest Sale of $93.5 million, net of transaction expenses of $11.6 million, on the Company's consolidated statements of operations, subject to post-closing adjustments, as this divestment represented more than 25% of the Company's June 30, 2021 proved reserves. For the purposes of calculating the gain, total capitalized costs were allocated between reserves sold and reserves retained as of the Sixth Street Closing Date. Leasehold acquisitions During the year ended December 31, 2021, the Company acquired certain oil and natural gas leasehold interests in Howard County, Texas, totaling approximately 455 net acres for an aggregate purchase price of $4.0 million. b. 2020 Asset acquisitions On October 16, 2020 and November 16, 2020, the Company closed a bolt-on acquisition of 2,758 and 80 net acres, respectively, including production of 210 BOE/D, in Howard County, Texas for an aggregate purchase price of $11.6 million, subject to customary post-closing purchase price adjustments. On April 30, 2020, the Company closed an acquisition of 180 net acres in Howard County, Texas for $0.6 million. The acquisition also provides for one or more potential contingent payments to be paid by the Company if the arithmetic average of the monthly settlement WTI NYMEX prices exceed certain thresholds for the contingency period beginning on January 1, 2021 and ending on the earlier of December 31, 2022 or the date the counterparty has received the maximum consideration of $1.2 million. The fair value of this contingent consideration was $0.2 million as of the acquisition date, which was recorded as part of the basis in the oil and natural gas properties acquired and as a contingent consideration derivative liability. See Notes 10.c and 11.a for additional discussion of this contingent consideration. On February 4, 2020, the Company closed a transaction for $22.5 million, acquiring 1,180 net acres and divesting 80 net acres in Howard County, Texas. All transaction costs were capitalized and are included in "Oil and natural gas properties, net" on the consolidated balance sheet. c. 2020 Divestiture On April 9, 2020, the Company closed a divestiture of 80 net acres and working interests in two producing wells in Glasscock County, Texas for $0.7 million, net of customary post-closing sales price adjustments. The divestiture was recorded as an adjustment to oil and natural gas properties pursuant to the rules governing full cost accounting. Effective at closing, the operations and cash flows of these oil and natural gas properties were eliminated from the ongoing operations of the Company, and the Company has no continuing involvement in the properties. This divestiture did not represent a strategic shift and has not had a major effect on the Company's future operations or financial results. d. 2019 Acquisitions Asset acquisitions On December 12, 2019, the Company closed an acquisition of 7,360 net acres and 750 net royalty acres in Howard County, Texas for $131.7 million, net of customary closing purchase price adjustments. The acquisition provided for a potential contingent payment, where the Company was required to pay $20 million if the arithmetic average of the monthly settlement WTI NYMEX prices for each consecutive calendar month for the one-year period beginning January 1, 2020 through December 31, 2020 exceeded a certain threshold. The fair value of this contingent consideration was $6.2 million as of the acquisition date, which was recorded as part of the basis in the oil and natural gas properties acquired and as a contingent consideration derivative liability. See Notes 10.c and 11.a for additional discussion of this contingent consideration. This acquisition was primarily financed through borrowings under the Senior Secured Credit Facility. Post-closing was finalized during the year ended December 31, 2020. On June 20, 2019, the Company acquired 640 net acres in Reagan County, Texas for $2.9 million. All transaction costs were capitalized and are included in "Oil and natural gas properties, net" on the consolidated balance sheet. Business combination On December 6, 2019, the Company closed a bolt-on acquisition of 4,475 contiguous net acres and working interests in 49 producing wells in western Glasscock County, Texas, which included net production of 1,400 BOE/D at the time of acquisition, for $64.6 million, net of customary closing purchase price adjustments. This acquisition was financed through borrowings under the Senior Secured Credit Facility. Post-closing was finalized during the year ended December 31, 2020. This acquisition was accounted for as a business combination. Accordingly, the Company conducted assessments of net assets acquired and recognized amounts for identifiable assets acquired and liabilities assumed at the estimated acquisition date fair values, while transaction costs associated with the acquisition were expensed. The Company makes various assumptions in estimating the fair values of assets acquired and liabilities assumed. The most significant assumptions relate to the estimated fair values of evaluated and unevaluated oil and natural gas properties. The fair values of these properties were measured using a discounted cash flow model that converts future cash flows to a single discounted amount. Significant inputs to the valuation include estimates of: (i) forecasted oil, NGL and natural gas reserve quantities; (ii) future commodity strip prices as of the closing dates adjusted for transportation and regional price differentials; (iii) forecasted ad valorem taxes, production taxes, income taxes, operating expenses and development costs; and (iv) a peer group weighted-average cost of capital rate subject to additional project-specific risk factors. To compensate for the inherent risk of estimating the value of the unevaluated properties, the discounted future net cash flows of proved undeveloped and probable reserves are reduced by additional reserve adjustment factors. These assumptions represent Level 3 inputs under the fair value hierarchy, as described in Note 11. The following table reflects an aggregate of the final estimate of the fair values of the assets acquired and liabilities assumed in this business combination on December 6, 2019: (in thousands) Fair values of acquisition Fair values of net assets: Evaluated oil and natural gas properties $ 29,921 Unevaluated oil and natural gas properties 34,700 Asset retirement cost 2,728 Total assets acquired $ 67,349 Asset retirement obligations (2,728) Net assets acquired $ 64,621 Fair values of consideration paid for net assets: Cash consideration $ 64,621 e. Exchange of unevaluated oil and natural gas properties From time to time, the Company exchanges undeveloped acreage with third parties. The exchanges are recorded at fair value and the difference is accounted for as an adjustment of capitalized costs with no gain or loss recognized pursuant to the rules governing full cost accounting, unless such adjustment would significantly alter the relationship between capitalized costs and proved reserves of oil, NGL and natural gas. |
Leases
Leases | 12 Months Ended |
Dec. 31, 2021 | |
Leases [Abstract] | |
Leases | Note 5 Leases See Note 2.h for discussion of the Company's significant accounting policies for oil and natural gas properties. a. Lease costs The following table presents components of total lease costs, net for the periods presented: Years ended December 31, (in thousands) 2021 2020 Operating lease costs (1) $ 15,894 $ 15,094 Short-term lease costs (2) 83,471 82,576 Variable lease costs (3) 6,873 10,218 Sublease income (1,057) (1,032) Total lease costs, net $ 105,181 $ 106,856 _____________________________________________________________________________ (1) Amounts represent straight-line costs associated with the Company's operating lease right-of-use assets. (2) Amounts include costs associated with the Company's short-term leases that are not included in the calculation of lease liabilities and right-of-use assets and, therefore, are not recorded on the consolidated balance sheets as such. (3) Amounts are primarily comprised of the non-lease service component of drilling rig commitments above the minimum required payments, and are not included in the calculation of lease liabilities and right-of-use assets. Both the minimum required payments and the non-lease service component of the drilling rig commitments are capitalized as additions to oil and natural gas properties. b. Operating leases Supplemental cash flow information The following table presents cash paid for amounts included in the measurement of operating lease liabilities, which may not agree to operating lease costs due to timing of cash payments and incurred capital expenditures for the periods presented: Years ended December 31, (in thousands) 2021 2020 Operating cash flows from operating leases $ 4,065 $ 5,910 Investing cash flows from operating leases (1) $ 12,569 $ 9,425 _____________________________________________________________________________ (1) Amounts associated with drilling operations are capitalized as additions to oil and natural gas properties. Lease terms and discount rates The following table presents the weighted-average remaining lease term and weighted-average discount rate for operating leases as of the dates presented: December 31, 2021 December 31, 2020 Weighted-average remaining lease term 2.80 years 2.87 years Weighted-average discount rate 7.41 % 7.72 % Maturities The following table reconciles the undiscounted cash flows for recognized operating lease liabilities for each of the first five years and the total remaining years to the operating lease liabilities recorded on the consolidated balance sheet as of the date presented: (in thousands) December 31, 2021 2022 $ 8,399 2023 1,925 2024 1,428 2025 1,423 2026 1,348 Thereafter 666 Total minimum lease payments 15,189 Less: lease liability expense (1,721) Present value of future minimum lease payments 13,468 Less: current operating lease liabilities (7,742) Noncurrent operating lease liabilities $ 5,726 Other information See Note 2.r for disclosure of supplemental non-cash adjustments information related to operating leases. |
Property and equipment
Property and equipment | 12 Months Ended |
Dec. 31, 2021 | |
Property, Plant and Equipment [Abstract] | |
Property and equipment | Note 6 Property and equipment a. Oil and natural gas properties See Note 2.g for discussion of the Company's significant accounting policies for oil and natural gas properties. The following table presents capitalized employee-related incurred capital expenditures in the acquisition, exploration and development of oil and natural gas properties for the periods presented: Years ended December 31, (in thousands) 2021 2020 2019 Capitalized employee-related costs $ 18,225 $ 18,954 $ 18,299 See Note 19.a for total incurred capital expenditures in the acquisition, exploration and development of oil and natural gas properties, which includes the aforementioned capitalized employee-related costs. The following table presents depletion expense, which is included in "Depletion, depreciation and amortization" on the consolidated statements of operations, and depletion expense per BOE sold of evaluated oil and natural gas properties for the periods presented: Years ended December 31, (in thousands except per BOE data) 2021 2020 2019 Depletion expense of evaluated oil and natural gas properties $ 201,691 $ 203,492 $ 250,857 Depletion expense per BOE sold $ 6.76 $ 6.34 $ 8.50 The full cost ceiling is based principally on the estimated future net cash flows from proved oil, NGL and natural gas reserves, which exclude the effect of the Company's commodity derivative transactions, discounted at 10%. SEC guidelines require companies to use the unweighted arithmetic average first-day-of-the-month price for each month within the 12-month period prior to the end of the reporting period before differentials ("Benchmark Prices"). The Benchmark Prices are then adjusted for quality, certain transportation fees, geographical differentials, marketing bonuses or deductions and other factors affecting the price received at the delivery point ("Realized Prices") without giving effect to the Company's commodity derivative transactions. The Realized Prices are utilized to calculate the estimated future net cash flows in the full cost ceiling calculation. Significant inputs included in the calculation of discounted cash flows used in the impairment analysis include the Company's estimate of operating and development costs, anticipated production of proved reserves and other relevant data. In the event the unamortized cost of evaluated oil and natural gas properties being depleted exceeds the full cost ceiling, as defined by the SEC, the excess is expensed in the period such excess occurs. Once incurred, a write-down of oil and natural gas properties is not reversible. The unamortized cost of evaluated oil and natural gas properties being depleted did not exceed the full cost ceiling during any of the quarterly periods in 2021. The following table presents the Benchmark Prices and the Realized Prices as of the dates presented: December 31, 2021 December 31, 2020 December 31, 2019 Benchmark Prices: Oil ($/Bbl) $ 63.04 $ 36.04 $ 52.19 NGL ($/Bbl) (1) $ 34.51 $ 16.63 $ 21.14 Natural gas ($/MMBtu) $ 3.35 $ 1.21 $ 0.87 Realized Prices: Oil ($/Bbl) $ 66.37 $ 37.69 $ 52.12 NGL ($/Bbl) $ 22.90 $ 7.43 $ 12.21 Natural gas ($/Mcf) $ 2.61 $ 0.79 $ 0.53 _____________________________________________________________________________ (1) Based on the Company's average composite NGL barrel. The following table presents full cost ceiling impairment expense, which is included in "Impairment expense" on the consolidated statements of operations for the periods presented: Years ended December 31, (in thousands) 2021 2020 2019 Full cost ceiling impairment expense $ — $ 889,453 $ 620,565 b. Midstream service assets Midstream service assets, which consist of oil and natural gas pipeline gathering assets, related equipment, oil delivery stations, water storage and treatment facilities and their related asset retirement cost, are recorded at cost, net of impairment. See Note 2.k for discussion regarding midstream service asset retirement cost. Depreciation of assets is recorded using the straight-line method based on estimated useful lives of 10 to 20 years, as applicable. Expenditures for significant betterments or renewals, which extend the useful lives of existing fixed assets, are capitalized and depreciated. Upon retirement or disposition, the cost and related accumulated depreciation are removed from the accounts and any gain or loss is recognized in "Loss on disposal of assets, net" in the consolidated statements of operations. Midstream service assets consisted of the following components as of the dates presented: (in thousands) December 31, 2021 December 31, 2020 Midstream service assets $ 165,232 $ 181,718 Less accumulated depreciation and impairment (68,704) (69,021) Total midstream service assets, net $ 96,528 $ 112,697 During the year ended December 31, 2021, the Company retired $18.8 million in midstream service assets, resulting in the removal of $9.4 million in accumulated depreciation and the recognition of an associated loss of $9.4 million. The following table presents depreciation of midstream service assets for the periods presented: Years ended December 31, (in thousands) 2021 2020 2019 Depreciation of midstream service assets $ 9,514 $ 9,838 $ 10,206 c. Other fixed assets Other fixed assets are recorded at cost and are subject to depreciation and amortization. Land is recorded at cost and is not subject to depreciation. Depreciation and amortization of other fixed assets is provided using the straight-line method based on estimated useful lives of three Other fixed assets consisted of the following components as of the dates presented: (in thousands) December 31, 2021 December 31, 2020 Computer hardware and software $ 15,039 $ 9,388 Vehicles 9,072 9,852 Leasehold improvements 7,136 7,125 Buildings 7,039 6,982 Other 5,095 4,107 Depreciable total 43,381 37,454 Less accumulated depreciation and amortization (27,692) (24,344) Depreciable total, net 15,689 13,110 Land 18,901 18,901 Total other fixed assets, net $ 34,590 $ 32,011 The following table presents depreciation and amortization of other fixed assets for the periods presented: Years ended December 31, (in thousands) 2021 2020 2019 Depreciation and amortization of other fixed assets $ 4,150 $ 3,771 $ 4,683 |
Debt
Debt | 12 Months Ended |
Dec. 31, 2021 | |
Debt Disclosure [Abstract] | |
Debt | Note 7 Debt a. July 2029 Notes On July 16, 2021, the Company completed a private offering and sale of $400.0 million in aggregate principal amount of 7.750% senior unsecured notes due 2029 (the "July 2029 Notes"). Interest for the July 2029 Notes is payable semi-annually, in cash in arrears on January 31 and July 31 of each year, commencing January 31, 2022 with interest from closing to that date. The terms of the July 2029 Notes include covenants, which are in addition to but different than similar covenants in the Senior Secured Credit Facility, which limit the Company's ability to incur indebtedness, make restricted payments, grant liens and dispose of assets. The July 2029 Notes are fully and unconditionally guaranteed on a senior unsecured basis by LMS, GCM and certain of the Company's future restricted subsidiaries, subject to certain automatic customary releases, including the sale, disposition or transfer of all of the capital stock or of all or substantially all of the assets of a subsidiary guarantor to one or more persons that are not the Company or a restricted subsidiary, exercise of legal defeasance or covenant defeasance options or satisfaction and discharge of the applicable indenture, designation of a subsidiary guarantor as a non-guarantor restricted subsidiary or as an unrestricted subsidiary in accordance with the applicable indenture, release from guarantee under the Senior Secured Credit Facility, or liquidation or dissolution (collectively, the "Releases"). The Company received net proceeds of approximately $392.0 million from the July 2029 Notes, after deducting underwriting discounts and commissions and estimated offering expenses. The proceeds from the offering were used for general corporate purposes, including repaying a portion of the borrowings outstanding under the Senior Secured Credit Facility. b. January 2025 Notes and January 2028 Notes On January 24, 2020, the Company completed an offer and sale (the "Offering") of $600.0 million in aggregate principal amount of 9.500% senior unsecured notes due 2025 (the "January 2025 Notes") and $400.0 million in aggregate principal amount of 10.125% senior unsecured notes due 2028 (the "January 2028 Notes"). Interest for both the January 2025 Notes and January 2028 Notes is payable semi-annually, in cash in arrears on January 15 and July 15 of each year. The first interest payment was made on July 15, 2020, and consisted of interest from closing to that date. The terms of the January 2025 Notes and January 2028 Notes include covenants, which are in addition to but different than similar covenants in the Senior Secured Credit Facility, which limit the Company's ability to incur indebtedness, make restricted payments, grant liens and dispose of assets. The January 2025 Notes and January 2028 Notes are fully and unconditionally guaranteed on a senior unsecured basis by LMS, GCM and certain of the Company's future restricted subsidiaries, subject to certain Releases. The Company received net proceeds of $982.0 million from the Offering, after deducting underwriting discounts and commissions and estimated offering expenses. The proceeds from the Offering were used (i) to fund Tender Offers (defined below) for the Company's January 2022 Notes and March 2023 Notes (defined below), (ii) to repay the Company's January 2022 Notes and March 2023 Notes that remained outstanding after settling the Tender Offers and (iii) for general corporate purposes, including repayment of a portion of the borrowings outstanding under the Company's Senior Secured Credit Facility. In November 2020, the Company's board of directors authorized a $50.0 million bond repurchase program. During the year ended December 31, 2020, the Company repurchased $22.1 million in aggregate principal amount of the January 2025 Notes and $39.0 million in aggregate principal amount of the January 2028 Notes for aggregate consideration of $13.9 million and $24.2 million, respectively, plus accrued and unpaid interest. The Company recognized a gain on extinguishment of $22.3 million related to the difference between the consideration paid and the net carrying amounts of the extinguished portions of the January 2025 Notes and January 2028 Notes. c. January 2022 Notes and March 2023 Notes On January 23, 2014, the Company completed an offering of $450.0 million in aggregate principal amount of 5 5/8% senior unsecured notes due 2022 (the "January 2022 Notes"). The January 2022 Notes were due to mature on January 15, 2022 and bore an interest rate of 5 5/8% per annum, payable semi-annually, in cash in arrears on January 15 and July 15 of each year, commencing July 15, 2014. The January 2022 Notes were fully and unconditionally guaranteed on a senior unsecured basis by LMS, GCM and certain of the Company's future restricted subsidiaries, subject to certain Releases. On March 18, 2015, the Company completed an offering of $350.0 million in aggregate principal amount of 6 1/4% senior unsecured notes due 2023 (the "March 2023 Notes"). The March 2023 Notes were due to mature on March 15, 2023 and bore an interest rate of 6 1/4% per annum, payable semi-annually, in cash in arrears on March 15 and September 15 of each year, commencing September 15, 2015. The March 2023 Notes were fully and unconditionally guaranteed on a senior unsecured basis by LMS, GCM and certain of the Company's future restricted subsidiaries, subject to certain Releases. On January 6, 2020, the Company commenced cash tender offers and consent solicitations for any or all of its outstanding January 2022 Notes and March 2023 Notes (collectively, the "Tender Offers"). On January 24, 2020 and February 6, 2020, the Company settled the Tender Offers for the principal outstanding amounts of $428.9 million and $299.4 million, respectively, for consideration for tender offers and early tender premiums of $431.6 million and $304.1 million for the January 2022 Notes and March 2023 Notes, respectively, plus accrued and unpaid interest. On January 29, 2020, the Company redeemed the remaining $21.1 million of January 2022 Notes not tendered under the Tender Offers at a redemption price of 100.000% of the principal amount thereof, plus accrued and unpaid interest. On March 15, 2020, the Company redeemed the remaining $50.6 million of March 2023 Notes not tendered under the Tender Offers at a redemption price of 101.563% of the principal amount thereof, plus accrued and unpaid interest. The Company recognized a loss on extinguishment of $13.3 million related to the difference between the consideration for tender offers, early tender premiums and redemption prices and the net carrying amounts of the extinguished January 2022 Notes and March 2023 Notes. d. Senior Secured Credit Facility On May 7, 2021, the Company entered into the Sixth Amendment (the “Sixth Amendment”) to the Fifth Amended and Restated Credit Agreement, among the Company, as borrower, Wells Fargo Bank, N.A., as administrative agent, LMS and GCM, as guarantors, and the banks signatory thereto (as amended, the "Senior Secured Credit Facility"). The Sixth Amendment, among other things, reaffirmed the Senior Secured Credit Facility borrowing base at $725.0 million and amended the Senior Secured Credit Facility to permit (i) the Sabalo/Shad Acquisition and the other transactions contemplated by the Sabalo/Shad PSAs and (ii) the Working Interest Sale and the other transactions contemplated by the Sixth Street PSA, in each case, subject to the terms of the Sixth Amendment and the Senior Secured Credit Facility. On July 16, 2021, the Company entered into the Seventh Amendment (the "Seventh Amendment") to the Senior Secured Credit Facility. The Seventh Amendment, among other things, included technical amendments (including in connection with Eurodollar advances), extended the maturity date by two years to July 16, 2025 (subject to a springing maturity date of July 29, 2024 if any of the January 2025 Notes are outstanding on such date), increased the applicable margins for advances made thereunder, increased certain commitment and letter of credit fees, revised certain exceptions to the limitations on the payment of distributions and the repayment of unsecured debt and decreased the leverage ratio for quarterly periods ending on and after September 30, 2021. As of December 31, 2021, the Senior Secured Credit Facility, which matures on July 16, 2025 (subject to a springing maturity date of July 29, 2024 if any of the January 2025 Notes are outstanding on such date), had a maximum credit amount of $2.0 billion, a borrowing base of $1.0 billion and an aggregate elected commitment of $725.0 million, with $105.0 million outstanding and was subject to an interest rate of 2.625%. The borrowing base is subject to a semi-annual redetermination occurring by May 1 and November 1 of each year based on the lenders' evaluation of the Company's oil, NGL and natural gas reserves. As defined in the Senior Secured Credit Facility, (i) the Adjusted Base Rate advances under the facility bear interest payable quarterly at an Adjusted Base Rate plus applicable margin, which ranges from 1.50% to 2.50%, based on the ratio of outstanding revolving credit to the borrowing base under the Senior Secured Credit Facility; and (ii) the Eurodollar advances under the facility bear interest, at the Company's election, at the end of one-month, three-month, six-month or, to the extent available, 12-month interest periods (and in the case of six-month and 12-month interest periods, every three months prior to the end of such interest period) at an Adjusted London Interbank Offered Rate ("LIBOR") plus an applicable margin, which ranges from 2.50% to 3.50%, based on the ratio of outstanding revolving credit to the borrowing base under the Senior Secured Credit Facility. Laredo is required to pay a quarterly commitment fee on the unused portion of the financial institutions' commitment of 0.5%. The Senior Secured Credit Facility is secured by a first-priority lien on Laredo and the Guarantors' assets and stock, including oil and natural gas properties constituting at least 85% of the present value of the Company's proved reserves. Further, the Company is subject to various financial and non-financial covenants on a consolidated basis, including a current ratio at the end of each calendar quarter, of not less than 1.00 to 1.00. As defined by the Senior Secured Credit Facility, the current ratio represents the ratio of current assets to current liabilities, inclusive of available capacity and exclusive of current balances associated with derivative positions. Additionally, the Company must maintain as of the last day of each calendar quarter a ratio of (a) its total debt (excluding reimbursement obligations in respect of undrawn letters of credit, if no loans are outstanding under the Senior Secured Credit Facility) minus a maximum of $50 million of unrestricted and unencumbered cash and cash equivalents, to (b) "Consolidated EBITDAX," as defined in the Senior Secured Credit Facility, for any period of four consecutive calendar quarters ending on the last day of such applicable calendar quarter of (i) not greater than 4.25 to 1.00 for quarterly periods ending on or prior to September 30, 2020, (ii) not greater than 4.00 to 1.00 for quarterly periods ending on or prior to March 31, 2021, (iii) not greater than 3.75 to 1.00 for the quarterly period ending on June 30, 2021 and (iv) not greater than 3.50 to 1.00 for quarterly periods ending on or after September 30, 2021. The Company was in compliance with these covenants for all periods presented. The Company's measurements of Adjusted EBITDA (non-GAAP) for financial reporting differs from the measurement used for compliance under its debt agreements. Additionally, the Senior Secured Credit Facility provides for the issuance of letters of credit, limited to the lesser of total capacity or $80.0 million. As of December 31, 2021 and 2020, the Company had one letter of credit outstanding of $44.1 million under the Senior Secured Credit Facility. See Note 18.a for discussion of a borrowing and repayment on the Senior Secured Credit Facility subsequent to December 31, 2021. e. Debt issuance costs The following table presents debt issuance costs capitalized and debt issuance costs write-offs for the periods presented: Years ended December 31, (in thousands) 2021 2020 2019 Debt issuance costs capitalized (1) $ 14,686 $ 18,479 $ — Debt issuance costs write-offs (2) $ — $ 6,163 $ 935 ______________________________________________________________________________ (1) The Company capitalized $14.7 million in debt issuance costs during the year ended December 31, 2021 in connection with an increase in the borrowing base, entering into the Sixth and Seventh Amendments to the Senior Secured Credit Facility and the issuance of the July 2029 Notes. The Company capitalized $18.5 million in debt issuance costs during the year ended December 31, 2020 in connection with the issuance of the January 2025 Notes and January 2028 Notes and entering into amendments to the Senior Secured Credit facility in connection with the semi-annual redeterminations. (2) The Company wrote off $1.1 million and $0.9 million of debt issuance costs during the years ended December 31, 2020 and 2019, respectively, which are the "Write-off of debt issuance costs" on the consolidated statements of operations, in connection with reductions in borrowing base and aggregate elected commitment under the Senior Secured Credit Facility in connection with the semi-annual redeterminations. The Company wrote off $5.1 million in debt issuance costs during the year ended December 31, 2020, which are included in "Gain on extinguishment of debt, net" on the consolidated statement of operations, in connection with the extinguishment of the January 2022 Notes and March 2023 Notes and portions of the January 2025 Notes and January 2028 Notes. The Company had total debt issuance costs of $26.2 million and $17.0 million, net of accumulated amortization of $27.2 million and $22.1 million, as of December 31, 2021 and 2020, respectively. Debt issuance costs related to the Company's January 2025 Notes, January 2028 Notes and July 2029 Notes are included in "Long-term debt, net" on the consolidated balance sheets. Debt issuance costs related to the Senior Secured Credit Facility are included in "Other noncurrent assets, net" on the consolidated balance sheets. Debt issuance costs are amortized on a straight-line basis over the respective terms of the notes and the Senior Secured Credit Facility. See Note 7.g for additional discussion of debt issuance costs. The following table presents future amortization expense of debt issuance costs: (in thousands) December 31, 2021 2022 6,165 2023 6,165 2024 6,165 2025 2,894 2026 1,735 Thereafter 3,079 Total 26,203 f. Interest expense The following table presents amounts that have been incurred and charged to interest expense: Years ended December 31, (in thousands) 2021 2020 2019 Cash payments for interest $ 100,733 $ 80,420 $ 59,021 Amortization of debt issuance costs and other adjustments 4,451 3,708 3,111 Change in accrued interest 14,067 23,900 220 Interest costs incurred 119,251 108,028 62,352 Less capitalized interest (5,866) (3,019) (805) Total interest expense $ 113,385 $ 105,009 $ 61,547 g. Long-term debt, net The following table presents the Company's long-term debt and debt issuance costs, net included in "Long-term debt, net" on the consolidated balance sheets as of the dates presented: December 31, 2021 December 31, 2020 (in thousands) Long-term debt Debt issuance costs, net Long-term debt, net Long-term debt Debt issuance costs, net Long-term debt, net January 2025 Notes 577,913 (6,345) 571,568 577,913 (8,676) 569,237 January 2028 Notes 361,044 (5,024) 356,020 361,044 (6,015) 355,029 July 2029 Notes 400,000 (6,730) 393,270 — — — Senior Secured Credit Facility (1) 105,000 — 105,000 255,000 — 255,000 Total $ 1,443,957 $ (18,099) $ 1,425,858 $ 1,193,957 $ (14,691) $ 1,179,266 _____________________________________________________________________________ (1) Debt issuance costs, net related to the Senior Secured Credit Facility of $8.1 million and $2.3 million as of December 31, 2021 and 2020, respectively, are included in "Other noncurrent assets, net" on the consolidated balance sheets. |
Stockholders' equity
Stockholders' equity | 12 Months Ended |
Dec. 31, 2021 | |
Equity [Abstract] | |
Stockholders' equity | Note 8 Stockholders' equity a. ATM Program On February 23, 2021, the Company entered into an equity distribution agreement (the "Equity Distribution Agreement") with Wells Fargo Securities, LLC acting as sales agent and/or principal (the "Sales Agent"), pursuant to which the Company may offer and sell, from time to time through the Sales Agent, shares of its common stock having an aggregate gross sales price of up to $75.0 million through an "at-the-market" equity program (the "ATM Program"). Pursuant to the Equity Distribution Agreement, shares of common stock may be offered and sold in privately negotiated transactions or transactions that are deemed to be "at-the-market" offerings as defined in Rule 415 under the Securities Act, including by ordinary brokers’ transactions through the facilities of the New York Stock Exchange, to or through a market maker or as otherwise agreed with the Sales Agent. Under the terms of the Equity Distribution Agreement, the Company may also sell common stock from time to time to the Sales Agent as principal for its own account at a price to be agreed upon at the time of sale. Any sale of common stock to the Sales Agent as principal would be pursuant to the terms of a separate terms agreement between the Company and the Sales Agent, which would be described in a separate prospectus supplement or pricing supplement. As of December 31, 2021, the Company has sold 1,438,105 shares of its common stock pursuant to the ATM Program for net proceeds of approximately $72.5 million, after underwriting commissions and other related expenses, thus completing the ATM Program. Proceeds from the share sales were utilized to reduce borrowings on the Senior Secured Credit Facility. b. Reverse stock split and Authorized Share Reduction On March 17, 2020, the board of directors authorized an amendment to the Company's amended and restated certificate of incorporation ("Certificate of Incorporation") to effect, at the discretion of the board of directors (i) a reverse stock split that would reduce the number of shares of outstanding common stock in accordance with a ratio to be determined by the board of directors within a range of 1-for-5 and 1-for-20 currently outstanding and (ii) a reduction of the number of authorized shares of common stock by a corresponding proportion ("Authorized Share Reduction"). On May 14, 2020, after receiving stockholder approval of the amendment to the Certificate of Incorporation, the board of directors approved the implementation of the reverse stock split at a ratio of 1-for-20 currently outstanding shares of common stock, and the related corresponding Authorized Share Reduction. On June 1, 2020, the amendment to the Company's Certificate of Incorporation became effective and effected the 1-for-20 reverse stock split of the Company's issued and outstanding common stock and the related Authorized Share Reduction from 450,000,000 to 22,500,000 authorized shares, par value $0.01 per share, with authorized shares of preferred stock remaining unchanged at 50,000,000, par value $0.01 per share, for a total of 72,500,000 shares of capital stock. See Note 9.a for discussion of the Laredo Petroleum, Inc. Omnibus Equity Incentive Plan (the "Equity Incentive Plan"), that proportionately reduced the number of shares that may be granted. |
Compensation plans
Compensation plans | 12 Months Ended |
Dec. 31, 2021 | |
Share-based Payment Arrangement [Abstract] | |
Compensation plans | Note 9 Compensation plans a. Equity Incentive Plan The Equity Incentive Plan provides for the granting of incentive awards in the form of restricted stock awards, stock option awards, performance share awards, outperformance share awards, performance unit awards, phantom unit awards and other awards. On June 1, 2020, in connection with the effectiveness of the reverse stock split and Authorized Share Reduction, the board of directors approved and adopted an amendment to the Equity Incentive Plan to proportionately adjust the limitations on awards that may be granted under the Equity Incentive Plan. Following the amendment, an aggregate of 1,492,500 shares may be issued under the Equity Incentive Plan. See Note 8.b for additional discussion of the reverse stock split and Authorized Share Reduction. On May 20, 2021, the Company's stockholders approved an amendment to the Equity Incentive Plan to, among other things, increase the maximum number of shares of the Company's common stock issuable under the Equity Incentive Plan from 1,492,500 to 2,432,500 shares. See Note 2.p for discussion of the Company's significant accounting policies for equity-based compensation awards. Restricted stock awards All service vesting restricted stock awards are treated as issued and outstanding in the consolidated financial statements. Per the award agreement terms, if employment is terminated prior to the restriction lapse date for reasons other than death or disability, the restricted stock awards are forfeited and canceled and are no longer considered issued and outstanding. If the termination of employment is by reason of death or disability, all of the holder's restricted stock will automatically vest. Restricted stock awards granted to employees vest in a variety of schedules that mainly include (i) 33%, 33% and 34% vesting per year beginning on the first anniversary of the grant date and (ii) full vesting on the first anniversary of the grant date. Restricted stock awards granted to non-employee directors vest immediately on the grant date. The following table reflects the restricted stock award activity for the years presented: (in thousands, except for weighted-average grant-date fair value) Restricted Weighted-average Outstanding as of December 31, 2018 210 $ 198.20 Granted 381 $ 65.20 Forfeited (178) $ 102.20 Vested (138) $ 178.40 Outstanding as of December 31, 2019 275 $ 85.80 Granted 238 $ 16.54 Forfeited (48) $ 53.51 Vested (156) $ 71.25 Outstanding as of December 31, 2020 309 $ 44.88 Granted 237 $ 38.86 Forfeited (42) $ 42.44 Vested (1) (154) $ 57.37 Outstanding as of December 31, 2021 350 $ 35.57 _____________________________________________________________________________ (1) The aggregate intrinsic value of vested restricted stock awards for the year ended December 31, 2021 was $7.3 million. The Company utilizes the closing stock price on the grant date to determine the fair value of restricted stock awards. As of December 31, 2021, unrecognized equity-based compensation related to the restricted stock awards expected to vest was $7.2 million. Such cost is expected to be recognized over a weighted-average period of 1.94 years. Stock option awards The following table reflects the stock option award activity for the years presented: (in thousands, except for weighted-average exercise price and weighted-average remaining contractual term) Stock option awards Weighted-average Weighted-average Outstanding as of December 31, 2018 127 $ 253.80 5.99 Exercised (1) $ 82.00 Expired or canceled (92) $ 271.00 Forfeited (17) $ 172.20 Outstanding as of December 31, 2019 17 $ 251.20 5.00 Expired or canceled (6) $ 238.38 Outstanding as of December 31, 2020 11 $ 257.42 4.00 Exercised (2) $ 82.00 Expired or canceled (2) $ 374.77 Outstanding and exercisable as of December 31, 2021 (1) 7 $ 275.88 3.24 _____________________________________________________________________________ (1) The vested and exercisable stock option awards as of December 31, 2021 had no intrinsic value. The Company utilizes the Black-Scholes option pricing model to determine the fair value of stock option awards and recognizes the associated expense on a straight-line basis over the four-year requisite service period of the awards. Stock option awards granted to employees vest and become exercisable in four equal installments on each of the four anniversaries of the grant date, in accordance with the following schedule: Full years of continuous employment following grant date Incremental percentage of Cumulative percentage of Less than one — % — % One 25 % 25 % Two 25 % 50 % Three 25 % 75 % Four 25 % 100 % Unless employment is terminated sooner, the vested stock option award will expire if and to the extent it is not exercised within 10 years from the grant date. The unvested portion of a stock option award shall forfeit upon termination of employment, and the vested portion of a stock option award shall remain exercisable for (i) one year following termination of employment by reason of the holder's death or disability, but not later than the expiration of the option period, or (ii) 90 days following termination of employment for any reason other than the holder's death or disability, and other than the holder's termination of employment for cause. The vested but unexercised portion of a stock option award shall expire upon the termination of the option holder's employment or service by the Company for cause. Performance share awards Performance share awards, which the Company has determined are equity awards, are subject to a combination of market, performance and service vesting criteria. For portions of awards with market criteria, a Monte Carlo simulation prepared by an independent third party is utilized to determine the grant-date (or modification date) fair value, and the associated expense is recognized on a straight-line basis over the three-year requisite service period of the awards. For portions of awards with performance criteria, the fair value is equal to the Company's closing stock price on the grant date (or modification date), and for each reporting period, the associated expense fluctuates and is adjusted based on an estimated payout of the number of shares of common stock to be delivered on the payment date for the three-year performance period. These awards were granted in 2019 and 2018, and their market criteria consists of: (i) the relative three-year total shareholder return ("TSR") comparing the Company's shareholder return to the shareholder return of the peer group specified in each award agreement ("RTSR Performance Percentage"), and (ii) the Company's absolute three-year total shareholder return ("ATSR Appreciation"). The performance criteria for these awards consists of the Company's three-year return on average capital employed ("ROACE Percentage"). Any shares earned under performance share awards are expected to be issued in the first quarter following the completion of the respective requisite service periods based on the achievement of certain market and performance criteria, and the payout can range from 0% to 200%. Per the award agreement terms, if employment is terminated prior to the restriction lapse date for reasons other than death or disability, the performance share awards are forfeited and canceled. If the termination of employment is by reason of death or disability, and the market and performance criteria are satisfied, then the holder of the earned performance share awards will receive a prorated number of shares based on the number of days the participant was employed with the Company during the performance period. The following table reflects the performance share award activity for the years presented: (in thousands, except for weighted-average grant-date fair value) Performance share awards Weighted-average Outstanding as of December 31, 2018 172 $ 274.80 Granted (1) 29 $ 50.40 Converted from performance unit awards (1)(2) 78 $ 74.80 Forfeited (87) $ 209.60 Lapsed (3) (77) $ 346.20 Outstanding as of December 31, 2019 115 $ 106.80 Forfeited (10) $ 110.94 Lapsed (4) (8) $ 379.20 Outstanding as of December 31, 2020 97 $ 84.06 Forfeited (10) $ 74.70 Vested (1) (15) $ 184.43 Outstanding as of December 31, 2021 72 $ 64.74 _____________________________________________________________________________ (1) The amounts payable in the Company's common stock at the end of the requisite service period for the performance share awards granted on February 16, 2018, February 28, 2019 and June 3, 2019 were determined based on three criteria: (i) RTSR Performance Percentage, (ii) ATSR Appreciation and (iii) ROACE Percentage. The RTSR Performance Percentage, ATSR Appreciation and ROACE Percentage will be used to identify the "RTSR Factor," the "ATSR Factor" and the "ROACE Factor," respectively, which are used to compute the "Performance Multiple" and ultimately to determine the number of shares to be delivered on the payment date. In computing the Performance Multiple, the RTSR Factor is given a 25% weight, the ATSR Factor a 25% weight and the ROACE Factor a 50% weight. The performance share awards granted on February 16, 2018 had a performance period of January 1, 2018 to December 31, 2020 and, as their market and performance criteria were partially satisfied, resulted in a 43% payout. Based on such payout, the granted awards vested and were converted into 6,343 shares of the Company's common stock during the year ended December 31, 2021. The performance share awards granted on February 28, 2019 and June 3, 2019 had a performance period of January 1, 2019 to December 31, 2021 and, as their market and performance criteria were fully satisfied, resulted in a 107% payout. Based on such payout, the granted awards will be converted into shares of the Company's common stock during the first quarter of 2022. (2) On May 16, 2019, the board of directors elected to change the form of payment from cash to common stock for the awards granted on February 28, 2019. This change in election triggered modification accounting, and the awards, formerly accounted for as liability awards, were converted to equity awards and, accordingly, new fair values were determined based on the May 16, 2019 modification date. (3) The performance share awards granted on May 25, 2016 had a performance period of January 1, 2016 to December 31, 2018 and, as their market criteria were not satisfied, resulted in a TSR modifier of 0% based on the Company finishing in the ninth percentile of its peer group for relative TSR. As such, the granted units lapsed and were not converted into the Company's common stock during the first quarter of 2019. (4) The performance share awards granted on February 17, 2017 had a performance period of January 1, 2017 to December 31, 2019 and, as their market criteria were not satisfied, resulted in a TSR modifier of 0% based on the Company finishing in the 15th percentile of its peer group for relative TSR. As such, the granted units lapsed and were not converted into the Company's common stock during the first quarter of 2020. As of December 31, 2021, unrecognized equity-based compensation related to the performance share awards expected to vest was $0.3 million. Such cost is expected to be recognized over a weighted-average period of 0.16 years. The following table presents (i) the fair values per performance share and the assumptions used to estimate these fair values per performance share and (ii) the expense per performance share, which is the fair value per performance share adjusted for the estimated payout of the performance criteria, for the outstanding performance share awards as of December 31, 2021 for the grant dates presented: June 3, 2019 February 28, 2019 (1) Market Criteria: 25% RTSR Factor + 25% ATSR Factor: Fair value assumptions: Remaining performance period on grant date 2.58 years 2.63 years Risk-free interest rate (2) 1.78 % 2.14 % Dividend yield — % — % Expected volatility (3) 55.45 % 55.01 % Closing stock price on grant date $ 51.80 $ 69.80 Grant-date fair value per performance share $ 49.00 $ 79.61 Expense per performance share as of December 31, 2021 $ 49.00 $ 79.61 Performance Criteria: 50% ROACE Factor: Fair value assumptions: Closing stock price on grant date $ 51.80 $ 69.80 Grant-date fair value per performance share $ 51.80 $ 69.80 Estimated payout for expense as of December 31, 2021 160 % 160 % Expense per performance share as of December 31, 2021 (4) $ 82.88 $ 111.68 Combined: Grant-date fair value per performance share (5) $ 65.94 $ 95.65 Expense per performance share as of December 31, 2021 (6) $ 65.94 $ 95.65 ______________________________________________________________________________ (1) The fair value assumptions of the performance share awards granted on February 28, 2019 are based on the May 16, 2019 modification date. The total incremental compensation expense resulting from the modification of $1.0 million, which will be recognized over the life of the awards, is calculated utilizing (i) the difference between the March 31, 2019 fair value and the May 16, 2019 fair value and (ii) the outstanding quantity of the converted performance share awards as of June 30, 2019. Such expense excludes the estimated payout component for expense for the 50% ROACE Factor as this is redetermined at each reporting period and the expense will fluctuate accordingly. (2) The remaining performance period matched zero-coupon risk-free interest rate was derived from the U.S. Treasury constant maturities yield curve on the grant date for each respective award, with the exception of the awards granted on February 28, 2019, which used the modification date of May 16, 2019. (3) The Company utilized its own remaining performance period matched historical volatility in order to develop the expected volatility. (4) As the 50% ROACE Factor is based on performance criteria, the expense fluctuates based on the estimated payout and is redetermined each reporting period and the life-to-date recognized expense for the respective awards is adjusted accordingly. (5) The combined grant-date fair value per performance share is the combination of the fair value per performance share weighted for the market and performance criteria for the respective awards. (6) The combined expense per performance share is the combination of the expense per performance share weighted for the market and performance criteria for the respective awards. Outperformance share award An outperformance share award was granted during the year ended December 31, 2019, in conjunction with the appointment of the Company's President, and is accounted for as an equity award. If earned, the payout ranges from 0 to 50,000 shares in the Company's common stock per the vesting schedule. This award is subject to a combination of market and service vesting criteria and, therefore, a Monte Carlo simulation prepared by an independent third party was utilized to determine the grant-date fair value with the associated expense recognized over the requisite service period. The payout of this award is based on the highest 50 consecutive trading day average closing stock price of the Company that occurs during the performance period that commenced on June 3, 2019 and ends on June 3, 2022 ("Final Date"). Of the earned outperformance shares, one-third of the award will vest on the Final Date, one-third will vest on the first anniversary of the Final Date and one-third will vest on the second anniversary of the Final Date, provided that the participant has been continuously employed with the Company through the applicable vesting date. Per the award agreement terms, if employment is terminated prior to any vesting date for reasons other than death or disability, then any outperformance shares that have not vested as of such date shall be forfeited and canceled. If the participant's employment is terminated prior to any vesting date by reason of death or disability, and the market criteria is satisfied, then the participant will receive a prorated number of shares based on the number of days the employee was employed with the Company during the performance period. The total fair value of the outperformance share award and the assumptions used to estimate the fair value of the outperformance share award as of the grant date presented are as follows: June 3, 2019 Performance period 3.00 years Risk-free interest rate (1) 1.77 % Dividend yield — % Expected volatility (2) 55.77 % Closing stock price on grant date $ 51.80 Total fair value of outperformance share award (in thousands) $ 670.0 _____________________________________________________________________________ (1) The performance period matched zero-coupon risk-free interest rate was derived from the U.S. Treasury constant maturities yield curve on the grant date. (2) The Company utilized its own performance period matched historical volatility in order to develop the expected volatility. As of December 31, 2021, unrecognized equity-based compensation related to the outperformance share award expected to vest was $0.2 million. Such cost is expected to be recognized over a weighted-average period of 1.78 years. Performance unit awards Performance unit awards, which the Company has determined are liability awards since they are settled in cash, are subject to a combination of market, performance and service vesting criteria. For portions of awards with market criteria, a Monte Carlo simulation prepared by an independent third party is utilized to determine the fair value, and is re-measured at each reporting period until settlement. For portions of awards with performance criteria, the Company's closing stock price is utilized to determine the fair value and is re-measured on the last trading day of each reporting period until settlement and, additionally, the associated expense fluctuates based on an estimated payout for the three-year performance period. The expense related to the performance unit awards is recognized on a straight-line basis over the three-year requisite service period of the awards, and the life-to-date recognized expense is adjusted accordingly at each reporting period based on the quarterly fair value re-measurements and redetermination of the estimated payout for the performance criteria. For performance unit awards granted in 2021, the market criteria consists of: (i) annual relative shareholder return comparing the Company's shareholder return to the shareholder return of the E&P companies listed in the Russell 2000 index ("Relative TSR") and (ii) annual absolute total shareholder return ("Absolute Return"), together the "PSU Matrix". The performance criteria for these awards consists of: (i) earnings before interest , taxes, depreciation, amortization and exploration expense ("EBITDAX") and three-year total debt reduction (the "EBITDAX/Total Debt Component") and (ii) growth in inventory (the "Inventory Growth Component"). Any units earned are expected to be paid in cash during the first quarter following the completion of the requisite service period, based on the achievement of certain market and performance criteria, and the payout can range from 0% to 250% for the market criteria and 0% to 200% for the performance criteria. For performance unit awards granted in 2020, the market criteria consists of: (i) the RTSR Performance Percentage and (ii) the ATSR Appreciation. The performance criteria for these awards consists of the ROACE Percentage. Any units earned, are expected to be paid in cash during the first quarter following the completion of the requisite service period, based on the achievement of certain market and performance criteria, and the payout can range from 0% to 200%, but is capped at 100% if the ATSR Appreciation is zero or less. Per the award agreement terms, if employment is terminated prior to the restriction lapse date for reasons other than death or disability, the performance unit awards are forfeited and canceled. If the termination of employment is by reason of death or disability, and the market and performance criteria are satisfied, then the holder of the earned performance unit awards will receive a prorated payment based on the number of days the participant was employed with the Company during the performance period. The following table reflects the performance unit award activity for the years presented: (in thousands) Performance units Outstanding as of December 31, 2019 — Granted (1) 123 Forfeited (24) Outstanding as of December 31, 2020 99 Granted (2) 110 Outstanding as of December 31, 2021 209 ______________________________________________________________________________ (1) The amounts potentially payable in cash at the end of the requisite service period for the performance unit awards granted on March 5, 2020 will be determined based on three criteria: (i) RTSR Performance Percentage, (ii) ATSR Appreciation and (iii) ROACE Percentage. The RTSR Performance Percentage, ATSR Appreciation and ROACE Percentage will be used to identify the "RTSR Factor," the "ATSR Factor" and the "ROACE Factor," respectively, which are used to compute the "Performance Multiple" and ultimately to determine the final value of each performance unit to be paid in cash on the payment date per the award agreement, subject to withholding requirements. In computing the Performance Multiple, the RTSR Factor is given a 1/3 weight, the ATSR Factor a 1/3 weight and the ROACE Factor a 1/3 weight. These awards have a performance period of January 1, 2020 to December 31, 2022. (2) The amounts potentially payable in cash at the end of the requisite service period for the performance unit awards granted on March 9, 2021 will be determined based on three criteria: (i) the PSU Matrix, (ii) the EBITDAX/Total Debt Component and (iii) the Inventory Growth Component. These criteria are used to compute the "Performance Multiple" and ultimately to determine the final value of each performance unit to be paid in cash on the payment date per the award agreement, subject to withholding requirements. In computing the Performance Multiple, the PSU Matrix is given a 50% weight, the EBITDAX/Total Debt Component a 25% weight and the Inventory Growth Component a 25% weight. These awards have a performance period of January 1, 2021 to December 31, 2023. The following tables present (i) the fair values per performance unit and the assumptions used to estimate these fair values per performance unit and (ii) the expense per performance unit, which is the fair value per performance unit adjusted for the estimated payout of the performance criteria, for the outstanding performance unit awards as of December 31, 2021 for the grant dates presented: March 5, 2020 Market criteria: 1/3 RTSR Factor + 1/3 ATSR Factor: Fair value assumptions: Remaining performance period 1.00 year Risk-free interest rate (1) 0.39 % Dividend yield — % Expected volatility (2) 86.17 % Closing stock price on December 31, 2021 $ 60.13 Fair value per performance unit as of December 31, 2021 $ 195.77 Expense per performance unit as of December 31, 2021 $ 195.77 Performance criteria: 1/3 ROACE Factor: Fair value assumptions: Closing stock price on December 31, 2021 $ 60.13 Fair value per performance unit as of December 31, 2021 $ 60.13 Estimated payout for expense as of December 31, 2021 130.00 % Expense per performance unit as of December 31, 2021 (3) $ 78.17 Combined: Fair value per performance unit as of December 31, 2021 (4) $ 91.31 Expense per performance unit as of December 31, 2021 (5) $ 91.31 ______________________________________________________________________________ (1) The remaining performance period matched zero-coupon risk-free interest rate was derived from the U.S. Treasury constant maturities yield curve on December 31, 2021. (2) The Company utilized its own remaining performance period matched historical volatility in order to develop the expected volatility. (3) As the 1/3 ROACE Factor is based on performance criteria, the expense fluctuates based on the estimated payout and is redetermined each reporting period and the life-to-date recognized expense for the award is adjusted accordingly. (4) The combined fair value per performance unit is the combination of the fair value per performance unit weighted for the market and performance criteria for the award. (5) The combined expense per performance unit is the combination of the expense per performance unit weighted for the market and performance criteria for the award. March 9, 2021 Market criteria: 50% PSU Matrix Component: Fair value assumptions: Remaining performance period 2.00 years Risk-free interest rate (1) 0.73 % Dividend yield — % Expected volatility (2) 135.42 % Closing stock price on December 31, 2021 $ 60.13 Fair value per performance unit as of December 31, 2021 $ 121.72 Expense per performance unit as of December 31, 2021 $ 121.72 Performance criteria: 25% EBITDAX/Total Debt Component + 25% Inventory Growth Component Fair value assumptions: Closing stock price on December 31, 2021 $ 60.13 Fair value per performance unit as of December 31, 2021 $ 60.13 Estimated payout for expense as of December 31, 2021 100.00 % Expense per performance unit as of December 31, 2021 (3) $ 60.13 Combined: Fair value per performance unit as of December 31, 2021 (4) $ 90.92 Expense per performance unit as of December 31, 2021 (5) $ 90.92 ______________________________________________________________________________ (1) The remaining performance period matched zero-coupon risk-free interest rate was derived from the U.S. Treasury constant maturities yield curve on December 31, 2021. (2) The Company utilized its own remaining performance period matched historical volatility in order to develop the expected volatility. (3) As the 25% EBITDAX/Total Debt Component and 25% Inventory Growth Component are based on performance criteria, the expense fluctuates based on the estimated payout and is redetermined each reporting period and the life-to-date recognized expense for the award is adjusted accordingly. (4) The combined fair value per performance unit is the combination of the fair value per performance unit weighted for the market and performance criteria for the award. (5) The combined expense per performance unit is the combination of the expense per performance unit weighted for the market and performance criteria for the award. As of December 31, 2021, unrecognized equity-based compensation related to the performance unit awards expected to vest was $10.8 million. Such cost is expected to be recognized over a weighted-average period of 1.86 years. Phantom unit awards Phantom unit awards, which the Company has determined are liability awards, represent the holder's right to receive the cash equivalent of one share of common stock of the Company for each phantom unit as of the applicable vesting date, subject to withholding requirements. Phantom unit awards granted to employees vest 33%, 33% and 34% per year beginning on the first anniversary of the grant date. Per the award agreement terms, if employment is terminated prior to the restriction lapse date for reasons other than death or disability, the phantom unit awards are forfeited and canceled. If the termination of employment is by reason of death or disability, all of the holder's phantom unit awards automatically vest. The following table reflects the phantom unit award activity for the year ended December 31, 2021: (in thousands, except for weighted-average fair value) Phantom units Outstanding as of December 31, 2019 — Granted 75 Outstanding as of December 31, 2020 75 Granted 5 Forfeited (22) Vested (1) (25) Outstanding as of December 31, 2021 (2) 33 ______________________________________________________________________________ (1) On March 5, 2021, the vested phantom unit awards were settled and paid out in cash at a fair value per unit of $34.24 based on the Company's closing stock price on the vesting date. (2) The fair value per unit of outstanding phantom unit awards as of December 31, 2021 was $60.13. The Company utilizes the closing stock price on the last day of each reporting period to determine the fair value of phantom unit awards and the life-to-date recognized expense is adjusted accordingly. As of December 31, 2021, unrecognized equity-based compensation related to the phantom unit awards expected to vest was $1.2 million. Such cost is expected to be recognized over a weighted-average period of 1.34 years. Equity-based compensation The following table reflects equity-based compensation expense for the years presented: Years ended December 31, (in thousands) 2021 2020 2019 Equity awards: Restricted stock awards $ 7,594 $ 8,839 $ 13,169 Performance share awards 1,482 2,545 (1,250) Outperformance share award 175 174 101 Stock option awards 7 77 740 Total share-settled equity-based compensation, gross $ 9,258 $ 11,635 $ 12,760 Less amounts capitalized (1,583) (3,418) (4,470) Total share-settled equity-based compensation, net $ 7,675 $ 8,217 $ 8,290 Liability awards: Performance unit awards $ 7,480 $ 749 $ — Phantom unit awards 1,238 404 — Total cash-settled equity-based compensation, gross $ 8,718 $ 1,153 $ — Less amounts capitalized (365) (163) — Total cash-settled equity-based compensation, net $ 8,353 $ 990 $ — Total equity-based compensation, net $ 16,028 $ 9,207 $ 8,290 See Note 17 for discussion of the Company's organizational restructurings and the related equity-based compensation reversals during the years ended December 31, 2021, 2020 and 2019. b. 401(k) plan The Company sponsors a 401(k) plan that is a defined contribution plan for the benefit of all employees at the date of hire. The plan allows eligible employees to make pre-tax and after-tax contributions up to 100% of their annual eligible compensation, not to exceed annual limits established by the federal government. The Company makes matching contributions of up to 6% of an employee's compensation and may make additional discretionary contributions for eligible employees. Employees are 100% vested in the employer contributions upon receipt. The following table presents the contributions expense recognized for the Company's 401(k) plan for the years presented: Years ended December 31, (in thousands) 2021 2020 2019 Contributions $ 1,652 $ 1,649 $ 1,742 |
Derivatives
Derivatives | 12 Months Ended |
Dec. 31, 2021 | |
Derivative Instruments and Hedging Activities Disclosure [Abstract] | |
Derivatives | Note 10 Derivatives The Company has three types of derivative instruments as of December 31, 2021: (i) commodity derivatives, (ii) a debt interest rate derivative and (iii) a contingent consideration derivative. See Notes (i) 2.e for the Company's significant accounting policies for derivatives and presentation in the consolidated financial statements, (ii) 11.a for fair value measurement of derivatives on a recurring basis and (iii) 18.b for derivatives subsequent events. The following table summarizes the Company's gain (loss) on derivatives, net by type of derivative instrument for the periods presented: Years ended December 31, (in thousands) 2021 2020 2019 Commodity $ (453,784) $ 73,662 $ 80,351 Interest rate (30) (343) — Contingent consideration 1,639 6,795 (1,200) Gain (loss) on derivatives, net $ (452,175) $ 80,114 $ 79,151 a. Commodity Due to the inherent volatility in oil, NGL and natural gas prices and the sometimes wide pricing differences in the prices of oil, NGL and natural gas between where the Company produces and where the Company sells such commodities, the Company engages in commodity derivative transactions, such as puts, swaps, collars and basis swaps to hedge price risk associated with a portion of the Company's anticipated sales volumes. By removing a portion of the price volatility associated with future sales volumes, the Company expects to mitigate, but not eliminate, the potential effects of variability in cash flows from operations. Each put transaction has an established floor price. The Company pays its counterparty a premium, which can be paid at inception or deferred until settlement, to enter into the put transaction. When the settlement price is below the floor price, the counterparty pays the Company an amount equal to the difference between the settlement price and the floor price multiplied by the hedged contract volume. When the settlement price is at or above the floor price in an individual month in the contract period, the put option expires with no settlement for that particular month, except with regard to the deferred premium, if any. Each swap transaction has an established fixed price. When the settlement price is below the fixed price, the counterparty pays the Company an amount equal to the difference between the settlement price and the fixed price multiplied by the hedged contract volume. When the settlement price is above the fixed price, the Company pays its counterparty an amount equal to the difference between the settlement price and the fixed price multiplied by the hedged contract volume. Each collar transaction has an established price floor and ceiling. Depending on the terms, the Company may pay its counterparty a premium, which can be paid at inception or deferred until settlement. When the settlement price is below the price floor established by these collars, the counterparty pays the Company an amount equal to the difference between the settlement price and the price floor multiplied by the hedged contract volume. When the settlement price is above the price ceiling established by these collars, the Company pays its counterparty an amount equal to the difference between the settlement price and the price ceiling multiplied by the hedged contract volume. When the settlement price is at or between the price floor and price ceiling established by these collars in an individual month in the contract period, the collar expires with no settlement paid by either the Company or the counterparty for that particular month, except with regard to the deferred premium, if any. Each basis swap transaction has an established fixed basis differential corresponding to two floating index prices. When the settlement basis differential is below the fixed basis differential, the counterparty pays the Company an amount equal to the difference between the fixed basis differential and the settlement basis differential multiplied by the hedged contract volume. When the settlement basis differential is above the fixed basis differential, the Company pays the counterparty an amount equal to the difference between the settlement basis differential and the fixed basis differential multiplied by the hedged contract volume. During the year ended December 31, 2021, the Company’s derivatives were settled based on reported prices on commodity exchanges, with (i) oil derivatives settled based on WTI NYMEX pricing and Brent ICE pricing, (ii) NGL derivatives settled based on Mont Belvieu OPIS pricing and (iii) natural gas derivatives settled based on Henry Hub NYMEX and Waha Inside FERC pricing. During the year ended December 31, 2021, in connection with the Working Interest Sale, the Company entered into derivative positions on behalf of Sixth Street. Following the closing of the Working Interest Sale on July 1, 2021, all of the hedges entered into on behalf of Sixth Street were novated to Sixth Street as intended. During the year ended December 31, 2021, the Company completed a hedge restructuring by (i) selling 2,254,500 calendar year 2021 $55.00 per barrel Brent ICE puts, which volumetrically offset existing calendar year 2021 $55.00 per barrel Brent ICE puts, and receiving aggregate premiums of $9.0 million at inception of the contracts and (ii) entering into 2,254,500 calendar year 2021 Brent ICE swaps at a weighted-average price of $55.09 per barrel. Associated with the aforementioned existing calendar year 2021 $55.00 per barrel Brent ICE puts, which were entered into during 2020, were $50.6 million in aggregate premiums paid at the inception of the contracts. During the year ended December 31, 2020, the Company completed hedge restructurings by (i) early terminating collars and entering into new swaps and (ii) early terminating swaps resulting in proceeds of $6.3 million. The following table details the commodity derivatives that were terminated: Aggregate volumes (Bbl) Weighted-average floor price ($/Bbl) Weighted-average ceiling price ($/Bbl) Contract period WTI NYMEX - Swaps 389,180 $ 60.25 $ 60.25 September 2020 - December 2020 WTI NYMEX - Collars 912,500 $ 45.00 $ 71.00 January 2021 - December 2021 During the year ended December 31, 2019, the Company completed hedge restructurings by early terminating puts and collars and entering into new swaps. The Company paid a net termination amount of $5.4 million that included the full settlement of the deferred premiums associated with a portion of these early-terminated puts and collars. The present value of these deferred premiums, classified under Level 3 of the fair value hierarchy, upon their early termination was $7.2 million. See Note 11 for information about the fair value hierarchy levels. The following table details the commodity derivatives that were terminated: Aggregate volumes (Bbl) Weighted-average floor price ($/Bbl) Weighted-average ceiling price ($/Bbl) Contract period WTI NYMEX - Puts 5,087,500 $ 46.03 $ — April 2019 - December 2019 WTI NYMEX - Put 366,000 $ 45.00 $ — January 2020 - December 2020 WTI NYMEX - Collars 1,134,600 $ 45.00 $ 76.13 January 2020 - December 2020 The following table summarizes open commodity derivative positions as of December 31, 2021, for commodity derivatives that were entered into through December 31, 2021, for the settlement periods presented: Year 2022 Year 2023 Oil: WTI NYMEX - Swaps: Volume (Bbl) 1,085,000 — Weighted-average price ($/Bbl) $ 67.77 $ — WTI NYMEX - Collars: Volume (Bbl) 3,394,500 730,000 Weighted-average floor price ($/Bbl) $ 58.23 $ 60.00 Weighted-average ceiling price ($/Bbl) $ 69.39 $ 75.66 Total WTI NYMEX: Total volume (Bbl) 4,479,500 730,000 Weighted-average floor price ($/Bbl) $ 60.54 $ 60.00 Weighted-average ceiling price ($/Bbl) $ 69.00 $ 75.66 Brent ICE - Swaps: Volume (Bbl) 4,124,500 — Weighted-average price ($/Bbl) $ 48.34 $ — Brent ICE - Collars: Volume (Bbl) 1,551,250 — Weighted-average floor price ($/Bbl) $ 56.65 $ — Weighted-average ceiling price ($/Bbl) $ 65.44 $ — Total Brent ICE: Total volume (Bbl) 5,675,750 — Weighted-average floor price ($/Bbl) $ 50.61 $ — Weighted-average ceiling price ($/Bbl) $ 53.01 $ — NGL: Purity Ethane - Swaps: Volume (Bbl) 1,533,000 — Weighted-average price ($/Bbl) $ 11.42 $ — Non-TET Propane - Swaps: Volume (Bbl) 1,168,000 — Weighted-average price ($/Bbl) $ 35.91 $ — Non-TET Normal Butane - Swaps: Volume (Bbl) 365,000 — Weighted-average price ($/Bbl) $ 41.58 $ — Non-TET Isobutane - Swaps: Volume (Bbl) 109,500 — Weighted-average price ($/Bbl) $ 42.00 $ — Non-TET Natural Gasoline - Swaps: Volume (Bbl) 365,000 — Weighted-average price ($/Bbl) $ 60.65 $ — Total NGL volume (Bbl) 3,540,500 — CONTINUED ON NEXT PAGE Year 2022 Year 2023 Natural gas: Henry Hub NYMEX - Swaps: Volume (MMBtu) 3,650,000 — Weighted-average price ($/MMBtu) $ 2.73 $ — Henry Hub NYMEX - Collars: Volume (MMBtu) 29,200,000 3,650,000 Weighted-average floor price ($/MMBtu) $ 3.09 $ 3.00 Weighted-average ceiling price ($/MMBtu) $ 3.84 $ 4.45 Total Henry Hub NYMEX: Total volume (MMBtu) 32,850,000 3,650,000 Weighted-average floor price ($/MMBtu) $ 3.05 $ 3.00 Weighted-average ceiling price ($/MMBtu) $ 3.71 $ 4.45 Waha Inside FERC to Henry Hub NYMEX - Basis Swaps: Volume (MMBtu) 29,017,500 — Weighted-average differential ($/MMBtu) $ (0.36) $ — b. Interest rate Due to the inherent volatility in interest rates, the Company has entered into an interest rate derivative swap to hedge interest rate risk associated with a portion of the Company's anticipated outstanding debt under the Senior Secured Credit Facility. The Company will pay a fixed rate over the contract term for that portion. By removing a portion of the interest rate volatility associated with anticipated outstanding debt, the Company expects to mitigate, but not eliminate, the potential effects of variability in cash flows from operations. The following table summarizes the Company's interest rate derivative: Notional amount Fixed rate Contract period LIBOR - Swap $ 100,000 0.345 % April 16, 2020 - April 18, 2022 c. Contingent consideration The Sixth Street PSA provided for potential contingent payments to be paid to the Company if certain cash flow targets are met related to divested oil and natural gas property operations. The Sixth Street Contingent Consideration provides the Company with the right to receive up to a maximum of $93.7 million in additional cash consideration, comprised of potential quarterly payments through June 2027 totaling up to $38.7 million and a potential balloon payment of $55.0 million in June 2027. The fair value of the Sixth Street Contingent Consideration was determined to be $33.8 million as of the Sixth Street Closing Date and $35.9 million as of December 31, 2021. The Company's asset acquisition of oil and natural gas properties that closed on April 30, 2020 provided for potential contingent payments to be paid by the Company if the arithmetic average of the monthly settlement WTI NYMEX prices exceed certain thresholds for the contingency period beginning on January 1, 2021 and ending on the earlier of December 31, 2022 or the date the counterparty has received the maximum consideration of $1.2 million. As the maximum thresholds were met, the Company paid the maximum amount of the $1.2 million contingent consideration to the counterparty during the year ended December 31, 2021. The Company's acquisition of oil and natural gas properties that closed on December 12, 2019 provided for a potential contingent payment. If the arithmetic average of the monthly settlement WTI NYMEX prices exceeded a certain threshold for the contingency period beginning on January 1, 2020 and ending on December 31, 2020, the Company would have been required to pay to the counterparty an amount equal to $20.0 million. As the provisions for this contingent payment were not met, no payment by the Company was required. |
Fair value measurements
Fair value measurements | 12 Months Ended |
Dec. 31, 2021 | |
Fair Value Disclosures [Abstract] | |
Fair value measurements | Note 11 Fair value measurements The Company has categorized its assets and liabilities measured at fair value, based on the priority of inputs to the valuation techniques, into a three-level fair value hierarchy. The fair value hierarchy gives the highest priority to quoted prices in active markets for identical assets or liabilities (Level 1) and the lowest priority to unobservable inputs (Level 3). Assets and liabilities recorded at fair value on the consolidated balance sheets are categorized based on inputs to the valuation techniques as follows: Level 1— Assets and liabilities recorded at fair value for which values are based on unadjusted quoted prices for identical assets or liabilities in an active market that management has the ability to access. Active markets are considered to be those in which transactions for the assets or liabilities occur in sufficient frequency and volume to provide pricing information on an ongoing basis. Level 2— Assets and liabilities recorded at fair value for which values are based on quoted prices in markets that are not active or model inputs that are observable either directly or indirectly for substantially the full term of the assets or liabilities. Substantially all of these inputs are observable in the marketplace throughout the full term of the price risk management instrument and can be derived from observable data or supported by observable levels at which transactions are executed in the marketplace. Level 3— Assets and liabilities recorded at fair value for which values are based on prices or valuation techniques that require inputs that are both unobservable and significant to the overall fair value measurement. Unobservable inputs are not corroborated by market data. These inputs reflect management's own assumptions about the assumptions a market participant would use in pricing the asset or liability. a. Fair value measurement on a recurring basis For further discussion of the Company's derivatives, see Notes (i) 2.e for the Company's significant accounting policies for derivatives, (ii) 10 for derivatives and (iii) 18.b for derivatives subsequent events. Balance sheet presentation The following tables present the Company's derivatives by (i) balance sheet classification, (ii) derivative type and (iii) fair value hierarchy level, and provide a total, on a gross basis and a net basis reflected in "Derivatives" on the consolidated balance sheets as of the dates presented: December 31, 2021 (in thousands) Level 1 Level 2 Level 3 Total gross fair value Amounts offset Net fair value presented on the consolidated balance sheets Assets: Current: Commodity - Oil $ — $ 14,653 $ — $ 14,653 $ (14,653) $ — Commodity - NGL — — — — — — Commodity - Natural gas — 7,018 — 7,018 (7,018) — Contingent consideration — — 4,346 4,346 — 4,346 Noncurrent: Commodity - Oil $ — $ 1,196 $ — $ 1,196 $ — $ 1,196 Commodity - NGL — — — — — — Commodity - Natural gas — 252 — 252 — 252 Contingent consideration — — 31,515 31,515 — 31,515 Liabilities: Current: Commodity - Oil $ — $ (167,749) $ — $ (167,749) $ 14,653 $ (153,096) Commodity - NGL — (17,581) — (17,581) — (17,581) Commodity - Natural gas — (16,098) — (16,098) 7,018 (9,080) Interest rate - LIBOR — (52) — (52) — (52) Contingent consideration — — — — — — Noncurrent: Commodity - Oil $ — $ — $ — $ — $ — $ — Commodity - NGL — — — — — — Commodity - Natural gas — — — — — — Interest rate - LIBOR — — — — — — Contingent consideration — — — — — — Net derivative liability positions $ — $ (178,361) $ 35,861 $ (142,500) $ — $ (142,500) December 31, 2020 (in thousands) Level 1 Level 2 Level 3 Total gross fair value Amounts offset Net fair value presented on the consolidated balance sheets Assets: Current: Commodity - Oil $ — $ 32,958 $ — $ 32,958 $ (24,930) $ 8,028 Commodity - NGL — 2,720 — 2,720 (2,720) — Commodity - Natural gas — 521 — 521 (656) (135) Contingent consideration — — — — — — Noncurrent: Commodity - Oil $ — $ — $ — $ — $ — $ — Commodity - NGL — — — — — — Commodity - Natural gas — 535 — 535 (535) — Contingent consideration — — — — — — Liabilities: Current: Commodity - Oil $ — $ (25,118) $ — $ (25,118) $ 24,930 $ (188) Commodity - NGL — (16,185) — (16,185) 2,720 (13,465) Commodity - Natural gas — (17,958) — (17,958) 656 (17,302) Interest rate - LIBOR — (206) — (206) — (206) Contingent consideration — (665) — (665) — (665) Noncurrent: Commodity - Oil $ — $ (10,932) $ — $ (10,932) $ — $ (10,932) Commodity - NGL — — — — — — Commodity - Natural gas — (1,476) — (1,476) 535 (941) Interest rate - LIBOR — (63) — (63) — (63) Contingent consideration — (115) — (115) — (115) Net derivative liability positions $ — $ (35,984) $ — $ (35,984) $ — $ (35,984) Commodity Significant Level 2 inputs associated with the calculation of discounted cash flows used in the fair value mark-to-market analysis of commodity derivatives include each commodity derivative contract's corresponding commodity index price(s), forward price curve models for substantially similar instruments and counterparty risk-adjusted discount rates generated from a compilation of data gathered by a third-party valuation specialist. The Company reviewed the third party specialist's valuations of commodity derivatives, including the related inputs, and analyzed changes in fair values between reporting dates. The Company's deferred premiums associated with its commodity derivative contracts were categorized as Level 3, as the Company utilized a net present value calculation to determine the valuation. They were considered to be measured on a recurring basis as the commodity derivative contracts they derive from were measured on a recurring basis. As commodity derivative contracts containing deferred premiums were entered into, the Company discounted the associated deferred premium to its net present value at the contract trade date, using the Senior Secured Credit Facility rate at the trade date (input rate), and then recorded the change in net present value to interest expense over the period from trade until the final settlement date at the end of the contract. After this initial valuation, the input rate of each deferred premium was not adjusted; therefore, significant increases (decreases) in the Senior Secured Credit Facility rate would have resulted in a significantly lower (higher) fair value measurement for each new contract entered into that contained a deferred premium; however, the initial valuation for the deferred premiums already recorded would have remained unaffected. While the Company believes the sources utilized to arrive at the fair value estimates were reliable, different sources or methods could have yielded different fair value estimates. The following table summarizes the changes in net assets and liabilities for commodity derivatives classified as Level 3 measurements for the periods presented: Years ended December 31, (in thousands) 2021 2020 2019 Balance of Level 3 at beginning of year $ — $ (477) $ (16,565) Change in net present value of commodity derivative deferred premiums (1) — — (139) Settlements of commodity derivative deferred premiums (2) — 477 16,227 Balance of Level 3 at end of year $ — $ — $ (477) _____________________________________________________________________________ (1) These amounts are included in "Interest expense" on the consolidated statements of operations. (2) The amount for the year ended December 31, 2019 includes $7.2 million that represents the present value of deferred premiums settled upon their early termination. Interest rate Significant Level 2 inputs associated with the calculation of discounted cash flows used in the fair value mark-to-market analysis of the interest rate derivative include the LIBOR interest rate forward curve and a counterparty risk-adjusted discount rate generated from a compilation of data gathered by a third-party valuation specialist. The Company reviewed the third-party specialist's valuation of the interest rate derivative, including the related inputs, and analyzed changes in fair values between reporting dates. Contingent consideration Significant Level 2 inputs for the option pricing model used in the fair value mark-to-market analysis of the contingent considerations include WTI NYMEX Futures price curves, implied volatility of futures contracts and the Company's credit risk-adjusted discount rate generated from a compilation of data gathered by a third-party valuation specialist. The Company reviewed the third-party specialist's valuations, including the related inputs, and analyzed changes in fair values between the acquisition closing dates and the reporting dates. The fair values of the contingent considerations were recorded as part of the basis in the oil and natural gas properties acquired and as a contingent consideration derivative liability. At each quarterly reporting period prior to the end of the contingency periods, the Company remeasured the contingent considerations with the changes in fair value recognized in earnings. The Working Interest Sale provided for potential contingent payments to be paid to the Company. The Sixth Street Contingent Consideration associated with the Working Interest Sale was categorized as Level 3, as the Company utilized its own cash flow projections along with a risk-adjusted discount rate generated by a third-party valuation specialist to determine the valuation. The Company reviewed the third-party specialist's valuation, including the related inputs, and analyzed changes in fair values between the divestiture closing date and the reporting dates. The fair value of the Sixth Street Contingent Consideration was recorded as part of the basis in the oil and natural gas properties divested and as a contingent consideration asset. At each quarterly reporting period prior to the end of the contingency period, the Company will remeasure the Sixth Street Contingent Consideration with the changes in fair value recognized in earnings. The following table summarizes the changes in contingent consideration derivatives classified as Level 3 measurements for the periods presented: Years ended December 31, (in thousands) 2021 2020 2019 Balance of Level 3 at beginning of year $ — $ — $ — Sixth Street Contingent Consideration valuation as of Sixth Street Closing Date 33,832 — — Change in net present value of Sixth Street Contingent Consideration 2,029 — — Balance of Level 3 at end of year $ 35,861 $ — $ — The Company's acquisition of oil and natural gas properties that closed on April 30, 2020 provided for potential contingent payments to be paid by the Company. During the year ended December 31, 2021, the maximum amount of the $1.2 million contingent consideration was distributed to the counterparty. The fair value of the contingent consideration derivative liability was determined to be $0.2 million as of the April 30, 2020 acquisition date, and $0.8 million as of December 31, 2020. The Company's acquisition of oil and natural gas properties that closed on December 12, 2019 provided for a potential contingent payment to be paid by the Company. The fair value of the contingent consideration derivative liability was $6.2 million as of the December 12, 2019 acquisition date. As the provisions for this contingent payment were not met, no payment by the Company was required. See Notes 4.a, 4.b and 4.d for further discussion of the Company's acquisitions and divestitures associated with the potential contingent consideration payments. b. Fair value measurement on a nonrecurring basis See Note 2.i for the Level 2 fair value hierarchy input assumptions used in estimating the NRV of inventory, which was used to determine the $1.6 million and $1.4 million impairment expense of inventory recorded during the years ended December 31, 2021 and 2020, respectively, pertaining to line-fill and other inventories. The Company recorded $0.3 million in impairment expense of inventory during the year ended December 31, 2019, pertaining to line-fill. See Note 4.d for the Level 3 fair value hierarchy input assumptions used in estimating the fair values of assets acquired and liabilities assumed for the acquisition of oil and natural gas properties accounted for as a business combination during the year ended December 31, 2019. There were no acquisitions accounted for as business combinations during the years ended December 31, 2021 or 2020. Impairments are recorded on long-lived assets when indicators of impairment are present and the undiscounted cash flows estimated to be generated by those assets are less than the assets' carrying amount. Impairment is measured based on the excess of the carrying amount over the fair value of the asset. For purposes of fair value measurement, it was determined that the impairment of long-lived assets is classified as Level 3, based on the use of internally developed cash flow models. The Company recorded $8.2 million in impairment expense of long-lived assets during the years ended December 31, 2020, pertaining to midstream service assets. There were no long-lived asset impairments recorded during the years ended December 31, 2021 or 2019. c. Items not accounted for at fair value The carrying amounts reported on the consolidated balance sheets for cash and cash equivalents, accounts receivable, accounts payable, accrued capital expenditures, undistributed revenue and royalties and other accrued assets and liabilities approximate their fair values. The Company has not elected to account for its debt instruments at fair value. The following table presents the carrying amounts and fair values of the Company's debt as of the dates presented: December 31, 2021 December 31, 2020 (in thousands) Long-term debt Fair value (1) Long-term debt Fair value (1) January 2025 Notes $ 577,913 $ 589,471 $ 577,913 $ 499,299 January 2028 Notes 361,044 378,578 361,044 299,667 July 2029 Notes 400,000 390,000 — — Senior Secured Credit Facility 105,000 105,040 255,000 255,187 Total $ 1,443,957 $ 1,463,089 $ 1,193,957 $ 1,054,153 _____________________________________________________________________________ (1) The fair values of the outstanding notes were determined using the Level 1 fair value hierarchy quoted market prices for each respective instrument as of December 31, 2021 and 2020. The fair values of the outstanding debt under the Senior Secured Credit Facility were estimated utilizing the Level 2 fair value hierarchy pricing model for similar instruments as of December 31, 2021 and 2020. |
Net income (loss) per common sh
Net income (loss) per common share | 12 Months Ended |
Dec. 31, 2021 | |
Earnings Per Share [Abstract] | |
Net income (loss) per common share | Note 12 Net income (loss) per common share Basic and diluted net income (loss) per common share are computed by dividing net income (loss) by the weighted-average common shares outstanding for the period. Diluted net income (loss) per common share reflects the potential dilution of non-vested restricted stock awards, outstanding stock option awards, non-vested performance share awards and the non-vested outperformance share award. See Note 9.a for additional discussion of these awards. For the year ended December 31, 2021, the dilutive effects of these awards were calculated utilizing the treasury stock method. For the years ended December 31, 2020 and 2019, all of these awards were anti-dilutive due to the Company's net loss and, therefore, were excluded from the calculation of diluted net loss per common share. The following table reflects the calculations of basic and diluted (i) weighted-average common shares outstanding and (ii) net income (loss) per common share for the periods presented: Years ended December 31, (in thousands, except for per share data) 2021 2020 2019 Net income (loss) (numerator) $ 145,008 $ (874,173) $ (342,459) Weighted-average common shares outstanding (denominator) (1) : Basic 14,240 11,668 11,565 Dilutive non-vested restricted stock awards 181 — — Dilutive non-vested performance share awards (2) 43 — — Diluted 14,464 11,668 11,565 Net income (loss) per common share (1) : Basic $ 10.18 $ (74.92) $ (29.61) Diluted $ 10.03 $ (74.92) $ (29.61) _____________________________________________________________________________ (1) For the year ended December 31, 2021, the weighted-average common shares outstanding used in the computation of basic and diluted net income per share includes the effects of equity issued by the Company during the year. There was no comparable equity issued during the years ended December 31, 2020 and 2019. See Notes 4.a and 8.a for additional discussion of equity issued by the Company. (2) The dilutive effect of the non-vested performance shares for the year ended December 31, 2021 was calculated as of the end of the performance period on December 31, 2021. |
Income taxes
Income taxes | 12 Months Ended |
Dec. 31, 2021 | |
Income Tax Disclosure [Abstract] | |
Income taxes | Note 13 Income taxes The Company is subject to federal and state income taxes and the Texas franchise tax. The following table presents the "Current" and "Deferred" income tax (expense) benefit reported on the consolidated statements of operations for the periods presented: Years ended December 31, (in thousands) 2021 2020 2019 Current income tax (expense) benefit: Federal $ — $ — $ — State (1,324) — — Deferred income tax (expense) benefit: Federal — — — State (2,321) 3,946 2,588 Total income tax (expense) benefit $ (3,645) $ 3,946 $ 2,588 The deferred income tax (expense) benefit affects the net deferred tax (liability) asset. See below for the table of significant components of the Company's net deferred tax (liability) asset as of December 31, 2021, 2020 and 2019. Total income tax (expense) benefit differed from amounts computed by applying the applicable federal income tax rate of 21% for the years ended December 31, 2021, 2020 and 2019 to pre-tax earnings as a result of the following: Years ended December 31, (in thousands) 2021 2020 2019 Income tax (expense) benefit computed by applying the statutory rate $ (31,217) $ 184,405 $ 72,460 Change in deferred tax valuation allowance 45,717 (182,634) (69,316) Non-deductible equity-based compensation (13,640) — — State income tax and change in valuation allowance (3,274) 2,903 1,863 Other items (1,231) (728) (2,419) Total income tax (expense) benefit $ (3,645) $ 3,946 $ 2,588 The effective tax rate was not meaningful for the periods presented. The Company's effective tax rate is affected by changes in tax rates, valuation allowances, recurring permanent differences and by discrete items that may occur in any given year, but are not consistent from year to year. The Company is required to estimate the federal and state income taxes in each of the jurisdictions it operates in. This process involves estimating the actual current tax exposure together with assessing temporary differences resulting from differing treatment of items for tax and financial accounting purposes. These differences and the Company's net operating loss carryforwards result in deferred tax assets and liabilities. The following table presents significant components of the Company's net deferred tax (liability) asset as of the dates presented: (in thousands) December 31, 2021 December 31, 2020 Net operating loss carryforward $ 445,426 $ 444,031 Oil and natural gas properties, midstream service assets and other fixed assets (39,504) 22,231 Equity-based compensation 11,123 22,494 Derivatives 36,639 7,166 Loss on sale of assets (14,364) (8,458) Other 3,227 3,130 Net deferred tax asset before valuation allowance 442,547 490,594 Valuation allowance (443,390) (489,116) Texas net deferred tax (liability) asset (1) $ (843) $ 1,478 ___________________________________________________________________________ (1) The net deferred tax (liability) asset is included in "Other noncurrent liabilities" and "Other noncurrent assets, net" as of December 31, 2021 and 2020, respectively. The following table presents the Company's federal net operating loss carryforwards and their applicable expiration dates as of the date presented: (in thousands) December 31, 2021 2026 $ 2,741 2027 38,651 2028 228,661 2029 101,932 2030 80,963 Thereafter 1,284,150 Total expiring federal net operating loss carryforwards 1,737,098 Non-expiring federal net operating loss carryforwards 376,212 Total federal net operating loss carryforwards $ 2,113,310 The Company had federal net operating loss carryforwards totaling $2.1 billion and state of Oklahoma net operating loss carryforwards totaling $34.6 million as of December 31, 2021, which begin expiring in 2026 and 2032, respectively. Due to the passing of the Tax Act (defined below), $376.2 million of the federal net operating loss carryforwards will not expire but may be limited in future periods. If the Company were to experience an "ownership change" as determined under Section 382 of the Internal Revenue Code, the Company's ability to offset taxable income arising after the ownership change with net operating losses arising prior to the ownership change would be limited. Mainly as a result of the estimated tax gain arising from the Working Interest Sale that occurred during the year ended December 31, 2021, the Company has recorded a corresponding current tax expense of $1.3 million for Texas franchise tax. A valuation allowance is established to reduce deferred tax assets if it is determined that it is more likely than not that the related tax benefit will not be realized. On a quarterly basis, management evaluates the need for and adequacy of valuation allowances based on the expected realizability of the deferred tax assets and adjusts the amount of such allowances, if necessary. To the extent a valuation allowance is established or is increased or decreased during a period, there is a corresponding expense or reduction of expense within the tax provision in the consolidated statement of operations. During the years ended December 31, 2021 and 2020, in evaluating whether it was more likely than not that the Company's net deferred tax assets were realizable through future net income, the Company considered all available positive and negative evidence, including (i) its earnings history exclusive of the loss that created the future deductible amount coupled with evidence indicating that the loss is an aberration rather than a continuing condition, (ii) its ability to recover net operating loss carryforward deferred tax assets in future years, (iii) the existence of significant proved oil, NGL and natural gas reserves, (iv) its ability to use tax planning strategies, such as electing to capitalize intangible drilling costs as opposed to expensing such costs in order to prevent an operating loss carryforward from expiring unused and future projections of taxable income, (v) its current price protection utilizing oil, NGL and natural gas hedges, (vi) future revenue and operating cost projections that indicate it will produce more than enough taxable income to realize the deferred tax asset based on existing sales prices and cost structures and (vii) current market prices for oil, NGL and natural gas. Based on all the evidence available, the Company determined it was more likely than not that the net deferred tax assets were not realizable. As of December 31, 2021, a total valuation allowance of $443.4 million has been recorded to offset the Company's federal and Oklahoma net deferred tax assets resulting in a Texas net deferred tax liability of $0.8 million that is included in "Other noncurrent liabilities, net" on the consolidated balance sheets. On December 22, 2017, the President signed into law Public Law No. 115-97, a comprehensive tax reform bill commonly referred to as the Tax Cuts and Jobs Act (the "Tax Act"). With the passage of the Tax Act, the Alternative Minimum Tax ("AMT") on corporations was repealed and a provision was added allowing corporations to offset future tax liabilities by the amount of AMT paid with an AMT credit carryforward. The Coronavirus Aid, Relief, and Economic Security Act, enacted March 27, 2020 ("CARES Act"), modified the opportunity for corporations to receive the AMT carryover refunds by adding in a provision where the AMT credit carryforwards do not expire and are fully refundable with the filing of the Company's 2019 consolidated tax return. The Company paid AMT during the year ended December 31, 2017, creating an AMT credit carryforward in the amount of $4.1 million, of which $2.0 million was received during the year ended December 31, 2019 and the remaining $2.1 million was received during the year ended December 31, 2020. The Company files a single return. The Company's income tax returns for the years 2018 through 2021 remain open and subject to examination by federal tax authorities and/or the tax authorities in Oklahoma and Texas, which are the jurisdictions where the Company has operations. Additionally, the statute of limitations for examination of federal net operating loss carryforwards typically does not begin to run until the year the attribute is utilized in a tax return. See Note 2.q for the Company's significant accounting policies for income taxes. |
Credit risk
Credit risk | 12 Months Ended |
Dec. 31, 2021 | |
Risks and Uncertainties [Abstract] | |
Credit risk | Note 14 Credit risk Financial instruments that potentially subject the Company to a concentration of credit risk consist of cash and cash equivalents, accounts receivable and derivatives. The Company places its cash and cash equivalents with high credit quality financial institutions. The Company uses commodity and interest rate derivatives to hedge its exposure to commodity prices and interest rate volatility, respectively. These transactions expose the Company to potential credit risk from its counterparties. The Company has entered into International Swaps and Derivatives Association Master Agreements ("ISDA Agreements") with each of its commodity and interest rate derivative counterparties, each of whom is also a lender in its Senior Secured Credit Facility, which, together with hedge agreements with lenders under such facility, is secured by its oil, NGL and natural gas reserves; therefore, the Company is not required to post any additional collateral. The Company did not require collateral from its commodity and interest rate derivative counterparties. The terms of the ISDA Agreements provide the non-defaulting or non-affected party the right to terminate the agreement upon the occurrence of certain events of default and termination events by a party and also provide for the marking to market of outstanding positions and the offset of the mark to market amounts owed to and by the parties (and in certain cases, the affiliates of the non-defaulting or non-affected party) upon termination; therefore, the credit risk associated with its commodity and interest rate derivative counterparties is somewhat mitigated. The Company minimizes the credit risk in commodity and interest rate derivatives by: (i) limiting its exposure to any single counterparty, (ii) entering into commodity and interest rate derivatives only with counterparties that meet its minimum credit quality standard or have a guarantee from an affiliate that meets its minimum credit quality standard and (iii) monitoring the creditworthiness of its counterparties on an ongoing basis. As of December 31, 2021, the Company had a net liability of $178.4 million from the fair values of its open commodity and interest rate derivative contracts. See "Part II, Item 7A. Quantitative and Qualitative Disclosures About Market Risk" located elsewhere in this Annual Report and Notes 2.e, 10, 11.a and 18.b for additional information regarding the Company's derivatives. The Company typically sells production to a relatively limited number of customers, as is customary in the exploration, development and production business. The Company's sales of purchased oil are generally made to a few customers. The Company's joint operations accounts receivable are from a number of oil and natural gas companies, partnerships, individuals and others who own interests in the oil and natural gas properties operated by the Company. The majority of the Company's accounts receivable are unsecured. On occasion the Company requires its customers to post collateral, and the inability or failure of the Company's significant customers to meet their obligations to the Company or their insolvency or liquidation may adversely affect the Company's financial results. In the current market environment, the Company believes that it could sell its production to numerous companies, so that the loss of any one of its major purchasers would not have a material adverse effect on its financial condition and results of operations solely by reason of such loss. Additionally, management believes that any credit risk imposed by a concentration in the oil and natural gas industry is offset by the creditworthiness of the Company's customer base and industry partners. The Company routinely assesses the recoverability of all material trade and other receivables to determine collectability. See Notes 2.d and 2.n for additional information regarding the Company's accounts receivable and revenue recognition, respectively. The following table presents purchasers that individually accounted for 10% or more of the Company's oil, NGL and natural gas sales in at least one of the years presented: Years ended December 31, 2021 2020 2019 Purchaser A (1) 29 % 33 % 59 % Purchaser B 24 % 24 % 18 % Purchaser C (1) 17 % 14 % n/a (2) Purchaser D n/a (2) 10 % n/a (2) Purchaser E n/a (2) n/a (2) 15 % Purchaser F (1) 14 % n/a (2) n/a (2) _____________________________________________________________________________ (1) This purchaser of the Company's oil, NGL and natural gas sales is also a purchaser of the Company's sales of purchased oil included in the table below. (2) This purchaser did not account for 10% or greater of the Company's oil, NGL and natural gas sales. The following table presents purchasers that individually accounted for 10% or more of the Company's sales of purchased oil in at least one of the years presented: Years ended December 31, 2021 2020 2019 Purchaser A (1) 47 % 69 % 26 % Purchaser B (1) 31 % 16 % 70 % Purchaser C (1) 22 % 14 % n/a (2) _____________________________________________________________________________ (1) This purchaser of the Company's sales of purchased oil is also a purchaser of the Company's oil, NGL and natural gas sales included in the table above. |
Commitments and contingencies
Commitments and contingencies | 12 Months Ended |
Dec. 31, 2021 | |
Commitments and Contingencies Disclosure [Abstract] | |
Commitments and contingencies | Note 15 Commitments and contingencies a. Litigation From time to time, the Company is subject to various legal proceedings arising in the ordinary course of business, including proceedings for which the Company may not have insurance coverage. While many of these matters involve inherent uncertainty, as of the date hereof, the Company does not currently believe that any such legal proceedings will have a material adverse effect on the Company's business, financial position, results of operations or liquidity. During the year ended December 31, 2019, the Company finalized and received a favorable settlement of $42.5 million in connection with the Company's damage claims asserted in a previously disclosed litigation matter relating to a breach and wrongful termination of a crude oil purchase agreement. This settlement is recorded as "Litigation settlement" on the consolidated statement of operations. The Company does not anticipate receiving further payments in connection with this matter as this settlement constituted a full and final satisfaction of the Company's claims. b. Drilling rig contracts The Company enters into drilling rig contracts to ensure availability of desired rigs to facilitate drilling plans. The Company has two operating leases for terms of multiple months, both of which contain early termination clauses that require the Company to potentially pay penalties to the third parties should the Company cease drilling efforts. These penalties would negatively impact the Company's financial statements upon early contract termination. There were no penalties incurred for early contract termination for the years ended December 31, 2021, 2020 or 2019. As these drilling rig contracts are operating leases with an initial term greater than 12 months, the present value of the future commitment as of December 31, 2021 is included in current and noncurrent "Operating lease liabilities" on the consolidated balance sheet as of December 31, 2021. See Note 5 for additional discussion of the Company's leases. c. Firm sale and transportation commitments The Company has committed to deliver, for sale or transportation, fixed volumes of product under certain contractual arrangements that specify the delivery of a fixed and determinable quantity. If not fulfilled, the Company is subject to firm transportation payments on excess pipeline capacity and other contractual penalties. These commitments are normal and customary for the Company's business. In certain instances, the Company has used spot market purchases to meet its commitments in certain locations or due to favorable pricing. A portion of the Company's commitments are related to transportation commitments with a certain pipeline pertaining to the gathering of the Company's production from established acreage that extends into 2024. The Company was unable to satisfy a portion of this particular commitment with produced or purchased oil. Therefore, the Company expensed firm transportation payments on excess capacity of $4.4 million and $4.0 million during the years ended December 31, 2021 and 2020, respectively, which is recorded in "Transportation and marketing expenses" on the consolidated statements of operations. The Company had an estimated aggregate liability of firm transportation payments on excess capacity of $4.7 million and $3.5 million as of December 31, 2021 and 2020, respectively, and is included in "Accounts payable and accrued liabilities" on the consolidated balance sheets. The Company expensed other contractual penalties related to sales commitments of $0.9 million during the year ended December 31, 2019, which is recorded net with oil, NGL, and natural gas sales revenues on the consolidated statement of operations. As of December 31, 2021, future firm sale and transportation commitments of $213.3 million are expected to be satisfied and, as such, are not recorded as a liability on the consolidated balance sheet. d. Sand commitment During the year ended December 31, 2021, the Company renegotiated an agreement to take delivery of processed sand at a fixed price for one year, which is utilized in the Company's completions activities, from its sand mine that is operated by a third-party contractor. As of December 31, 2021, under the terms of this agreement, the Company is required to purchase a certain volume remaining under its commitment or it would incur a shortfall payment of $5.3 million at the end of the contract period. e. Federal and state regulations Oil and natural gas exploration, production and related operations are subject to extensive federal and state laws, rules and regulations. Failure to comply with these laws, rules and regulations can result in substantial penalties. The regulatory burden on the oil and natural gas industry increases the cost of doing business and affects profitability. The Company believes that it is in compliance with currently applicable federal and state regulations related to oil and natural gas exploration and production, and that compliance with the current regulations will not have a material adverse impact on the financial position or results of operations of the Company. These rules and regulations are frequently amended or reinterpreted; therefore, the Company is unable to predict the future cost or impact of complying with these regulations. f. Environmental The Company is subject to extensive federal, state and local environmental laws and regulations. These laws, among other things, regulate the discharge of materials into the environment and may require the Company to remove or mitigate the environmental effects of the disposal or release of petroleum or chemical substances at various sites. Environmental expenditures are expensed in the period incurred. Liabilities for expenditures of a non-capital nature are recorded when environmental assessment or remediation is probable and the costs can be reasonably estimated. Such liabilities are generally undiscounted unless the timing of cash payments is fixed and readily determinable. Management believes no materially significant liabilities of this nature existed as of December 31, 2021 or 2020. |
Related parties
Related parties | 12 Months Ended |
Dec. 31, 2021 | |
Related Party Transactions [Abstract] | |
Related parties | Note 16 Related parties a. Halliburton Beginning in 2020, the Chairman of the Company's board of directors is on the board of directors of Halliburton Company ("Halliburton"). Halliburton provides drilling and completions services to the Company. The following table presents the capital expenditures for oil and natural gas properties paid to Halliburton included in the consolidated statements of cash flows for the periods presented: Years ended December 31, (in thousands) 2021 2020 Capital expenditures for oil and natural gas properties $ 69,670 $ 63,886 |
Organizational restructurings
Organizational restructurings | 12 Months Ended |
Dec. 31, 2021 | |
Restructuring and Related Activities [Abstract] | |
Organizational restructurings | Note 17 Organizational restructurings On June 29, 2021 (the "Effective Date"), the Company committed to a company-wide reorganization effort (the “Plan”) that included a workforce reduction of 14 individuals, or approximately 5% of the workforce. The reduction in workforce was communicated to employees on the Effective Date and implemented immediately, subject to certain administrative procedures. The Plan was put in place in order to better position the Company for the future. On June 17, 2020, the Company announced organizational changes, including a workforce reduction of 22 individuals which included a senior officer, that were implemented immediately, subject to certain administrative procedures. The Company's board of directors approved the reduction in workforce in response to the COVID-19 pandemic and market conditions to reduce costs and better position the Company for the future. On September 27, 2019, in connection with the previously announced comprehensive succession planning process, the Company announced that, effective as of October 1, 2019, Randy A. Foutch would transition from his role as Chief Executive Officer. In connection with this transition and in recognition of his efforts as the Company's founder, Mr. Foutch entered into an agreement under which he received the following payments and benefits: (i) a "Founder's Bonus" of $5.9 million approved by the board of directors and (ii) 18 months of COBRA employer contributions that began on October 1, 2019. On April 2, 2019, the Company announced the retirement of two of its senior officers. Additionally, on April 8, 2019, the Company committed to a company-wide reorganization effort that included a workforce reduction of 20%, which included an executive officer. The reduction in workforce was communicated to employees on April 8, 2019 and implemented immediately, subject to certain administrative procedures. The Company's board of directors approved the reduction in workforce in response to market conditions and to reduce costs and better position the Company for the future. In connection with these organizational restructurings, the Company incurred charges comprised of compensation, tax, professional, outplacement and insurance-related expenses. The following table reflects the aggregate of these expenses, which is recorded as "Organizational restructuring expenses" on the consolidated statements of operations, for the periods presented: Years ended December 31, (in thousands) 2021 2020 2019 Organizational restructuring expenses $ 9,800 $ 4,200 $ 16,371 All equity-based compensation awards held by the affected employees were forfeited and the corresponding equity-based compensation was reversed. See Note 9.a for additional information on the associated forfeiture activity for the years ended December 31, 2021, 2020 and 2019. The following table reflects the aggregate of gross equity-based compensation expense reversals in connection with the Company's respective organizational restructurings, which is recorded in "General and administrative" on the consolidated statements of operations, for the periods presented: Years ended December 31, (in thousands) 2021 2020 2019 Gross equity-based compensation expense reversals $ (1,088) $ (793) $ (11,706) |
Subsequent events
Subsequent events | 12 Months Ended |
Dec. 31, 2021 | |
Subsequent Events [Abstract] | |
Subsequent events | Note 18 Subsequent events a. Senior Secured Credit Facility On January 14, 2022, the Company borrowed an additional $50.0 million and on January 31, 2022, the Company repaid $10.0 million on the Senior Secured Credit Facility. As a result, the outstanding balance under the Senior Secured Credit Facility was $145.0 million as of February 21, 2022. b. Commodity derivatives The following table summarizes the resulting open oil derivative positions as of December 31, 2021, updated for the derivative transactions entered into from December 31, 2021 through February 24, 2022, for the settlement periods presented: Year 2022 Year 2023 Oil: WTI NYMEX - Swaps: Volume (Bbl) 1,878,000 — Weighted-average price ($/Bbl) $ 76.11 $ — WTI NYMEX - Collars: Volume (Bbl) 3,394,500 3,632,000 Weighted-average floor price ($/Bbl) $ 58.23 $ 65.50 Weighted-average ceiling price ($/Bbl) $ 69.39 $ 79.94 Total WTI NYMEX: Total volume (Bbl) 5,272,500 3,632,000 Weighted-average floor price ($/Bbl) $ 64.60 $ 65.50 Weighted-average ceiling price ($/Bbl) $ 71.78 $ 79.94 Brent ICE - Swaps: Volume (Bbl) 4,124,500 — Weighted-average price ($/Bbl) $ 48.34 $ — Brent ICE - Collars: Volume (Bbl) 1,551,250 — Weighted-average floor price ($/Bbl) $ 56.65 $ — Weighted-average ceiling price ($/Bbl) $ 65.44 $ — Total Brent ICE: Total volume with floor (Bbl) 5,675,750 — Weighted-average floor price ($/Bbl) $ 50.61 $ — Weighted-average ceiling price ($/Bbl) $ 53.01 $ — See Note 10.a for additional discussion regarding the Company's derivatives. There has been no other derivative activity subsequent to December 31, 2021. |
Supplemental oil, NGL and natur
Supplemental oil, NGL and natural gas disclosures (unaudited) | 12 Months Ended |
Dec. 31, 2021 | |
Oil and Gas Exploration and Production Industries Disclosures [Abstract] | |
Supplemental oil, NGL and natural gas disclosures (unaudited) | Note 19 Supplemental oil, NGL and natural gas disclosures (unaudited) a. Incurred capital expenditures in oil and natural gas property acquisition, exploration and development activities The following table presents incurred capital expenditures in the acquisition, exploration and development of oil and natural gas properties, with asset retirement obligations included in evaluated property acquisition costs and development costs, for the periods presented: Years ended December 31, (in thousands) 2021 2020 2019 Property acquisition costs: Evaluated $ 899,128 $ 11,368 $ 126,372 Unevaluated 198,770 25,549 83,738 Exploration costs 33,482 17,337 19,954 Development costs 410,855 326,823 450,501 Total oil and natural gas properties incurred capital expenditures $ 1,542,235 $ 381,077 $ 680,565 b. Aggregate capitalized oil, NGL and natural gas costs The following table presents the aggregate capitalized costs related to oil, NGL and natural gas production activities with applicable accumulated depletion and impairment as of the dates presented: (in thousands) December 31, 2021 December 31, 2020 Gross capitalized costs: Evaluated properties $ 8,968,668 $ 7,874,932 Unevaluated properties not being depleted 170,033 70,020 Total gross capitalized costs 9,138,701 7,944,952 Less accumulated depletion and impairment (7,019,670) (6,817,949) Net capitalized costs $ 2,119,031 $ 1,127,003 The following table presents a summary of the unevaluated property costs not being depleted as of December 31, 2021, by year in which such costs were incurred: (in thousands) 2021 2020 2019 2018 and prior Total Unevaluated properties not being depleted $ 166,158 $ 784 $ 1,902 $ 1,189 $ 170,033 Unevaluated properties, which are not subject to depletion, are not individually significant and consist of costs for acquiring oil and natural gas leasehold where no evaluated reserves have been identified, including costs of wells being evaluated. The evaluation process associated with these properties has not been completed and therefore, the Company is unable to estimate when these costs will be included in the depletion calculation. c. Results of operations of oil, NGL and natural gas producing activities The following table presents the results of operations of oil, NGL and natural gas producing activities (excluding corporate overhead and interest costs) for the periods presented: Years ended December 31, (in thousands) 2021 2020 2019 Revenues: Oil, NGL and natural gas sales $ 1,147,143 $ 496,355 $ 706,548 Production costs: Lease operating expenses 101,994 82,020 90,786 Production and ad valorem taxes 68,742 33,050 40,712 Transportation and marketing expenses 47,916 49,927 25,397 Total production costs 218,652 164,997 156,895 Other costs: Depletion 201,691 203,492 250,857 Accretion of asset retirement obligation 4,018 4,227 3,926 Impairment expense — 889,453 620,565 Income tax expense (benefit) (1) 14,456 — (3,257) Total other costs 220,165 1,097,172 872,091 Results of operations $ 708,326 $ (765,814) $ (322,438) _____________________________________________________________________________ (1) During each of the years ended December 31, 2021, 2020 and 2019, the Company recorded valuation allowances against its deferred tax assets related to its oil, NGL and natural gas producing activities. Accordingly, the income tax expense (benefit) was computed utilizing the Company's effective tax rate of 2% for the year ended December 31, 2021, 0% for the year ended December 31, 2020 and 1% for the year ended December 31, 2019, which reflects tax deductions and tax credits and allowances relating to the oil, NGL and natural gas producing activities that are reflected in the Company's "Total income tax (expense) benefit" on the consolidated statements of operations. d. Net proved oil, NGL and natural gas reserves Ryder Scott Company, L.P. ("Ryder Scott"), the Company's independent reserve engineers, estimated 100% of the Company's proved reserves as of December 31, 2021, 2020 and 2019. In accordance with SEC regulations, the reserves as of December 31, 2021, 2020 and 2019 were estimated using the Realized Prices, which reflect adjustments to the Benchmark Prices for quality, certain transportation fees, geographical differentials, marketing bonuses or deductions and other factors affecting the price received at the delivery point. See Note 6.a for these Realized Prices. The Company's reserves are reported in three streams: oil, NGL and natural gas. The SEC has defined proved reserves as the estimated quantities of oil, NGL and natural gas that geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions. The process of estimating oil, NGL and natural gas reserves is complex, requiring significant decisions in the evaluation of available geological, geophysical, engineering and economic data. 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, material revisions to existing reserve estimates occur from time to time. Although every reasonable effort is made to ensure that reserve estimates reported represent the most accurate assessments possible, the subjective decisions and variances in available data for various properties increase the likelihood of significant changes in these estimates. If such changes are material, they could significantly affect future amortization of capitalized costs and result in impairment of assets that may be material. The following tables provide an analysis of the changes in estimated proved reserve quantities of oil, NGL and natural gas for the years ended December 31, 2021, 2020 and 2019, all of which are located within the U.S.: Year ended December 31, 2021 Oil NGL Natural gas MBOE Proved developed and undeveloped reserves: Beginning of year 67,759 100,922 657,284 278,228 Revisions of previous estimates 4,740 16,952 102,080 38,709 Extensions, discoveries and other additions 10,354 5,269 22,479 19,369 Acquisitions of reserves in place 65,572 19,711 90,023 100,286 Divestitures of reserves in place (15,904) (34,129) (228,546) (88,125) Production (11,619) (8,678) (57,175) (29,827) End of year 120,902 100,047 586,145 318,640 Proved developed reserves: Beginning of year 51,751 96,251 633,503 253,586 End of year 70,727 78,908 494,476 232,048 Proved undeveloped reserves: Beginning of year 16,008 4,671 23,781 24,642 End of year 50,175 21,139 91,669 86,592 Year ended December 31, 2020 Oil NGL Natural gas MBOE Proved developed and undeveloped reserves: Beginning of year 78,639 102,198 675,237 293,377 Revisions of previous estimates (10,517) 6,218 34,376 1,430 Extensions, discoveries and other additions 4,282 1,811 10,772 7,888 Acquisitions of reserves in place 5,182 1,310 6,948 7,650 Production (9,827) (10,615) (70,049) (32,117) End of year 67,759 100,922 657,284 278,228 Proved developed reserves: Beginning of year 52,711 90,861 600,334 243,628 End of year 51,751 96,251 633,503 253,586 Proved undeveloped reserves: Beginning of year 25,928 11,337 74,903 49,749 End of year 16,008 4,671 23,781 24,642 Year ended December 31, 2019 Oil NGL Natural gas MBOE Proved developed and undeveloped reserves: Beginning of year 61,894 86,647 537,756 238,167 Revisions of previous estimates (7,865) 5,301 69,678 9,049 Extensions, discoveries and other additions 13,573 12,614 83,345 40,078 Acquisitions of reserves in place 21,413 6,754 44,627 35,605 Production (10,376) (9,118) (60,169) (29,522) End of year 78,639 102,198 675,237 293,377 Proved developed reserves: Beginning of year 55,893 79,241 491,828 217,105 End of year 52,711 90,861 600,334 243,628 Proved undeveloped reserves: Beginning of year 6,001 7,406 45,928 21,062 End of year 25,928 11,337 74,903 49,749 The following discussion is for the year ended December 31, 2021. The Company's positive revision of 38,709 MBOE of previously estimated quantities consisted of (i) 3,622 MBOE of negative revisions from performance of proved developed producing wells, (ii) 2,885 MBOE of negative revisions from a decrease in previously estimated quantities of proved undeveloped locations, (iii) 37,341 MBOE of positive revisions from an increase in the Realized Prices for oil, NGL and natural gas and other changes to proved wells and (iv) 7,875 MBOE of positive revisions due to proved undeveloped locations that were removed from the development plan in prior years. Six of these locations became proved developed producing wells in 2021 and twelve were revised back to proved undeveloped reserves as they are now economically producible due to increased commodity prices and increases in lateral lengths. Extensions, discoveries and other additions of 19,369 MBOE consisted of (i) 6,724 MBOE that resulted from new wells drilled and (ii) 12,645 MBOE that resulted from new horizontal proved undeveloped locations added in the Company's acreage in Howard and western Glasscock Counties. Sales of reserves of 88,125 MBOE attributed to the divestment of 37.5% interest of certain proved developed producing wells in Reagan and Glasscock counties. Acquisitions of reserves in place of 100,286 MBOE consisted of (i) 47,310 MBOE from new proved developed wells (ii) 52,976 MBOE from new proved undeveloped locations in Howard and western Glasscock Counties. The following discussion is for the year ended December 31, 2020. The Company's positive revision of 1,430 MBOE of previously estimated quantities consisted of (i) 29,080 MBOE of positive revisions from performance of proved developed producing wells, (ii) 3,140 MBOE of negative revisions from a decrease in previously estimated quantities of proved undeveloped locations, (iii) 8,245 MBOE of negative revisions due to proved undeveloped locations that were removed due to year-end pricing and (iv) 16,265 MBOE of negative revisions from a decrease in the Realized Prices for oil, NGL and natural gas and other changes to proved wells. Extensions, discoveries and other additions of 7,888 MBOE consisted of (i) 5,347 MBOE that resulted from new wells drilled and (ii) 2,541 MBOE that resulted from new horizontal proved undeveloped locations added in the Company's Howard County, Texas acreage. Acquisitions of reserves in place of 7,650 MBOE consisted of (i) 367 MBOE from new proved developed producing wells and (ii) 4,016 MBOE from additional acreage acquired under proved locations in Howard County and (iii) 3,267 MBOE from new proved undeveloped locations in Howard County. The following discussion is for the year ended December 31, 2019. The Company's positive revision of 9,049 MBOE of previously estimated quantities consisted of (i) 20,858 MBOE of positive revisions from performance of proved developed producing wells, (ii) 12,417 MBOE of negative revisions from a decrease in the Realized Prices for oil, NGL and natural gas and other changes to proved developed producing wells and (iii) 608 MBOE of positive revisions due to proved undeveloped locations that were removed from the development plan in prior years. Extensions, discoveries and other additions of 40,078 MBOE consisted of (i) 24,629 MBOE that resulted from new wells drilled and (ii) 15,449 MBOE that resulted from new horizontal proved undeveloped locations added in our established acreage. Acquisitions of reserves in place of 35,605 MBOE consisted of (i) 1,306 MBOE from new proved developed producing wells and (ii) 34,299 MBOE from 86 new proved undeveloped locations in Howard and western Glasscock Counties of Texas. e. Standardized measure of discounted future net cash flows The standardized measure of discounted future net cash flows does not purport to be, nor should it be interpreted to present, the fair value of the oil, NGL and natural gas reserves of the property. An estimate of fair value would take into account, among other things, the recovery of reserves not presently classified as proved, the value of proved properties and consideration of expected future economic and operating conditions. The estimates of future cash flows and future production and development costs as of December 31, 2021, 2020 and 2019 are based on the Realized Prices, which reflect adjustments to the Benchmark Prices for quality, certain transportation fees, geographical differentials, marketing bonuses or deductions and other factors affecting the price received at the delivery point. All Realized Prices are held flat over the forecast period for all reserve categories in calculating the discounted future net cash flows. Any effect from the Company's commodity hedges is excluded. In accordance with SEC regulations, the proved reserves were anticipated to be economically producible from the "as of date" forward based on existing economic conditions, including prices and costs at which economic producibility from a reservoir was determined. These costs, held flat over the forecast period, include development costs, operating costs, ad valorem and production taxes and abandonment costs after salvage. Future income tax expenses are computed using the appropriate year-end statutory tax rates applied to the future pretax net cash flows from proved oil, NGL and natural gas reserves, less the tax basis of the Company's oil and natural gas properties. The estimated future net cash flows are then discounted at a rate of 10%. The Company's unamortized cost of evaluated oil and natural gas properties being depleted exceeded the full cost ceiling for each of the quarterly periods in 2020 and for the third and fourth quarters of 2019 and, as such, the Company recorded non-cash full cost ceiling impairments totaling $889.5 million and $620.6 million during the years ended December 31, 2020 and 2019, respectively. No full cost ceiling impairment was recorded for the year ended December 31, 2021. See Note 6.a for discussion of the Benchmark Prices, Realized Prices and the 2020 and 2019 full cost ceiling impairments recorded. The following table presents the standardized measure of discounted future net cash flows relating to proved oil, NGL and natural gas reserves for the periods presented: Years ended December 31, (in thousands) 2021 2020 2019 Future cash inflows $ 11,846,148 $ 3,824,104 $ 5,702,580 Future production costs (3,595,524) (1,740,537) (1,994,732) Future development costs (1,064,527) (351,568) (615,839) Future income tax expenses (774,461) (20,076) (24,392) Future net cash flows 6,411,636 1,711,923 3,067,617 10% discount for estimated timing of cash flows (2,986,324) (697,069) (1,405,356) Standardized measure of discounted future net cash flows $ 3,425,312 $ 1,014,854 $ 1,662,261 It is not intended that the FASB's standardized measure of discounted future net cash flows represent the fair market value of the Company's proved reserves. The Company cautions that the disclosures shown are based on estimates of proved reserve quantities and future production schedules which are inherently imprecise and subject to revision, and the 10% discount rate is arbitrary. In addition, prices and costs as of the measurement date are used in the determinations, and no value may be assigned to probable or possible reserves. The following table presents the changes in the standardized measure of discounted future net cash flows relating to proved oil, NGL and natural gas reserves for the periods presented: Years ended December 31, (in thousands) 2021 2020 2019 Standardized measure of discounted future net cash flows, beginning of year $ 1,014,854 $ 1,662,261 $ 2,114,237 Changes in the year resulting from: Sales, less production costs (934,440) (331,358) (549,653) Revisions of previous quantity estimates 426,060 199 36,182 Extensions, discoveries and other additions 293,511 60,004 361,479 Net change in prices and production costs 1,572,662 (770,885) (900,019) Changes in estimated future development costs 134,091 64,146 14,876 Previously estimated development incurred capital expenditures during the period 169,376 186,261 158,631 Acquisitions of reserves in place 1,509,087 14,208 207,636 Divestitures of reserves in place (369,601) — — Accretion of discount 102,607 167,227 217,119 Net change in income taxes (279,722) (1,205) 46,939 Timing differences and other (213,173) (36,004) (45,166) Standardized measure of discounted future net cash flows, end of year $ 3,425,312 $ 1,014,854 $ 1,662,261 Estimates of economically recoverable oil, NGL and natural gas reserves and of future net cash flows are based upon a number of variable factors and assumptions, all of which are, to some degree, subjective and may vary considerably from actual results. Therefore, actual production, revenues, development and operating expenditures may not occur as estimated. The reserve data are estimates only, are subject to many uncertainties and are based on data gained from production histories and on assumptions as to geologic formations and other matters. Actual quantities of oil, NGL and natural gas may differ materially from the amounts estimated. |
Supplemental quarterly financia
Supplemental quarterly financial data (unaudited) | 12 Months Ended |
Dec. 31, 2021 | |
Quarterly Financial Information Disclosure [Abstract] | |
Supplemental quarterly financial data (unaudited) | Note 20 Supplemental quarterly financial data (unaudited) The below quarterly financial data is being provided in consideration of the Company's 1-for-20 reverse stock split effective June 1, 2020, and the associated material retrospective adjustment to first-quarter 2020 basic and diluted net income per common share. The Company's results by quarter for the periods presented are as follows: December 31, 2021 (in thousands, except per share data) First Second Third Fourth Revenues $ 250,230 $ 294,371 $ 379,250 $ 470,224 Operating income $ 102,803 $ 108,347 $ 265,736 $ 243,449 Net income (loss) $ (75,439) $ (132,661) $ 136,832 $ 216,276 Net income (loss) per common share: Basic $ (6.33) $ (10.47) $ 8.68 $ 13.07 Diluted $ (6.33) $ (10.47) $ 8.56 $ 12.84 December 31, 2020 (in thousands, except per share data) First Quarter (1) Second Quarter (1) Third Quarter (1) Fourth Quarter (1) Revenues $ 204,992 $ 110,588 $ 173,547 $ 188,065 Operating loss $ (181,972) $ (434,052) $ (167,678) $ (78,031) Net income (loss) $ 74,646 $ (545,455) $ (237,432) $ (165,932) Net income (loss) per common share (2) : Basic $ 6.43 $ (46.75) $ (20.32) $ (14.18) Diluted $ 6.39 $ (46.75) $ (20.32) $ (14.18) ______________________________________________________________________________ (1) See Note 6.a for discussion of the Company's full cost ceiling impairments recorded during the year ended December 31, 2020. (2) Per share data was retroactively adjusted to reflect the Company's 1-for-20 reverse stock split effective June 1, 2020, as described in Note 8.b. |
Basis of presentation and sig_2
Basis of presentation and significant accounting policies (Policies) | 12 Months Ended |
Dec. 31, 2021 | |
Accounting Policies [Abstract] | |
Basis of presentation | The accompanying consolidated financial statements were derived from the historical accounting records of the Company and reflect the historical financial position, results of operations and cash flows for the periods described herein. The accompanying consolidated financial statements have been prepared in accordance with accounting principles generally accepted in the United States of America ("GAAP"). All material intercompany transactions and account balances have been eliminated in the consolidation of accounts. |
Use of estimates in the preparation of consolidated financial statements | The preparation of the accompanying consolidated financial statements in conformity with GAAP requires management to make estimates and assumptions about future events. These estimates and the underlying assumptions affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Although management believes these estimates are reasonable, actual results could differ.Significant estimates include, but are not limited to, (i) volumes of the Company's reserves of oil, natural gas liquids ("NGL") and natural gas, (ii) future cash flows from oil and natural gas properties, (iii) depletion, depreciation and amortization, (iv) impairments, (v) asset retirement obligations, (vi) equity-based compensation, (vii) deferred income taxes, (viii) fair values of assets acquired and liabilities assumed in an acquisition, (ix) fair values of derivatives and deferred premiums and (x) contingent assets or liabilities. As fair value is a market-based measurement, it is determined based on the assumptions that would be used by market participants. These estimates and assumptions are based on management's best judgment. Management evaluates its estimates and assumptions on an ongoing basis using historical experience and other factors, including the current economic environment. Such estimates and assumptions are adjusted when facts and circumstances dictate. Illiquid credit markets and volatile equity and energy markets may increase the uncertainty inherent in such estimates and assumptions. Management believes its estimates and assumptions to be reasonable under the circumstances. As future events and their effects cannot be determined with precision, actual values and results could differ from these estimates. Any changes in estimates resulting from future changes in the economic environment will be reflected in the financial statements in future periods. |
Cash and cash equivalents | The Company defines cash and cash equivalents to include cash on hand, cash in bank accounts and highly liquid investments with original maturities of three months or less. The Company maintains cash and cash equivalents in bank deposit accounts and money market funds that may not be federally insured. The Company has not experienced any losses in such accounts and believes it is not exposed to any significant credit risk on such accounts. |
Accounts receivable | The Company sells its produced oil, NGL and natural gas and purchased oil to various customers and participates with other parties in the development and operation of oil and natural gas properties. The Company maintains an allowance for expected credit losses inherent in its accounts receivable portfolio. In establishing the required allowance, management considers significant factors such as historical losses, current receivables aging, the debtors' current ability to pay its obligation to the Company and existing industry and economic data. Account balances are charged off against the allowance after all means of collection have been exhausted and the potential for recovery is remote, and payments subsequently received on such balances are credited to the allowance. See Note 14 for discussion regarding the Company's exposure to credit risk. |
Derivatives | Derivatives are recorded at fair value and are presented on a net basis in "Derivatives" on the consolidated balance sheets as assets and/or liabilities. The Company records the fair value of derivatives, net by counterparty where the right of offset exists. The Company determines the fair value of its derivatives using fair value hierarchy level inputs to its valuation techniques. The Company's derivatives were not designated as hedges for accounting purposes, and the Company does not enter into such instruments for speculative trading purposes. Accordingly, the changes in fair value are recognized in "Gain (loss) on derivatives, net" under "Non-operating income (expense)" on the consolidated statements of operations. |
Oil and natural gas properties | The Company uses the full cost method of accounting for its oil and natural gas properties. Under this method, all acquisition, exploration and development costs, including certain employee-related costs, incurred for the purpose of acquiring, exploring for or developing oil and natural gas properties, are capitalized and, once evaluated, depleted on a composite unit-of-production method based on estimates of proved oil, NGL and natural gas reserves. The depletion base includes estimated future development costs and dismantlement, restoration and abandonment costs, net of estimated salvage values. Capitalized costs include the cost of drilling and equipping productive wells, dry hole costs, lease acquisition costs, delay rentals and other costs related to such activities. Costs, including employee-related costs, associated with production and general corporate activities are expensed in the period incurred. The Company excludes unevaluated property acquisition costs and exploration costs from the depletion calculation until it is determined whether or not proved reserves can be assigned to the properties. The Company capitalizes a portion of its interest costs to its unevaluated properties and such costs become subject to depletion when proved reserves can be assigned to the associated properties. All items classified as unevaluated properties are assessed on a quarterly basis for possible impairment. The assessment includes consideration of the following factors, among others: intent to drill, remaining lease term, geological and geophysical evaluations, drilling results and activity, the assignment of proved reserves and the economic viability of development if proved reserves are assigned. During any period in which these factors indicate an impairment, the cumulative drilling incurred capital expenditures to date for such property and all or a portion of the associated leasehold costs are transferred to the full cost pool and are then subject to depletion. |
Leases | The Company recognizes operating lease right-of-use assets and operating lease liabilities on the consolidated balance sheets for operating leases with an initial term greater than 12 months. The Company determines whether a contract is or contains a lease at inception of the contract, based on answers to a series of questions that address whether an identified asset exists and whether the Company has the right to obtain substantially all of the benefit of the asset and to control its use over the full term of the agreement. When available, the Company uses the rate implicit in the lease to discount lease payments to present value; however, most of the Company's leases do not provide a readily determinable implicit rate. In such cases, the Company is required to use its incremental borrowing rate ("IBR"). The Company determines its IBR using both a "credit notching" approach and a "recovery method" approach. The results of these approaches are then weighted equally and averaged in order to determine the concluded IBR. This concluded IBR is utilized to discount the lease payments based on information available at lease commencement. There are no material residual value guarantees, nor any restrictions or covenants included in the Company's lease agreements. Mineral leases, including oil and natural gas leases granting the right to explore for those natural resources and rights to use the land in which those natural resources are contained, are not included in the scope of Accounting Standards Codification ("ASC") 842, Leases . The Company has recognized operating lease right-of-use assets and operating lease liabilities on the consolidated balance sheets for leases of commercial real estate with lease terms extending into 2027 and drilling, completion, production and other equipment leases with lease terms extending into 2022. The Company has various other drilling, completion and production equipment leases on a short-term basis which are reflected in short-term lease costs. The Company's lease costs include those that are recognized in net income (loss) during the period and capitalized as part of the cost of another asset in accordance with other GAAP. The lease costs related to drilling, completion and production activities are reflected at the Company's net ownership, which is consistent with the principals of proportional consolidation, and lease commitments are reflected on a gross basis. As of December 31, 2021, the Company had an average working interest of 96% in wells associated with Laredo's active drilling program over the next 12 months. Certain of the Company's leases include provisions for variable payments. These variable payments are typically determined based on a measure of throughput, actual days or another measure of usage. For our drilling rigs, the variable lease costs include the payments that depend on the performance or usage of the underlying asset, the costs to move and the costs to repair the drilling rigs. For certain of our commercial office buildings, utilities and common area, the variable lease costs are the variable maintenance charges. For our equipment leases, the variable lease costs are the amounts incurred under our contracts that are beyond the minimum rental fee, inclusive of maintenance. The Company subleases certain office space to third parties but remains the primary obligor under the head lease. The lease terms on those subleases each contain renewal options that do not extend past the term of the head lease. The subleases do not contain residual value guarantees. Sublease income is recognized based on the contract terms and is included as a reduction of lease expense under the head lease. Certain of the Company's operating lease right-of-use asset classes include options to renew on a month-to-month basis. The Company considers contract-based, asset-based, market-based and entity-based factors to determine the term over which it is reasonably certain to extend the lease in determining its right-of-use assets and liabilities. The Company's material leases do not include options to purchase the leased property. |
Inventory | The Company has the following types of inventory: (i) materials and supplies inventory used in production activities of oil and natural gas properties and midstream service assets, (ii) frac pit water inventory used in developing oil and natural gas properties and (iii) line-fill in third-party pipelines, which is the minimum volume of product in a pipeline system that enables the system to operate, and is generally not available to be withdrawn from the pipeline until the expiration of the transportation contract. All inventory is carried at the lower of cost or net realizable value ("NRV"), with cost determined using the weighted-average cost method, and is included in "Other current assets" and "Other noncurrent assets, net" on the consolidated balance sheets. The NRV for materials and supplies inventory and frac pit water inventory is estimated utilizing a replacement cost approach (Level 2). The NRV for line-fill in third-party pipelines is estimated utilizing a quoted market price adjusted for regional price differentials (Level 2). |
Debt issuance costs | Debt issuance costs, which are recorded at cost, net of amortization, are amortized over the life of the respective debt agreements utilizing the straight-line method. |
Asset retirement obligations | Asset retirement obligations associated with the retirement of tangible long-lived assets are recognized as a liability in the period in which they are incurred and become determinable. The associated asset retirement costs are part of the carrying amount of the long-lived asset. Subsequently, the asset retirement cost included in the carrying amount of the related long-lived asset is expensed through depletion, or for midstream service assets through depreciation. Changes in the liability due to the passage of time are recognized as an increase in the carrying amount of the liability and accretion expense. The fair value of additions to the asset retirement obligation liability is measured using valuation techniques consistent with the income approach, which converts future cash flows into a single discounted amount. Significant inputs to the valuation include: (i) estimated plug and abandonment or removal and remediation cost per well or midstream service asset based on Company experience, if any, in accordance with applicable state laws, (ii) estimated remaining life per well or midstream service asset, (iii) future inflation factors and (iv) the Company's average credit-adjusted risk-free rate. Inherent in the fair value calculation of asset retirement obligations are numerous assumptions and judgments including, in addition to those noted above, the ultimate settlement of these amounts, the ultimate timing of such settlement and changes in technology, regulatory, political, environmental, safety and public relations matters. To the extent future revisions to these assumptions impact the fair value of the existing asset retirement obligation liability, an adjustment will be made to the asset balance. |
Fair value measurements | The carrying amounts reported on the consolidated balance sheets for cash and cash equivalents, accounts receivable, accounts payable, accrued capital expenditures, undistributed revenue and royalties and other accrued assets and liabilities approximate their fair values. The Company has categorized its assets and liabilities measured at fair value, based on the priority of inputs to the valuation techniques, into a three-level fair value hierarchy. The fair value hierarchy gives the highest priority to quoted prices in active markets for identical assets or liabilities (Level 1) and the lowest priority to unobservable inputs (Level 3). Assets and liabilities recorded at fair value on the consolidated balance sheets are categorized based on inputs to the valuation techniques as follows: Level 1— Assets and liabilities recorded at fair value for which values are based on unadjusted quoted prices for identical assets or liabilities in an active market that management has the ability to access. Active markets are considered to be those in which transactions for the assets or liabilities occur in sufficient frequency and volume to provide pricing information on an ongoing basis. Level 2— Assets and liabilities recorded at fair value for which values are based on quoted prices in markets that are not active or model inputs that are observable either directly or indirectly for substantially the full term of the assets or liabilities. Substantially all of these inputs are observable in the marketplace throughout the full term of the price risk management instrument and can be derived from observable data or supported by observable levels at which transactions are executed in the marketplace. Level 3— Assets and liabilities recorded at fair value for which values are based on prices or valuation techniques that require inputs that are both unobservable and significant to the overall fair value measurement. Unobservable inputs are not corroborated by market data. These inputs reflect management's own assumptions about the assumptions a market participant would use in pricing the asset or liability. |
Treasury stock | Treasury stock is recorded at cost, which includes incremental direct transaction costs, and is retired upon acquisition as a result of (i) stock exchanged to satisfy tax withholding that arises upon the lapse of restrictions on share-settled equity-based awards at the awardee's election or (ii) stock exchanged for the cost of exercise of stock options at the awardee's election. |
Revenue recognition | Oil, NGL and natural gas sales and sales of purchased oil are generally recognized at the point in time that control of the product is transferred to the customer. Midstream service revenues are recognized over time as the customer benefits from services when provided. Oil sales and sales of purchased oil Under its oil sales contracts, the Company sells produced or purchased oil at the delivery point specified in the contract and collects an agreed-upon index price, net of pricing differentials. The delivery point may be at the wellhead, the inlet of the purchaser's pipeline or nominated pipeline or the Company's truck unloading facility. At the delivery point, the purchaser typically takes custody, title and risk of loss of the product and, therefore, control as defined under ASC 606, Revenue from Contracts with Customers , typically passes at the delivery point. The Company recognizes revenue at the net price received when control transfers to the purchaser. The Company engages in transactions in which it sells oil at the lease and subsequently repurchases the same volume of oil from that customer at a downstream delivery point under a separate agreement ("Repurchase Agreement") for use in the sale to the final customer. The commercial reasoning for such transactions may vary. Where a Repurchase Agreement exists, the Company must evaluate whether the customer obtains control of the oil at the lease and therefore whether it is appropriate to recognize revenue for the lease sale. Where the Company has an obligation or a right to repurchase the oil, the customer does not obtain control of the oil because it is limited in its ability to direct the use of, and obtain substantially all of the remaining benefits from the oil even though it may have physical possession of the oil. If the Company repurchases the oil for less than the original selling price, such a transaction will be classified as a lease. If the Company repurchases the oil for equal to or more than the original selling price, then the transaction represents a financing arrangement unless there is only a short passage of time between the sale and repurchase, in which case any excess amount paid represents an expense associated with the sale of oil to the final customer. The Company recognizes such repurchase expense and any transportation expenses incurred for the delivery of the oil to the final customer in the "Transportation and marketing expenses" line item in the accompanying consolidated statements of operations. In certain situations, the Company enters into purchase and sale transactions of oil inventory with the same counterparty in contemplation with one another, and these transactions are presented on the consolidated statements of operations on a net basis in accordance with ASC 845, Nonmonetary Transactions . The following table presents the net effect of these transactions for the periods presented: Years ended December 31, (in thousands) 2021 2020 2019 Sales of purchased oil inventory $ 327,839 $ 17,026 $ — Purchased oil inventory 326,625 16,918 — Net effect on earnings (1) $ 1,214 $ 108 $ — ______________________________________________________________________________ (1) Amounts presented are recorded in "Sales of purchased oil" in the consolidated statements of operations. Under certain of its customer contracts, the Company is subject to contractual penalties if it fails to deliver contractual minimum volumes to its customers. Such amounts are recorded as a reduction to the transaction price as these amounts do not represent payments to the customer for distinct goods or services and instead relate specifically to the failure to perform under the specific customer contract. Such amounts are recorded as a reduction to the transaction price when payment is determined as probable, typically when such a deficiency occurs. NGL and natural gas sales Under its natural gas processing contracts, the Company delivers produced natural gas to a midstream processing entity at the wellhead or the inlet of the processing entity's system. The processing entity processes the natural gas, sells the resulting NGL and residue gas to third parties and pays the Company for the NGL and residue gas with deductions that may include gathering, compression, processing and transportation fees. In these scenarios, the Company evaluates whether it is the principal or the agent in the transaction. For existing contracts, the Company has concluded that it is the agent in the ultimate sale to the third party and the midstream processing entity is the principal and that the Company has transferred control of unprocessed natural gas to the midstream processing entity; therefore, the Company recognizes revenue based on the net amount of the proceeds received from the midstream processing entity who represents the Company's customer. If for future contracts the Company was to conclude that it was the principal with the ultimate third party being the customer, the Company would recognize revenue for those contracts on a gross basis, with gathering, compression, processing, and transportation fees presented as an expense. Midstream service revenues Revenue from oil throughput agreements is recognized based on a rate per barrel for volumes transported. Under the Company's oil throughput agreements, a volumetric deduction is taken from customer oil as a pipeline loss allowance. While these amounts represent non-cash consideration under ASC 606, such deductions are immaterial. Revenue from natural gas throughput agreements is recognized based on a rate per MMbtu for volumes transported. Revenue from water delivery, recycling and takeaway is recognized based on the volumes of water for which the services are provided at the applicable contractual rate. Imbalances The Company recognizes revenue for all oil, NGL and natural gas sold to purchasers regardless of whether the sales are proportionate to the Company's ownership interest in the property. Production imbalances are recognized as a liability to the extent an imbalance on a specific property exceeds the Company's share of remaining proved oil, NGL and natural gas reserves. The Company is also subject to natural gas pipeline imbalances, which are recorded as accounts receivable or payable at values consistent with contractual arrangements with the owner of the pipeline. The Company did not have any producer or pipeline imbalance positions as of December 31, 2021 or 2020. Significant judgments The Company engages in various types of transactions in which unaffiliated midstream entities process the Company's liquids-rich natural gas and, in some scenarios, subsequently market resulting NGL and residue gas to third-party customers on the Company's behalf. These types of transactions require judgment to determine whether the Company is the principal or the agent in the contract and, as a result, whether revenues are recorded gross or net. For existing contracts, the Company has determined that it serves as the agent in the sale of products under certain natural gas processing and marketing agreements with unaffiliated midstream entities in accordance with the control model in ASC 606, Revenue from Contracts with Customers . As a result, the Company presents revenue on a net basis for amounts expected to be received from third-party customers through the marketing process, with expenses and deductions incurred subsequent to control of the product(s) transferring to the unaffiliated midstream entity being netted against revenue. Transaction price allocated to remaining performance obligations A significant number of the Company's product sales are short-term in nature with a contract term of one year or less. For those contracts, the Company has utilized the practical expedient in ASC 606-10-50-14 that exempts the Company from disclosure of the transaction price allocated to remaining performance obligations if the performance obligation is part of a contract that has an original expected duration of one year or less. For the Company's product sales that have a contract term greater than one year and for its Midstream Services, the Company has utilized the practical expedient in ASC 606-10-50-14A that states that it is not required to disclose the transaction price allocated to remaining performance obligations if the variable consideration is allocated entirely to a wholly unsatisfied performance obligation. Under the Company's product sales contracts, each unit of product generally represents a separate performance obligation; therefore, future volumes are wholly unsatisfied. Under the Midstream Services contracts each unit of service represents a separate performance obligation and therefore performance obligations in respect of future services are wholly unsatisfied. Contract balances Under the Company's customer contracts, invoicing occurs once the Company's performance obligations have been satisfied, at which point payment is unconditional. Accordingly, the Company's contracts do not give rise to contract assets or liabilities under ASC 606, Revenue from Contracts with Customers . Prior-period performance obligations |
Fees received for the operation of jointly-owned oil and natural gas properties | The Company receives fees for the operation of jointly-owned oil and natural gas properties and records such reimbursements as a reduction of general and administrative expenses. |
Compensation awards | Equity-based compensation expense is included in "General and administrative" on the consolidated statements of operations, and includes expense for (i) restricted stock awards, stock option awards, performance share awards and the outperformance share award, which are accounted for as equity awards and are generally based on the awards' grant date or modification date fair value less an expected forfeiture rate and (ii) performance unit awards and phantom unit awards, which are accounted for as liability awards and are re-measured at each quarterly reporting period until settlement. The Company capitalizes a portion of equity-based compensation for employees who are directly involved in the acquisition, exploration and development of its oil and natural gas properties into the full cost pool. Capitalized equity-based compensation is included in "Evaluated properties" on the consolidated balance sheets. Restricted stock awards All service vesting restricted stock awards are treated as issued and outstanding in the consolidated financial statements. Per the award agreement terms, if employment is terminated prior to the restriction lapse date for reasons other than death or disability, the restricted stock awards are forfeited and canceled and are no longer considered issued and outstanding. If the termination of employment is by reason of death or disability, all of the holder's restricted stock will automatically vest. Restricted stock awards granted to employees vest in a variety of schedules that mainly include (i) 33%, 33% and 34% vesting per year beginning on the first anniversary of the grant date and (ii) full vesting on the first anniversary of the grant date. Restricted stock awards granted to non-employee directors vest immediately on the grant date. |
Income taxes | Income taxes are accounted for under the asset and liability method. Deferred tax assets and liabilities are recognized for the future tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax bases and operating losses and tax credit carryforwards. Under this method, deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which those temporary differences are expected to be recovered or settled. The effect on deferred tax assets and liabilities of a change in tax rates is recognized in income (loss) in the period that includes the enactment date. The Company evaluates uncertain tax positions for recognition and measurement in the consolidated financial statements. To recognize a tax position, the Company determines whether it is more likely than not that the tax position will be sustained upon examination, including resolution of any related appeals or litigation, based on the technical merits of the position. A tax position that meets the more-likely-than-not threshold is measured to determine the amount of benefit to be recognized in the consolidated financial statements. The amount of tax benefit recognized with respect to any tax position is measured as the largest amount of benefit that is greater than 50 percent likely of being realized upon settlement. |
Recently issued or adopted accounting pronouncements | The Company considered the applicability and impact of all accounting standard updates ("ASU") issued by the Financial Accounting Standards Board ("FASB") to the Accounting Standards Codification ("ASC") and has determined there are no ASUs that are not yet adopted and meaningful to disclose as of December 31, 2021. Additionally, the Company did not adopt any new ASUs during the year ended December 31, 2021. |
Basis of presentation and sig_3
Basis of presentation and significant accounting policies (Tables) | 12 Months Ended |
Dec. 31, 2021 | |
Accounting Policies [Abstract] | |
Schedule of components of accounts receivable | Accounts receivable consisted of the following components as of the dates presented: (in thousands) December 31, 2021 December 31, 2020 Oil, NGL and natural gas sales (1) $ 135,560 $ 46,714 Joint operations, net (2) 11,491 2,753 Sales of purchased oil and other products 4,756 5,083 Derivatives and other — 9,426 Total accounts receivable, net $ 151,807 $ 63,976 _____________________________________________________________________________ (1) For purchasers that the Company has netting arrangements with, the amounts presented include the net positions. (2) Accounts receivable for joint operations are presented net of an allowance for expected credit losses of $0.4 million as of both December 31, 2021 and 2020. As the operator of the majority of its wells, the Company has the ability to realize some or all of these receivables through the netting of revenues. |
Schedule of components of other current assets | Other current assets consisted of the following components as of the dates presented: (in thousands) December 31, 2021 December 31, 2020 Prepaid expenses and other $ 12,746 $ 12,768 Inventory (1) 10,160 3,196 Total other current assets $ 22,906 $ 15,964 ______________________________________________________________________________ (1) See Note 2.i for discussion of the Company's types of inventory. |
Schedule of components of other current liabilities | Other current liabilities consisted of the following components as of the dates presented: (in thousands) December 31, 2021 December 31, 2020 Accrued interest payable $ 56,468 $ 42,401 Accrued compensation and benefits 14,434 16,687 Other accrued liabilities 28,569 3,678 Total other current liabilities $ 99,471 $ 62,766 |
Schedule of asset retirement obligation liability | The following table reconciles the Company's asset retirement obligation liability associated with tangible long-lived assets for the periods presented: Years ended December 31, (in thousands) 2021 2020 Liability at beginning of year $ 68,326 $ 62,718 Liabilities added due to acquisitions, drilling, midstream service asset construction and other 14,610 2,252 Accretion expense (1) 4,233 4,430 Liabilities settled due to plugging and abandonment or removed due to sale (15,186) (1,074) Revision of estimates 20 — Liability at end of year $ 72,003 $ 68,326 ______________________________________________________________________________ (1) Accretion expense is included in "Other operating expenses" on the consolidated statements of operations. |
Schedule of principal transactions revenue | The following table presents the net effect of these transactions for the periods presented: Years ended December 31, (in thousands) 2021 2020 2019 Sales of purchased oil inventory $ 327,839 $ 17,026 $ — Purchased oil inventory 326,625 16,918 — Net effect on earnings (1) $ 1,214 $ 108 $ — ______________________________________________________________________________ (1) Amounts presented are recorded in "Sales of purchased oil" in the consolidated statements of operations. |
Schedule of fees received from operation of jointly owned oil and natural gas properties | The following table presents the fees received for the operation of jointly-owned oil and natural gas properties for the periods presented: Years ended December 31, (in thousands) 2021 2020 2019 Fees received for the operation of jointly-owned oil and natural gas properties $ 876 $ 464 $ 468 |
Schedule of non-cash investing and supplemental cash flow information | The following table presents supplemental cash flow and non-cash information for the periods presented: Years ended December 31, (in thousands) 2021 2020 2019 Supplemental cash flow information: Cash paid for interest, net of $5,866, $3,019 and $805 of capitalized interest, respectively (1) $ 94,867 $ 77,401 $ 58,216 Net cash received for income taxes (2) $ — $ 2,129 $ 3,187 Supplemental non-cash investing information: Fair value of contingent consideration asset (liability) on transaction closing date (3) $ 33,832 $ (225) $ (6,150) Change in accrued capital expenditures $ 22,310 $ (8,053) $ 6,353 Capitalized share-settled equity-based compensation $ 1,583 $ 3,418 $ 4,470 Capitalized asset retirement cost $ 14,610 $ 2,252 $ 4,755 ______________________________________________________________________________ (1) See Note 7.f for additional discussion of the Company's interest expense. (2) See Note 13 for additional discussion of the Company's income taxes. (3) See Notes 4.a, 4.b and 4.d for additional discussion of the Company's acquisitions and divestiture of oil and natural gas properties that include contingent considerations. See Note 11.a for discussion of the quarterly remeasurement of the respective contingent considerations. The following table presents supplemental non-cash adjustments information related to operating leases for the periods presented: Years ended December 31, (in thousands) 2021 2020 Right-of-use assets obtained in exchange for operating lease liabilities (1) $ 7,742 $ 2,349 ______________________________________________________________________________ (1) See Note 5 for additional discussion of the Company's leases. |
Acquisitions and divestitures (
Acquisitions and divestitures (Tables) | 12 Months Ended |
Dec. 31, 2021 | |
Business Combination and Asset Acquisition [Abstract] | |
Schedule of components of purchase price | The following table presents components of the purchase price, inclusive of customary closing adjustments: (in thousands, except for share and share price data) As of October 18, 2021 Shares of Company common stock 959,691 Company common stock price at the Pioneer Closing Date $ 73.90 Value of Company common stock consideration $ 70,921 Cash consideration $ 131,633 Transaction costs 3,013 Total purchase price $ 205,567 The following table presents components of the purchase price, inclusive of customary closing adjustments: (in thousands, except for share and share price data) As of July 1, 2021 Shares of Company common stock 2,506,964 Company common stock price at the Sabalo/Shad Closing Date $ 95.72 Value of Company common stock consideration $ 239,967 Cash consideration $ 606,126 Transaction costs 17,020 Total purchase price $ 863,113 |
Schedule of final estimate of the fair values of the assets acquired and liabilities assumed | The following table presents the allocation of the purchase price to the assets acquired and liabilities assumed, based on their relative fair values, on the Pioneer Closing Date: (in thousands) As of October 18, 2021 Evaluated properties $ 139,360 Unevaluated properties 73,929 Revenue suspense liabilities assumed (7,722) Allocated purchase price $ 205,567 The following table presents the allocation of the purchase price to the assets acquired and liabilities assumed, based on their relative fair values, on the Sabalo/Shad Closing Date: (in thousands) As of July 1, 2021 Evaluated properties $ 503,005 Unevaluated properties 362,977 Revenue suspense liabilities assumed (4,269) Inventory 1,400 Allocated purchase price $ 863,113 The following table reflects an aggregate of the final estimate of the fair values of the assets acquired and liabilities assumed in this business combination on December 6, 2019: (in thousands) Fair values of acquisition Fair values of net assets: Evaluated oil and natural gas properties $ 29,921 Unevaluated oil and natural gas properties 34,700 Asset retirement cost 2,728 Total assets acquired $ 67,349 Asset retirement obligations (2,728) Net assets acquired $ 64,621 Fair values of consideration paid for net assets: Cash consideration $ 64,621 |
Leases (Tables)
Leases (Tables) | 12 Months Ended |
Dec. 31, 2021 | |
Leases [Abstract] | |
Schedule of lease costs, supplemental cash flow information, lease terms and discount rates | The following table presents components of total lease costs, net for the periods presented: Years ended December 31, (in thousands) 2021 2020 Operating lease costs (1) $ 15,894 $ 15,094 Short-term lease costs (2) 83,471 82,576 Variable lease costs (3) 6,873 10,218 Sublease income (1,057) (1,032) Total lease costs, net $ 105,181 $ 106,856 _____________________________________________________________________________ (1) Amounts represent straight-line costs associated with the Company's operating lease right-of-use assets. (2) Amounts include costs associated with the Company's short-term leases that are not included in the calculation of lease liabilities and right-of-use assets and, therefore, are not recorded on the consolidated balance sheets as such. (3) Amounts are primarily comprised of the non-lease service component of drilling rig commitments above the minimum required payments, and are not included in the calculation of lease liabilities and right-of-use assets. Both the minimum required payments and the non-lease service component of the drilling rig commitments are capitalized as additions to oil and natural gas properties. The following table presents cash paid for amounts included in the measurement of operating lease liabilities, which may not agree to operating lease costs due to timing of cash payments and incurred capital expenditures for the periods presented: Years ended December 31, (in thousands) 2021 2020 Operating cash flows from operating leases $ 4,065 $ 5,910 Investing cash flows from operating leases (1) $ 12,569 $ 9,425 _____________________________________________________________________________ (1) Amounts associated with drilling operations are capitalized as additions to oil and natural gas properties. The following table presents the weighted-average remaining lease term and weighted-average discount rate for operating leases as of the dates presented: December 31, 2021 December 31, 2020 Weighted-average remaining lease term 2.80 years 2.87 years Weighted-average discount rate 7.41 % 7.72 % |
Schedule of maturities of operating lease liabilities | The following table reconciles the undiscounted cash flows for recognized operating lease liabilities for each of the first five years and the total remaining years to the operating lease liabilities recorded on the consolidated balance sheet as of the date presented: (in thousands) December 31, 2021 2022 $ 8,399 2023 1,925 2024 1,428 2025 1,423 2026 1,348 Thereafter 666 Total minimum lease payments 15,189 Less: lease liability expense (1,721) Present value of future minimum lease payments 13,468 Less: current operating lease liabilities (7,742) Noncurrent operating lease liabilities $ 5,726 |
Property and equipment (Tables)
Property and equipment (Tables) | 12 Months Ended |
Dec. 31, 2021 | |
Property, Plant and Equipment [Abstract] | |
Schedule of employee-related costs capitalized to oil and natural gas properties | The following table presents capitalized employee-related incurred capital expenditures in the acquisition, exploration and development of oil and natural gas properties for the periods presented: Years ended December 31, (in thousands) 2021 2020 2019 Capitalized employee-related costs $ 18,225 $ 18,954 $ 18,299 |
Schedule of property and equipment | The following table presents depletion expense, which is included in "Depletion, depreciation and amortization" on the consolidated statements of operations, and depletion expense per BOE sold of evaluated oil and natural gas properties for the periods presented: Years ended December 31, (in thousands except per BOE data) 2021 2020 2019 Depletion expense of evaluated oil and natural gas properties $ 201,691 $ 203,492 $ 250,857 Depletion expense per BOE sold $ 6.76 $ 6.34 $ 8.50 The following table presents full cost ceiling impairment expense, which is included in "Impairment expense" on the consolidated statements of operations for the periods presented: Years ended December 31, (in thousands) 2021 2020 2019 Full cost ceiling impairment expense $ — $ 889,453 $ 620,565 Midstream service assets consisted of the following components as of the dates presented: (in thousands) December 31, 2021 December 31, 2020 Midstream service assets $ 165,232 $ 181,718 Less accumulated depreciation and impairment (68,704) (69,021) Total midstream service assets, net $ 96,528 $ 112,697 The following table presents depreciation of midstream service assets for the periods presented: Years ended December 31, (in thousands) 2021 2020 2019 Depreciation of midstream service assets $ 9,514 $ 9,838 $ 10,206 Other fixed assets consisted of the following components as of the dates presented: (in thousands) December 31, 2021 December 31, 2020 Computer hardware and software $ 15,039 $ 9,388 Vehicles 9,072 9,852 Leasehold improvements 7,136 7,125 Buildings 7,039 6,982 Other 5,095 4,107 Depreciable total 43,381 37,454 Less accumulated depreciation and amortization (27,692) (24,344) Depreciable total, net 15,689 13,110 Land 18,901 18,901 Total other fixed assets, net $ 34,590 $ 32,011 The following table presents depreciation and amortization of other fixed assets for the periods presented: Years ended December 31, (in thousands) 2021 2020 2019 Depreciation and amortization of other fixed assets $ 4,150 $ 3,771 $ 4,683 |
Schedule of Benchmark Prices and Realized Prices used in the full cost ceiling calculation | The following table presents the Benchmark Prices and the Realized Prices as of the dates presented: December 31, 2021 December 31, 2020 December 31, 2019 Benchmark Prices: Oil ($/Bbl) $ 63.04 $ 36.04 $ 52.19 NGL ($/Bbl) (1) $ 34.51 $ 16.63 $ 21.14 Natural gas ($/MMBtu) $ 3.35 $ 1.21 $ 0.87 Realized Prices: Oil ($/Bbl) $ 66.37 $ 37.69 $ 52.12 NGL ($/Bbl) $ 22.90 $ 7.43 $ 12.21 Natural gas ($/Mcf) $ 2.61 $ 0.79 $ 0.53 _____________________________________________________________________________ |
Debt (Tables)
Debt (Tables) | 12 Months Ended |
Dec. 31, 2021 | |
Debt Disclosure [Abstract] | |
Schedule of debt issuance costs capitalized and write-offs | The following table presents debt issuance costs capitalized and debt issuance costs write-offs for the periods presented: Years ended December 31, (in thousands) 2021 2020 2019 Debt issuance costs capitalized (1) $ 14,686 $ 18,479 $ — Debt issuance costs write-offs (2) $ — $ 6,163 $ 935 ______________________________________________________________________________ (1) The Company capitalized $14.7 million in debt issuance costs during the year ended December 31, 2021 in connection with an increase in the borrowing base, entering into the Sixth and Seventh Amendments to the Senior Secured Credit Facility and the issuance of the July 2029 Notes. The Company capitalized $18.5 million in debt issuance costs during the year ended December 31, 2020 in connection with the issuance of the January 2025 Notes and January 2028 Notes and entering into amendments to the Senior Secured Credit facility in connection with the semi-annual redeterminations. |
Schedule of future amortization of debt issuance costs | The following table presents future amortization expense of debt issuance costs: (in thousands) December 31, 2021 2022 6,165 2023 6,165 2024 6,165 2025 2,894 2026 1,735 Thereafter 3,079 Total 26,203 |
Schedule of amounts incurred and charged to interest expenses | The following table presents amounts that have been incurred and charged to interest expense: Years ended December 31, (in thousands) 2021 2020 2019 Cash payments for interest $ 100,733 $ 80,420 $ 59,021 Amortization of debt issuance costs and other adjustments 4,451 3,708 3,111 Change in accrued interest 14,067 23,900 220 Interest costs incurred 119,251 108,028 62,352 Less capitalized interest (5,866) (3,019) (805) Total interest expense $ 113,385 $ 105,009 $ 61,547 |
Schedule of net presentation of the Company's long-term debt and debt issuance cost | The following table presents the Company's long-term debt and debt issuance costs, net included in "Long-term debt, net" on the consolidated balance sheets as of the dates presented: December 31, 2021 December 31, 2020 (in thousands) Long-term debt Debt issuance costs, net Long-term debt, net Long-term debt Debt issuance costs, net Long-term debt, net January 2025 Notes 577,913 (6,345) 571,568 577,913 (8,676) 569,237 January 2028 Notes 361,044 (5,024) 356,020 361,044 (6,015) 355,029 July 2029 Notes 400,000 (6,730) 393,270 — — — Senior Secured Credit Facility (1) 105,000 — 105,000 255,000 — 255,000 Total $ 1,443,957 $ (18,099) $ 1,425,858 $ 1,193,957 $ (14,691) $ 1,179,266 _____________________________________________________________________________ (1) Debt issuance costs, net related to the Senior Secured Credit Facility of $8.1 million and $2.3 million as of December 31, 2021 and 2020, respectively, are included in "Other noncurrent assets, net" on the consolidated balance sheets. |
Compensation plans (Tables)
Compensation plans (Tables) | 12 Months Ended |
Dec. 31, 2021 | |
Share-based Payment Arrangement [Abstract] | |
Schedule of restricted stock award activity | The following table reflects the restricted stock award activity for the years presented: (in thousands, except for weighted-average grant-date fair value) Restricted Weighted-average Outstanding as of December 31, 2018 210 $ 198.20 Granted 381 $ 65.20 Forfeited (178) $ 102.20 Vested (138) $ 178.40 Outstanding as of December 31, 2019 275 $ 85.80 Granted 238 $ 16.54 Forfeited (48) $ 53.51 Vested (156) $ 71.25 Outstanding as of December 31, 2020 309 $ 44.88 Granted 237 $ 38.86 Forfeited (42) $ 42.44 Vested (1) (154) $ 57.37 Outstanding as of December 31, 2021 350 $ 35.57 _____________________________________________________________________________ (1) The aggregate intrinsic value of vested restricted stock awards for the year ended December 31, 2021 was $7.3 million. |
Schedule of stock option award activity | The following table reflects the stock option award activity for the years presented: (in thousands, except for weighted-average exercise price and weighted-average remaining contractual term) Stock option awards Weighted-average Weighted-average Outstanding as of December 31, 2018 127 $ 253.80 5.99 Exercised (1) $ 82.00 Expired or canceled (92) $ 271.00 Forfeited (17) $ 172.20 Outstanding as of December 31, 2019 17 $ 251.20 5.00 Expired or canceled (6) $ 238.38 Outstanding as of December 31, 2020 11 $ 257.42 4.00 Exercised (2) $ 82.00 Expired or canceled (2) $ 374.77 Outstanding and exercisable as of December 31, 2021 (1) 7 $ 275.88 3.24 _____________________________________________________________________________ (1) The vested and exercisable stock option awards as of December 31, 2021 had no intrinsic value. |
Schedule of vesting rights options | Stock option awards granted to employees vest and become exercisable in four equal installments on each of the four anniversaries of the grant date, in accordance with the following schedule: Full years of continuous employment following grant date Incremental percentage of Cumulative percentage of Less than one — % — % One 25 % 25 % Two 25 % 50 % Three 25 % 75 % Four 25 % 100 % |
Schedule of performance share/unit award activity | The following table reflects the performance share award activity for the years presented: (in thousands, except for weighted-average grant-date fair value) Performance share awards Weighted-average Outstanding as of December 31, 2018 172 $ 274.80 Granted (1) 29 $ 50.40 Converted from performance unit awards (1)(2) 78 $ 74.80 Forfeited (87) $ 209.60 Lapsed (3) (77) $ 346.20 Outstanding as of December 31, 2019 115 $ 106.80 Forfeited (10) $ 110.94 Lapsed (4) (8) $ 379.20 Outstanding as of December 31, 2020 97 $ 84.06 Forfeited (10) $ 74.70 Vested (1) (15) $ 184.43 Outstanding as of December 31, 2021 72 $ 64.74 _____________________________________________________________________________ (1) The amounts payable in the Company's common stock at the end of the requisite service period for the performance share awards granted on February 16, 2018, February 28, 2019 and June 3, 2019 were determined based on three criteria: (i) RTSR Performance Percentage, (ii) ATSR Appreciation and (iii) ROACE Percentage. The RTSR Performance Percentage, ATSR Appreciation and ROACE Percentage will be used to identify the "RTSR Factor," the "ATSR Factor" and the "ROACE Factor," respectively, which are used to compute the "Performance Multiple" and ultimately to determine the number of shares to be delivered on the payment date. In computing the Performance Multiple, the RTSR Factor is given a 25% weight, the ATSR Factor a 25% weight and the ROACE Factor a 50% weight. The performance share awards granted on February 16, 2018 had a performance period of January 1, 2018 to December 31, 2020 and, as their market and performance criteria were partially satisfied, resulted in a 43% payout. Based on such payout, the granted awards vested and were converted into 6,343 shares of the Company's common stock during the year ended December 31, 2021. The performance share awards granted on February 28, 2019 and June 3, 2019 had a performance period of January 1, 2019 to December 31, 2021 and, as their market and performance criteria were fully satisfied, resulted in a 107% payout. Based on such payout, the granted awards will be converted into shares of the Company's common stock during the first quarter of 2022. (2) On May 16, 2019, the board of directors elected to change the form of payment from cash to common stock for the awards granted on February 28, 2019. This change in election triggered modification accounting, and the awards, formerly accounted for as liability awards, were converted to equity awards and, accordingly, new fair values were determined based on the May 16, 2019 modification date. (3) The performance share awards granted on May 25, 2016 had a performance period of January 1, 2016 to December 31, 2018 and, as their market criteria were not satisfied, resulted in a TSR modifier of 0% based on the Company finishing in the ninth percentile of its peer group for relative TSR. As such, the granted units lapsed and were not converted into the Company's common stock during the first quarter of 2019. (4) The performance share awards granted on February 17, 2017 had a performance period of January 1, 2017 to December 31, 2019 and, as their market criteria were not satisfied, resulted in a TSR modifier of 0% based on the Company finishing in the 15th percentile of its peer group for relative TSR. As such, the granted units lapsed and were not converted into the Company's common stock during the first quarter of 2020. The following table reflects the performance unit award activity for the years presented: (in thousands) Performance units Outstanding as of December 31, 2019 — Granted (1) 123 Forfeited (24) Outstanding as of December 31, 2020 99 Granted (2) 110 Outstanding as of December 31, 2021 209 ______________________________________________________________________________ (1) The amounts potentially payable in cash at the end of the requisite service period for the performance unit awards granted on March 5, 2020 will be determined based on three criteria: (i) RTSR Performance Percentage, (ii) ATSR Appreciation and (iii) ROACE Percentage. The RTSR Performance Percentage, ATSR Appreciation and ROACE Percentage will be used to identify the "RTSR Factor," the "ATSR Factor" and the "ROACE Factor," respectively, which are used to compute the "Performance Multiple" and ultimately to determine the final value of each performance unit to be paid in cash on the payment date per the award agreement, subject to withholding requirements. In computing the Performance Multiple, the RTSR Factor is given a 1/3 weight, the ATSR Factor a 1/3 weight and the ROACE Factor a 1/3 weight. These awards have a performance period of January 1, 2020 to December 31, 2022. (2) The amounts potentially payable in cash at the end of the requisite service period for the performance unit awards granted on March 9, 2021 will be determined based on three criteria: (i) the PSU Matrix, (ii) the EBITDAX/Total Debt Component and (iii) the Inventory Growth Component. These criteria are used to compute the "Performance Multiple" and ultimately to determine the final value of each performance unit to be paid in cash on the payment date per the award agreement, subject to withholding requirements. In computing the Performance Multiple, the PSU Matrix is given a 50% weight, the EBITDAX/Total Debt Component a 25% weight and the Inventory Growth Component a 25% weight. These awards have a performance period of January 1, 2021 to December 31, 2023. |
Schedule of fair value of performance share awards granted assumptions | The following table presents (i) the fair values per performance share and the assumptions used to estimate these fair values per performance share and (ii) the expense per performance share, which is the fair value per performance share adjusted for the estimated payout of the performance criteria, for the outstanding performance share awards as of December 31, 2021 for the grant dates presented: June 3, 2019 February 28, 2019 (1) Market Criteria: 25% RTSR Factor + 25% ATSR Factor: Fair value assumptions: Remaining performance period on grant date 2.58 years 2.63 years Risk-free interest rate (2) 1.78 % 2.14 % Dividend yield — % — % Expected volatility (3) 55.45 % 55.01 % Closing stock price on grant date $ 51.80 $ 69.80 Grant-date fair value per performance share $ 49.00 $ 79.61 Expense per performance share as of December 31, 2021 $ 49.00 $ 79.61 Performance Criteria: 50% ROACE Factor: Fair value assumptions: Closing stock price on grant date $ 51.80 $ 69.80 Grant-date fair value per performance share $ 51.80 $ 69.80 Estimated payout for expense as of December 31, 2021 160 % 160 % Expense per performance share as of December 31, 2021 (4) $ 82.88 $ 111.68 Combined: Grant-date fair value per performance share (5) $ 65.94 $ 95.65 Expense per performance share as of December 31, 2021 (6) $ 65.94 $ 95.65 ______________________________________________________________________________ (1) The fair value assumptions of the performance share awards granted on February 28, 2019 are based on the May 16, 2019 modification date. The total incremental compensation expense resulting from the modification of $1.0 million, which will be recognized over the life of the awards, is calculated utilizing (i) the difference between the March 31, 2019 fair value and the May 16, 2019 fair value and (ii) the outstanding quantity of the converted performance share awards as of June 30, 2019. Such expense excludes the estimated payout component for expense for the 50% ROACE Factor as this is redetermined at each reporting period and the expense will fluctuate accordingly. (2) The remaining performance period matched zero-coupon risk-free interest rate was derived from the U.S. Treasury constant maturities yield curve on the grant date for each respective award, with the exception of the awards granted on February 28, 2019, which used the modification date of May 16, 2019. (3) The Company utilized its own remaining performance period matched historical volatility in order to develop the expected volatility. (4) As the 50% ROACE Factor is based on performance criteria, the expense fluctuates based on the estimated payout and is redetermined each reporting period and the life-to-date recognized expense for the respective awards is adjusted accordingly. (5) The combined grant-date fair value per performance share is the combination of the fair value per performance share weighted for the market and performance criteria for the respective awards. (6) The combined expense per performance share is the combination of the expense per performance share weighted for the market and performance criteria for the respective awards. The total fair value of the outperformance share award and the assumptions used to estimate the fair value of the outperformance share award as of the grant date presented are as follows: June 3, 2019 Performance period 3.00 years Risk-free interest rate (1) 1.77 % Dividend yield — % Expected volatility (2) 55.77 % Closing stock price on grant date $ 51.80 Total fair value of outperformance share award (in thousands) $ 670.0 _____________________________________________________________________________ (1) The performance period matched zero-coupon risk-free interest rate was derived from the U.S. Treasury constant maturities yield curve on the grant date. (2) The Company utilized its own performance period matched historical volatility in order to develop the expected volatility. The following tables present (i) the fair values per performance unit and the assumptions used to estimate these fair values per performance unit and (ii) the expense per performance unit, which is the fair value per performance unit adjusted for the estimated payout of the performance criteria, for the outstanding performance unit awards as of December 31, 2021 for the grant dates presented: March 5, 2020 Market criteria: 1/3 RTSR Factor + 1/3 ATSR Factor: Fair value assumptions: Remaining performance period 1.00 year Risk-free interest rate (1) 0.39 % Dividend yield — % Expected volatility (2) 86.17 % Closing stock price on December 31, 2021 $ 60.13 Fair value per performance unit as of December 31, 2021 $ 195.77 Expense per performance unit as of December 31, 2021 $ 195.77 Performance criteria: 1/3 ROACE Factor: Fair value assumptions: Closing stock price on December 31, 2021 $ 60.13 Fair value per performance unit as of December 31, 2021 $ 60.13 Estimated payout for expense as of December 31, 2021 130.00 % Expense per performance unit as of December 31, 2021 (3) $ 78.17 Combined: Fair value per performance unit as of December 31, 2021 (4) $ 91.31 Expense per performance unit as of December 31, 2021 (5) $ 91.31 ______________________________________________________________________________ (1) The remaining performance period matched zero-coupon risk-free interest rate was derived from the U.S. Treasury constant maturities yield curve on December 31, 2021. (2) The Company utilized its own remaining performance period matched historical volatility in order to develop the expected volatility. (3) As the 1/3 ROACE Factor is based on performance criteria, the expense fluctuates based on the estimated payout and is redetermined each reporting period and the life-to-date recognized expense for the award is adjusted accordingly. (4) The combined fair value per performance unit is the combination of the fair value per performance unit weighted for the market and performance criteria for the award. (5) The combined expense per performance unit is the combination of the expense per performance unit weighted for the market and performance criteria for the award. March 9, 2021 Market criteria: 50% PSU Matrix Component: Fair value assumptions: Remaining performance period 2.00 years Risk-free interest rate (1) 0.73 % Dividend yield — % Expected volatility (2) 135.42 % Closing stock price on December 31, 2021 $ 60.13 Fair value per performance unit as of December 31, 2021 $ 121.72 Expense per performance unit as of December 31, 2021 $ 121.72 Performance criteria: 25% EBITDAX/Total Debt Component + 25% Inventory Growth Component Fair value assumptions: Closing stock price on December 31, 2021 $ 60.13 Fair value per performance unit as of December 31, 2021 $ 60.13 Estimated payout for expense as of December 31, 2021 100.00 % Expense per performance unit as of December 31, 2021 (3) $ 60.13 Combined: Fair value per performance unit as of December 31, 2021 (4) $ 90.92 Expense per performance unit as of December 31, 2021 (5) $ 90.92 ______________________________________________________________________________ (1) The remaining performance period matched zero-coupon risk-free interest rate was derived from the U.S. Treasury constant maturities yield curve on December 31, 2021. (2) The Company utilized its own remaining performance period matched historical volatility in order to develop the expected volatility. (3) As the 25% EBITDAX/Total Debt Component and 25% Inventory Growth Component are based on performance criteria, the expense fluctuates based on the estimated payout and is redetermined each reporting period and the life-to-date recognized expense for the award is adjusted accordingly. (4) The combined fair value per performance unit is the combination of the fair value per performance unit weighted for the market and performance criteria for the award. |
Schedule of phantom unit award activity | The following table reflects the phantom unit award activity for the year ended December 31, 2021: (in thousands, except for weighted-average fair value) Phantom units Outstanding as of December 31, 2019 — Granted 75 Outstanding as of December 31, 2020 75 Granted 5 Forfeited (22) Vested (1) (25) Outstanding as of December 31, 2021 (2) 33 ______________________________________________________________________________ (1) On March 5, 2021, the vested phantom unit awards were settled and paid out in cash at a fair value per unit of $34.24 based on the Company's closing stock price on the vesting date. (2) The fair value per unit of outstanding phantom unit awards as of December 31, 2021 was $60.13. |
Schedule of stock-based compensation expense | The following table reflects equity-based compensation expense for the years presented: Years ended December 31, (in thousands) 2021 2020 2019 Equity awards: Restricted stock awards $ 7,594 $ 8,839 $ 13,169 Performance share awards 1,482 2,545 (1,250) Outperformance share award 175 174 101 Stock option awards 7 77 740 Total share-settled equity-based compensation, gross $ 9,258 $ 11,635 $ 12,760 Less amounts capitalized (1,583) (3,418) (4,470) Total share-settled equity-based compensation, net $ 7,675 $ 8,217 $ 8,290 Liability awards: Performance unit awards $ 7,480 $ 749 $ — Phantom unit awards 1,238 404 — Total cash-settled equity-based compensation, gross $ 8,718 $ 1,153 $ — Less amounts capitalized (365) (163) — Total cash-settled equity-based compensation, net $ 8,353 $ 990 $ — Total equity-based compensation, net $ 16,028 $ 9,207 $ 8,290 |
Schedule of costs recognized for defined contribution plan | The following table presents the contributions expense recognized for the Company's 401(k) plan for the years presented: Years ended December 31, (in thousands) 2021 2020 2019 Contributions $ 1,652 $ 1,649 $ 1,742 |
Derivatives (Tables)
Derivatives (Tables) | 12 Months Ended |
Dec. 31, 2021 | |
Derivative Instruments and Hedging Activities Disclosure [Abstract] | |
Schedule of gain (loss) on derivatives | The following table summarizes the Company's gain (loss) on derivatives, net by type of derivative instrument for the periods presented: Years ended December 31, (in thousands) 2021 2020 2019 Commodity $ (453,784) $ 73,662 $ 80,351 Interest rate (30) (343) — Contingent consideration 1,639 6,795 (1,200) Gain (loss) on derivatives, net $ (452,175) $ 80,114 $ 79,151 |
Schedule of derivatives terminated | The following table details the commodity derivatives that were terminated: Aggregate volumes (Bbl) Weighted-average floor price ($/Bbl) Weighted-average ceiling price ($/Bbl) Contract period WTI NYMEX - Swaps 389,180 $ 60.25 $ 60.25 September 2020 - December 2020 WTI NYMEX - Collars 912,500 $ 45.00 $ 71.00 January 2021 - December 2021 Aggregate volumes (Bbl) Weighted-average floor price ($/Bbl) Weighted-average ceiling price ($/Bbl) Contract period WTI NYMEX - Puts 5,087,500 $ 46.03 $ — April 2019 - December 2019 WTI NYMEX - Put 366,000 $ 45.00 $ — January 2020 - December 2020 WTI NYMEX - Collars 1,134,600 $ 45.00 $ 76.13 January 2020 - December 2020 |
Schedule of open positions and derivatives in place | The following table summarizes open commodity derivative positions as of December 31, 2021, for commodity derivatives that were entered into through December 31, 2021, for the settlement periods presented: Year 2022 Year 2023 Oil: WTI NYMEX - Swaps: Volume (Bbl) 1,085,000 — Weighted-average price ($/Bbl) $ 67.77 $ — WTI NYMEX - Collars: Volume (Bbl) 3,394,500 730,000 Weighted-average floor price ($/Bbl) $ 58.23 $ 60.00 Weighted-average ceiling price ($/Bbl) $ 69.39 $ 75.66 Total WTI NYMEX: Total volume (Bbl) 4,479,500 730,000 Weighted-average floor price ($/Bbl) $ 60.54 $ 60.00 Weighted-average ceiling price ($/Bbl) $ 69.00 $ 75.66 Brent ICE - Swaps: Volume (Bbl) 4,124,500 — Weighted-average price ($/Bbl) $ 48.34 $ — Brent ICE - Collars: Volume (Bbl) 1,551,250 — Weighted-average floor price ($/Bbl) $ 56.65 $ — Weighted-average ceiling price ($/Bbl) $ 65.44 $ — Total Brent ICE: Total volume (Bbl) 5,675,750 — Weighted-average floor price ($/Bbl) $ 50.61 $ — Weighted-average ceiling price ($/Bbl) $ 53.01 $ — NGL: Purity Ethane - Swaps: Volume (Bbl) 1,533,000 — Weighted-average price ($/Bbl) $ 11.42 $ — Non-TET Propane - Swaps: Volume (Bbl) 1,168,000 — Weighted-average price ($/Bbl) $ 35.91 $ — Non-TET Normal Butane - Swaps: Volume (Bbl) 365,000 — Weighted-average price ($/Bbl) $ 41.58 $ — Non-TET Isobutane - Swaps: Volume (Bbl) 109,500 — Weighted-average price ($/Bbl) $ 42.00 $ — Non-TET Natural Gasoline - Swaps: Volume (Bbl) 365,000 — Weighted-average price ($/Bbl) $ 60.65 $ — Total NGL volume (Bbl) 3,540,500 — CONTINUED ON NEXT PAGE Year 2022 Year 2023 Natural gas: Henry Hub NYMEX - Swaps: Volume (MMBtu) 3,650,000 — Weighted-average price ($/MMBtu) $ 2.73 $ — Henry Hub NYMEX - Collars: Volume (MMBtu) 29,200,000 3,650,000 Weighted-average floor price ($/MMBtu) $ 3.09 $ 3.00 Weighted-average ceiling price ($/MMBtu) $ 3.84 $ 4.45 Total Henry Hub NYMEX: Total volume (MMBtu) 32,850,000 3,650,000 Weighted-average floor price ($/MMBtu) $ 3.05 $ 3.00 Weighted-average ceiling price ($/MMBtu) $ 3.71 $ 4.45 Waha Inside FERC to Henry Hub NYMEX - Basis Swaps: Volume (MMBtu) 29,017,500 — Weighted-average differential ($/MMBtu) $ (0.36) $ — Notional amount Fixed rate Contract period LIBOR - Swap $ 100,000 0.345 % April 16, 2020 - April 18, 2022 |
Fair value measurements (Tables
Fair value measurements (Tables) | 12 Months Ended |
Dec. 31, 2021 | |
Fair Value Disclosures [Abstract] | |
Schedule of fair value hierarchy for assets and liabilities measured at fair value on a recurring basis | The following tables present the Company's derivatives by (i) balance sheet classification, (ii) derivative type and (iii) fair value hierarchy level, and provide a total, on a gross basis and a net basis reflected in "Derivatives" on the consolidated balance sheets as of the dates presented: December 31, 2021 (in thousands) Level 1 Level 2 Level 3 Total gross fair value Amounts offset Net fair value presented on the consolidated balance sheets Assets: Current: Commodity - Oil $ — $ 14,653 $ — $ 14,653 $ (14,653) $ — Commodity - NGL — — — — — — Commodity - Natural gas — 7,018 — 7,018 (7,018) — Contingent consideration — — 4,346 4,346 — 4,346 Noncurrent: Commodity - Oil $ — $ 1,196 $ — $ 1,196 $ — $ 1,196 Commodity - NGL — — — — — — Commodity - Natural gas — 252 — 252 — 252 Contingent consideration — — 31,515 31,515 — 31,515 Liabilities: Current: Commodity - Oil $ — $ (167,749) $ — $ (167,749) $ 14,653 $ (153,096) Commodity - NGL — (17,581) — (17,581) — (17,581) Commodity - Natural gas — (16,098) — (16,098) 7,018 (9,080) Interest rate - LIBOR — (52) — (52) — (52) Contingent consideration — — — — — — Noncurrent: Commodity - Oil $ — $ — $ — $ — $ — $ — Commodity - NGL — — — — — — Commodity - Natural gas — — — — — — Interest rate - LIBOR — — — — — — Contingent consideration — — — — — — Net derivative liability positions $ — $ (178,361) $ 35,861 $ (142,500) $ — $ (142,500) December 31, 2020 (in thousands) Level 1 Level 2 Level 3 Total gross fair value Amounts offset Net fair value presented on the consolidated balance sheets Assets: Current: Commodity - Oil $ — $ 32,958 $ — $ 32,958 $ (24,930) $ 8,028 Commodity - NGL — 2,720 — 2,720 (2,720) — Commodity - Natural gas — 521 — 521 (656) (135) Contingent consideration — — — — — — Noncurrent: Commodity - Oil $ — $ — $ — $ — $ — $ — Commodity - NGL — — — — — — Commodity - Natural gas — 535 — 535 (535) — Contingent consideration — — — — — — Liabilities: Current: Commodity - Oil $ — $ (25,118) $ — $ (25,118) $ 24,930 $ (188) Commodity - NGL — (16,185) — (16,185) 2,720 (13,465) Commodity - Natural gas — (17,958) — (17,958) 656 (17,302) Interest rate - LIBOR — (206) — (206) — (206) Contingent consideration — (665) — (665) — (665) Noncurrent: Commodity - Oil $ — $ (10,932) $ — $ (10,932) $ — $ (10,932) Commodity - NGL — — — — — — Commodity - Natural gas — (1,476) — (1,476) 535 (941) Interest rate - LIBOR — (63) — (63) — (63) Contingent consideration — (115) — (115) — (115) Net derivative liability positions $ — $ (35,984) $ — $ (35,984) $ — $ (35,984) |
Schedule of changes in assets classified as Level 3 measurements | The following table summarizes the changes in net assets and liabilities for commodity derivatives classified as Level 3 measurements for the periods presented: Years ended December 31, (in thousands) 2021 2020 2019 Balance of Level 3 at beginning of year $ — $ (477) $ (16,565) Change in net present value of commodity derivative deferred premiums (1) — — (139) Settlements of commodity derivative deferred premiums (2) — 477 16,227 Balance of Level 3 at end of year $ — $ — $ (477) _____________________________________________________________________________ (1) These amounts are included in "Interest expense" on the consolidated statements of operations. (2) The amount for the year ended December 31, 2019 includes $7.2 million that represents the present value of deferred premiums settled upon their early termination. |
Schedule of changes in contingent consideration derivatives | The following table summarizes the changes in contingent consideration derivatives classified as Level 3 measurements for the periods presented: Years ended December 31, (in thousands) 2021 2020 2019 Balance of Level 3 at beginning of year $ — $ — $ — Sixth Street Contingent Consideration valuation as of Sixth Street Closing Date 33,832 — — Change in net present value of Sixth Street Contingent Consideration 2,029 — — Balance of Level 3 at end of year $ 35,861 $ — $ — |
Schedule of carrying amounts and fair values of debt | The following table presents the carrying amounts and fair values of the Company's debt as of the dates presented: December 31, 2021 December 31, 2020 (in thousands) Long-term debt Fair value (1) Long-term debt Fair value (1) January 2025 Notes $ 577,913 $ 589,471 $ 577,913 $ 499,299 January 2028 Notes 361,044 378,578 361,044 299,667 July 2029 Notes 400,000 390,000 — — Senior Secured Credit Facility 105,000 105,040 255,000 255,187 Total $ 1,443,957 $ 1,463,089 $ 1,193,957 $ 1,054,153 _____________________________________________________________________________ (1) The fair values of the outstanding notes were determined using the Level 1 fair value hierarchy quoted market prices for each respective instrument as of December 31, 2021 and 2020. The fair values of the outstanding debt under the Senior Secured Credit Facility were estimated utilizing the Level 2 fair value hierarchy pricing model for similar instruments as of December 31, 2021 and 2020. |
Net income (loss) per common _2
Net income (loss) per common share (Tables) | 12 Months Ended |
Dec. 31, 2021 | |
Earnings Per Share [Abstract] | |
Schedule of calculation of basic and diluted weighted average shares outstanding and net income per share | The following table reflects the calculations of basic and diluted (i) weighted-average common shares outstanding and (ii) net income (loss) per common share for the periods presented: Years ended December 31, (in thousands, except for per share data) 2021 2020 2019 Net income (loss) (numerator) $ 145,008 $ (874,173) $ (342,459) Weighted-average common shares outstanding (denominator) (1) : Basic 14,240 11,668 11,565 Dilutive non-vested restricted stock awards 181 — — Dilutive non-vested performance share awards (2) 43 — — Diluted 14,464 11,668 11,565 Net income (loss) per common share (1) : Basic $ 10.18 $ (74.92) $ (29.61) Diluted $ 10.03 $ (74.92) $ (29.61) _____________________________________________________________________________ (1) For the year ended December 31, 2021, the weighted-average common shares outstanding used in the computation of basic and diluted net income per share includes the effects of equity issued by the Company during the year. There was no comparable equity issued during the years ended December 31, 2020 and 2019. See Notes 4.a and 8.a for additional discussion of equity issued by the Company. (2) The dilutive effect of the non-vested performance shares for the year ended December 31, 2021 was calculated as of the end of the performance period on December 31, 2021. |
Income taxes (Tables)
Income taxes (Tables) | 12 Months Ended |
Dec. 31, 2021 | |
Income Tax Disclosure [Abstract] | |
Schedule of income tax expense | The following table presents the "Current" and "Deferred" income tax (expense) benefit reported on the consolidated statements of operations for the periods presented: Years ended December 31, (in thousands) 2021 2020 2019 Current income tax (expense) benefit: Federal $ — $ — $ — State (1,324) — — Deferred income tax (expense) benefit: Federal — — — State (2,321) 3,946 2,588 Total income tax (expense) benefit $ (3,645) $ 3,946 $ 2,588 |
Schedule of reconciliation of income tax (expense) benefit computed by applying the federal income tax rate of 34% to pre-tax income from operations | Total income tax (expense) benefit differed from amounts computed by applying the applicable federal income tax rate of 21% for the years ended December 31, 2021, 2020 and 2019 to pre-tax earnings as a result of the following: Years ended December 31, (in thousands) 2021 2020 2019 Income tax (expense) benefit computed by applying the statutory rate $ (31,217) $ 184,405 $ 72,460 Change in deferred tax valuation allowance 45,717 (182,634) (69,316) Non-deductible equity-based compensation (13,640) — — State income tax and change in valuation allowance (3,274) 2,903 1,863 Other items (1,231) (728) (2,419) Total income tax (expense) benefit $ (3,645) $ 3,946 $ 2,588 |
Schedule of net deferred tax assets (liabilities) | The following table presents significant components of the Company's net deferred tax (liability) asset as of the dates presented: (in thousands) December 31, 2021 December 31, 2020 Net operating loss carryforward $ 445,426 $ 444,031 Oil and natural gas properties, midstream service assets and other fixed assets (39,504) 22,231 Equity-based compensation 11,123 22,494 Derivatives 36,639 7,166 Loss on sale of assets (14,364) (8,458) Other 3,227 3,130 Net deferred tax asset before valuation allowance 442,547 490,594 Valuation allowance (443,390) (489,116) Texas net deferred tax (liability) asset (1) $ (843) $ 1,478 ___________________________________________________________________________ |
Schedule of federal net operating loss carryforwards | The following table presents the Company's federal net operating loss carryforwards and their applicable expiration dates as of the date presented: (in thousands) December 31, 2021 2026 $ 2,741 2027 38,651 2028 228,661 2029 101,932 2030 80,963 Thereafter 1,284,150 Total expiring federal net operating loss carryforwards 1,737,098 Non-expiring federal net operating loss carryforwards 376,212 Total federal net operating loss carryforwards $ 2,113,310 |
Credit risk (Tables)
Credit risk (Tables) | 12 Months Ended |
Dec. 31, 2021 | |
Risks and Uncertainties [Abstract] | |
Schedule of concentration of risk | The following table presents purchasers that individually accounted for 10% or more of the Company's oil, NGL and natural gas sales in at least one of the years presented: Years ended December 31, 2021 2020 2019 Purchaser A (1) 29 % 33 % 59 % Purchaser B 24 % 24 % 18 % Purchaser C (1) 17 % 14 % n/a (2) Purchaser D n/a (2) 10 % n/a (2) Purchaser E n/a (2) n/a (2) 15 % Purchaser F (1) 14 % n/a (2) n/a (2) _____________________________________________________________________________ (1) This purchaser of the Company's oil, NGL and natural gas sales is also a purchaser of the Company's sales of purchased oil included in the table below. (2) This purchaser did not account for 10% or greater of the Company's oil, NGL and natural gas sales. The following table presents purchasers that individually accounted for 10% or more of the Company's sales of purchased oil in at least one of the years presented: Years ended December 31, 2021 2020 2019 Purchaser A (1) 47 % 69 % 26 % Purchaser B (1) 31 % 16 % 70 % Purchaser C (1) 22 % 14 % n/a (2) _____________________________________________________________________________ (1) This purchaser of the Company's sales of purchased oil is also a purchaser of the Company's oil, NGL and natural gas sales included in the table above. |
Related parties (Tables)
Related parties (Tables) | 12 Months Ended |
Dec. 31, 2021 | |
Related Party Transactions [Abstract] | |
Schedule of oil and gas related party transactions | The following table presents the capital expenditures for oil and natural gas properties paid to Halliburton included in the consolidated statements of cash flows for the periods presented: Years ended December 31, (in thousands) 2021 2020 Capital expenditures for oil and natural gas properties $ 69,670 $ 63,886 |
Organizational restructurings (
Organizational restructurings (Tables) | 12 Months Ended |
Dec. 31, 2021 | |
Restructuring and Related Activities [Abstract] | |
Schedule of organizational restructuring expenses and gross equity-based compensation expense reversals | The following table reflects the aggregate of these expenses, which is recorded as "Organizational restructuring expenses" on the consolidated statements of operations, for the periods presented: Years ended December 31, (in thousands) 2021 2020 2019 Organizational restructuring expenses $ 9,800 $ 4,200 $ 16,371 Years ended December 31, (in thousands) 2021 2020 2019 Gross equity-based compensation expense reversals $ (1,088) $ (793) $ (11,706) |
Subsequent events (Tables)
Subsequent events (Tables) | 12 Months Ended |
Dec. 31, 2021 | |
Subsequent Events [Abstract] | |
Schedule of subsequent events | The following table summarizes the resulting open oil derivative positions as of December 31, 2021, updated for the derivative transactions entered into from December 31, 2021 through February 24, 2022, for the settlement periods presented: Year 2022 Year 2023 Oil: WTI NYMEX - Swaps: Volume (Bbl) 1,878,000 — Weighted-average price ($/Bbl) $ 76.11 $ — WTI NYMEX - Collars: Volume (Bbl) 3,394,500 3,632,000 Weighted-average floor price ($/Bbl) $ 58.23 $ 65.50 Weighted-average ceiling price ($/Bbl) $ 69.39 $ 79.94 Total WTI NYMEX: Total volume (Bbl) 5,272,500 3,632,000 Weighted-average floor price ($/Bbl) $ 64.60 $ 65.50 Weighted-average ceiling price ($/Bbl) $ 71.78 $ 79.94 Brent ICE - Swaps: Volume (Bbl) 4,124,500 — Weighted-average price ($/Bbl) $ 48.34 $ — Brent ICE - Collars: Volume (Bbl) 1,551,250 — Weighted-average floor price ($/Bbl) $ 56.65 $ — Weighted-average ceiling price ($/Bbl) $ 65.44 $ — Total Brent ICE: Total volume with floor (Bbl) 5,675,750 — Weighted-average floor price ($/Bbl) $ 50.61 $ — Weighted-average ceiling price ($/Bbl) $ 53.01 $ — See Note 10.a for additional discussion regarding the Company's derivatives. There has been no other derivative activity subsequent to December 31, 2021. |
Supplemental oil, NGL and nat_2
Supplemental oil, NGL and natural gas disclosures (unaudited) (Tables) | 12 Months Ended |
Dec. 31, 2021 | |
Oil and Gas Exploration and Production Industries Disclosures [Abstract] | |
Schedule of incurred capital expenditures in the acquisition, exploration and development of oil and natural gas assets | The following table presents incurred capital expenditures in the acquisition, exploration and development of oil and natural gas properties, with asset retirement obligations included in evaluated property acquisition costs and development costs, for the periods presented: Years ended December 31, (in thousands) 2021 2020 2019 Property acquisition costs: Evaluated $ 899,128 $ 11,368 $ 126,372 Unevaluated 198,770 25,549 83,738 Exploration costs 33,482 17,337 19,954 Development costs 410,855 326,823 450,501 Total oil and natural gas properties incurred capital expenditures $ 1,542,235 $ 381,077 $ 680,565 |
Schedule of aggregate capitalized costs related to oil and natural gas production activities with applicable accumulated depletion, depreciation and impairment | The following table presents the aggregate capitalized costs related to oil, NGL and natural gas production activities with applicable accumulated depletion and impairment as of the dates presented: (in thousands) December 31, 2021 December 31, 2020 Gross capitalized costs: Evaluated properties $ 8,968,668 $ 7,874,932 Unevaluated properties not being depleted 170,033 70,020 Total gross capitalized costs 9,138,701 7,944,952 Less accumulated depletion and impairment (7,019,670) (6,817,949) Net capitalized costs $ 2,119,031 $ 1,127,003 |
Schedule of oil and natural gas property costs not being amortized by year | The following table presents a summary of the unevaluated property costs not being depleted as of December 31, 2021, by year in which such costs were incurred: (in thousands) 2021 2020 2019 2018 and prior Total Unevaluated properties not being depleted $ 166,158 $ 784 $ 1,902 $ 1,189 $ 170,033 |
Schedule of results of oil and natural gas producing activities (excluding corporate overhead and interest costs) | The following table presents the results of operations of oil, NGL and natural gas producing activities (excluding corporate overhead and interest costs) for the periods presented: Years ended December 31, (in thousands) 2021 2020 2019 Revenues: Oil, NGL and natural gas sales $ 1,147,143 $ 496,355 $ 706,548 Production costs: Lease operating expenses 101,994 82,020 90,786 Production and ad valorem taxes 68,742 33,050 40,712 Transportation and marketing expenses 47,916 49,927 25,397 Total production costs 218,652 164,997 156,895 Other costs: Depletion 201,691 203,492 250,857 Accretion of asset retirement obligation 4,018 4,227 3,926 Impairment expense — 889,453 620,565 Income tax expense (benefit) (1) 14,456 — (3,257) Total other costs 220,165 1,097,172 872,091 Results of operations $ 708,326 $ (765,814) $ (322,438) _____________________________________________________________________________ |
Schedule of analysis of change in estimated quantities of oil and natural gas reserves located within United States | The following tables provide an analysis of the changes in estimated proved reserve quantities of oil, NGL and natural gas for the years ended December 31, 2021, 2020 and 2019, all of which are located within the U.S.: Year ended December 31, 2021 Oil NGL Natural gas MBOE Proved developed and undeveloped reserves: Beginning of year 67,759 100,922 657,284 278,228 Revisions of previous estimates 4,740 16,952 102,080 38,709 Extensions, discoveries and other additions 10,354 5,269 22,479 19,369 Acquisitions of reserves in place 65,572 19,711 90,023 100,286 Divestitures of reserves in place (15,904) (34,129) (228,546) (88,125) Production (11,619) (8,678) (57,175) (29,827) End of year 120,902 100,047 586,145 318,640 Proved developed reserves: Beginning of year 51,751 96,251 633,503 253,586 End of year 70,727 78,908 494,476 232,048 Proved undeveloped reserves: Beginning of year 16,008 4,671 23,781 24,642 End of year 50,175 21,139 91,669 86,592 Year ended December 31, 2020 Oil NGL Natural gas MBOE Proved developed and undeveloped reserves: Beginning of year 78,639 102,198 675,237 293,377 Revisions of previous estimates (10,517) 6,218 34,376 1,430 Extensions, discoveries and other additions 4,282 1,811 10,772 7,888 Acquisitions of reserves in place 5,182 1,310 6,948 7,650 Production (9,827) (10,615) (70,049) (32,117) End of year 67,759 100,922 657,284 278,228 Proved developed reserves: Beginning of year 52,711 90,861 600,334 243,628 End of year 51,751 96,251 633,503 253,586 Proved undeveloped reserves: Beginning of year 25,928 11,337 74,903 49,749 End of year 16,008 4,671 23,781 24,642 Year ended December 31, 2019 Oil NGL Natural gas MBOE Proved developed and undeveloped reserves: Beginning of year 61,894 86,647 537,756 238,167 Revisions of previous estimates (7,865) 5,301 69,678 9,049 Extensions, discoveries and other additions 13,573 12,614 83,345 40,078 Acquisitions of reserves in place 21,413 6,754 44,627 35,605 Production (10,376) (9,118) (60,169) (29,522) End of year 78,639 102,198 675,237 293,377 Proved developed reserves: Beginning of year 55,893 79,241 491,828 217,105 End of year 52,711 90,861 600,334 243,628 Proved undeveloped reserves: Beginning of year 6,001 7,406 45,928 21,062 End of year 25,928 11,337 74,903 49,749 |
Schedule of standardized measure of discounted future net cash flows relating to proved oil and natural gas reserves | The following table presents the standardized measure of discounted future net cash flows relating to proved oil, NGL and natural gas reserves for the periods presented: Years ended December 31, (in thousands) 2021 2020 2019 Future cash inflows $ 11,846,148 $ 3,824,104 $ 5,702,580 Future production costs (3,595,524) (1,740,537) (1,994,732) Future development costs (1,064,527) (351,568) (615,839) Future income tax expenses (774,461) (20,076) (24,392) Future net cash flows 6,411,636 1,711,923 3,067,617 10% discount for estimated timing of cash flows (2,986,324) (697,069) (1,405,356) Standardized measure of discounted future net cash flows $ 3,425,312 $ 1,014,854 $ 1,662,261 |
Schedule of changes in standardized measure of discounted future net cash flows relating to proved oil and natural gas reserves | The following table presents the changes in the standardized measure of discounted future net cash flows relating to proved oil, NGL and natural gas reserves for the periods presented: Years ended December 31, (in thousands) 2021 2020 2019 Standardized measure of discounted future net cash flows, beginning of year $ 1,014,854 $ 1,662,261 $ 2,114,237 Changes in the year resulting from: Sales, less production costs (934,440) (331,358) (549,653) Revisions of previous quantity estimates 426,060 199 36,182 Extensions, discoveries and other additions 293,511 60,004 361,479 Net change in prices and production costs 1,572,662 (770,885) (900,019) Changes in estimated future development costs 134,091 64,146 14,876 Previously estimated development incurred capital expenditures during the period 169,376 186,261 158,631 Acquisitions of reserves in place 1,509,087 14,208 207,636 Divestitures of reserves in place (369,601) — — Accretion of discount 102,607 167,227 217,119 Net change in income taxes (279,722) (1,205) 46,939 Timing differences and other (213,173) (36,004) (45,166) Standardized measure of discounted future net cash flows, end of year $ 3,425,312 $ 1,014,854 $ 1,662,261 |
Supplemental quarterly financ_2
Supplemental quarterly financial data (unaudited) (Tables) | 12 Months Ended |
Dec. 31, 2021 | |
Quarterly Financial Information Disclosure [Abstract] | |
Schedule of results of operations by quarter | The Company's results by quarter for the periods presented are as follows: December 31, 2021 (in thousands, except per share data) First Second Third Fourth Revenues $ 250,230 $ 294,371 $ 379,250 $ 470,224 Operating income $ 102,803 $ 108,347 $ 265,736 $ 243,449 Net income (loss) $ (75,439) $ (132,661) $ 136,832 $ 216,276 Net income (loss) per common share: Basic $ (6.33) $ (10.47) $ 8.68 $ 13.07 Diluted $ (6.33) $ (10.47) $ 8.56 $ 12.84 December 31, 2020 (in thousands, except per share data) First Quarter (1) Second Quarter (1) Third Quarter (1) Fourth Quarter (1) Revenues $ 204,992 $ 110,588 $ 173,547 $ 188,065 Operating loss $ (181,972) $ (434,052) $ (167,678) $ (78,031) Net income (loss) $ 74,646 $ (545,455) $ (237,432) $ (165,932) Net income (loss) per common share (2) : Basic $ 6.43 $ (46.75) $ (20.32) $ (14.18) Diluted $ 6.39 $ (46.75) $ (20.32) $ (14.18) ______________________________________________________________________________ (1) See Note 6.a for discussion of the Company's full cost ceiling impairments recorded during the year ended December 31, 2020. (2) Per share data was retroactively adjusted to reflect the Company's 1-for-20 reverse stock split effective June 1, 2020, as described in Note 8.b. |
Organization - Narrative (Detai
Organization - Narrative (Details) | 12 Months Ended |
Dec. 31, 2021operating_segment | |
Organization, Consolidation and Presentation of Financial Statements [Abstract] | |
Number of operating segments | 1 |
Basis of presentation and sig_4
Basis of presentation and significant accounting policies - Accounts receivable (Details) - USD ($) $ in Thousands | Dec. 31, 2021 | Dec. 31, 2020 |
Accounts receivable | ||
Oil, NGL and natural gas sales | $ 135,560 | $ 46,714 |
Joint operations, net | 11,491 | 2,753 |
Sales of purchased oil and other products | 4,756 | 5,083 |
Derivatives and other | 0 | 9,426 |
Total accounts receivable, net | 151,807 | 63,976 |
Allowance for doubtful accounts of accounts receivable for joint operations | $ (400) | $ (400) |
Basis of presentation and sig_5
Basis of presentation and significant accounting policies - Other current assets (Details) - USD ($) $ in Thousands | Dec. 31, 2021 | Dec. 31, 2020 |
Accounting Policies [Abstract] | ||
Prepaid expenses and other | $ 12,746 | $ 12,768 |
Inventory | 10,160 | 3,196 |
Total other current assets | $ 22,906 | $ 15,964 |
Basis of presentation and sig_6
Basis of presentation and significant accounting policies - Other current liabilities (Details) - USD ($) $ in Thousands | Dec. 31, 2021 | Dec. 31, 2020 |
Accounting Policies [Abstract] | ||
Accrued interest payable | $ 56,468 | $ 42,401 |
Accrued compensation and benefits | 14,434 | 16,687 |
Other accrued liabilities | 28,569 | 3,678 |
Total other current liabilities | $ 99,471 | $ 62,766 |
Basis of presentation and sig_7
Basis of presentation and significant accounting policies - Leases (Details) | Dec. 31, 2021 | Dec. 31, 2020 |
Accounting Policies [Abstract] | ||
Average working interest (as a percent) | 96.00% | 96.00% |
Basis of presentation and sig_8
Basis of presentation and significant accounting policies - Asset retirement obligations (Details) - USD ($) $ in Thousands | 12 Months Ended | |
Dec. 31, 2021 | Dec. 31, 2020 | |
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward] | ||
Liability at beginning of year | $ 68,326 | $ 62,718 |
Liabilities added due to acquisitions, drilling, midstream service asset construction and other | 14,610 | 2,252 |
Accretion expense | 4,233 | 4,430 |
Liabilities settled due to plugging and abandonment or removed due to sale | (15,186) | (1,074) |
Revision of estimates | 20 | 0 |
Liability at end of year | $ 72,003 | $ 68,326 |
Basis of presentation and sig_9
Basis of presentation and significant accounting policies - Net effect of transactions (Details) - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2021 | Dec. 31, 2020 | Dec. 31, 2019 | |
Sales of purchased oil | |||
Disaggregation of Revenue [Line Items] | |||
Net effect on earnings | $ 1,214 | $ 108 | $ 0 |
Sales of purchased oil inventory | |||
Disaggregation of Revenue [Line Items] | |||
Net effect on earnings | 327,839 | 17,026 | 0 |
Purchased oil inventory | |||
Disaggregation of Revenue [Line Items] | |||
Net effect on earnings | $ 326,625 | $ 16,918 | $ 0 |
Basis of presentation and si_10
Basis of presentation and significant accounting policies - Revenue recognition (Details) | 12 Months Ended |
Dec. 31, 2021 | |
Minimum | |
Disaggregation of Revenue [Line Items] | |
Settlement statements and payment period | 30 days |
Maximum | |
Disaggregation of Revenue [Line Items] | |
Settlement statements and payment period | 90 days |
Basis of presentation and si_11
Basis of presentation and significant accounting policies - Fees received for the operation of jointly-owned oil and natural gas properties (Details) - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2021 | Dec. 31, 2020 | Dec. 31, 2019 | |
General and administrative expense | |||
Fees received for the operation of jointly-owned oil and natural gas properties | $ 876 | $ 464 | $ 468 |
Basis of presentation and si_12
Basis of presentation and significant accounting policies - Income taxes (Details) - USD ($) | Dec. 31, 2021 | Dec. 31, 2020 |
Accounting Policies [Abstract] | ||
Unrecognized tax benefits | $ 0 | $ 0 |
Basis of presentation and si_13
Basis of presentation and significant accounting policies - Non-cash investing and financing information (Details) - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2021 | Dec. 31, 2020 | Dec. 31, 2019 | |
Supplemental cash flow information: | |||
Cash paid for interest, net of capitalized interest | $ 94,867 | $ 77,401 | $ 58,216 |
Net cash (received) paid for income taxes | 0 | 2,129 | 3,187 |
Supplemental non-cash investing information: | |||
Fair value of contingent consideration asset (liability) on transaction closing date | 33,832 | (225) | (6,150) |
Change in accrued capital expenditures | 22,310 | (8,053) | 6,353 |
Capitalized share-settled equity-based compensation | 1,583 | 3,418 | 4,470 |
Capitalized asset retirement cost | 14,610 | 2,252 | 4,755 |
Capitalized interest | 5,866 | 3,019 | $ 805 |
Right-of-use assets obtained in exchange for operating lease liabilities | $ 7,742 | $ 2,349 |
Acquisitions and divestitures -
Acquisitions and divestitures - Narrative (Details) $ / shares in Units, $ in Thousands | Oct. 18, 2021USD ($)$ / sharesshares | Jul. 01, 2021USD ($)shares | Apr. 30, 2020USD ($)a | Apr. 09, 2020USD ($)awell | Feb. 04, 2020USD ($)a | Dec. 12, 2019USD ($)a | Dec. 06, 2019USD ($)aBoeproperty | Jun. 20, 2019USD ($)a | Nov. 16, 2020USD ($)aBoe | Dec. 31, 2021USD ($)a$ / shares | Dec. 31, 2020USD ($)$ / shares | Dec. 31, 2019USD ($) | Jun. 30, 2027USD ($) | Dec. 31, 2022USD ($) | Sep. 17, 2021alocation | May 07, 2021alocationagreement | Oct. 16, 2020a | Jun. 01, 2020$ / shares |
Business Acquisition [Line Items] | ||||||||||||||||||
Common stock, par value (USD per share) | $ / shares | $ 0.01 | $ 0.01 | $ 0.01 | $ 0.01 | ||||||||||||||
Average working interest (as a percent) | 96.00% | 96.00% | ||||||||||||||||
Acquisitions of oil and natural gas properties | $ 763,411 | $ 35,786 | $ 199,284 | |||||||||||||||
Fair value of contingent consideration asset (liability) on acquisition date | 33,832 | (225) | $ (6,150) | |||||||||||||||
Fair value of contingent consideration | $ 200 | 800 | ||||||||||||||||
Pioneer Acquisition | ||||||||||||||||||
Business Acquisition [Line Items] | ||||||||||||||||||
Area of land (in acres) | a | 20,000 | |||||||||||||||||
Total purchase price | $ 205,567 | |||||||||||||||||
Cash consideration | $ 131,633 | |||||||||||||||||
Stock issued in asset acquisition (shares) | shares | 959,691 | |||||||||||||||||
Transaction related expenses | $ 3,013 | |||||||||||||||||
Pioneer - Glasscock County Gross - Operated Locations | ||||||||||||||||||
Business Acquisition [Line Items] | ||||||||||||||||||
Number of real estate properties | location | 135 | |||||||||||||||||
Pioneer - Glasscock County Net - Operated Locations | ||||||||||||||||||
Business Acquisition [Line Items] | ||||||||||||||||||
Number of real estate properties | location | 121 | |||||||||||||||||
Pioneer Acquisition - Tag-Along Sales Rights | ||||||||||||||||||
Business Acquisition [Line Items] | ||||||||||||||||||
Cash consideration | $ 2,900 | |||||||||||||||||
Sabalo and Shad | ||||||||||||||||||
Business Acquisition [Line Items] | ||||||||||||||||||
Area of land (in acres) | a | 21,000 | |||||||||||||||||
Total purchase price | $ 863,113 | |||||||||||||||||
Cash consideration | $ 606,126 | |||||||||||||||||
Stock issued in asset acquisition (shares) | shares | 2,506,964 | |||||||||||||||||
Transaction related expenses | $ 17,020 | |||||||||||||||||
Number of purchase and sale agreements | agreement | 2 | |||||||||||||||||
Sabalo and Shad - Howard and Borden County Gross - Operated Locations | ||||||||||||||||||
Business Acquisition [Line Items] | ||||||||||||||||||
Number of real estate properties | location | 120 | |||||||||||||||||
Sabalo and Shad - Howard and Borden County Net - Operated Locations | ||||||||||||||||||
Business Acquisition [Line Items] | ||||||||||||||||||
Number of real estate properties | location | 109 | |||||||||||||||||
Sabalo and Shad - Howard and Borden County Gross - Non-Operated Locations | ||||||||||||||||||
Business Acquisition [Line Items] | ||||||||||||||||||
Number of real estate properties | location | 150 | |||||||||||||||||
Sabalo and Shad - Howard and Borden County Net - Non-Operated Locations | ||||||||||||||||||
Business Acquisition [Line Items] | ||||||||||||||||||
Number of real estate properties | location | 18 | |||||||||||||||||
Leasehold Acquisition - Howard County, Texas | ||||||||||||||||||
Business Acquisition [Line Items] | ||||||||||||||||||
Area of land (in acres) | a | 455 | |||||||||||||||||
Acquisitions of oil and natural gas properties | $ 4,000 | |||||||||||||||||
Disposal group, disposed of by sale, not discontinued operations | ||||||||||||||||||
Business Acquisition [Line Items] | ||||||||||||||||||
Average working interest (as a percent) | 37.50% | |||||||||||||||||
Sixth Street PSA | Disposal group, disposed of by sale, not discontinued operations | ||||||||||||||||||
Business Acquisition [Line Items] | ||||||||||||||||||
Proceeds after transaction costs | 405,000 | |||||||||||||||||
Aggregate quarterly payments of additional cash contingent consideration | 38,700 | |||||||||||||||||
Balloon payment of additional cash contingent consideration | 55,000 | |||||||||||||||||
Fair value of contingent consideration | 33,800 | $ 35,900 | ||||||||||||||||
Gain on disposal | 93,500 | |||||||||||||||||
Transaction costs associated with disposition | 11,600 | |||||||||||||||||
Sixth Street PSA | Disposal group, disposed of by sale, not discontinued operations | Maximum | ||||||||||||||||||
Business Acquisition [Line Items] | ||||||||||||||||||
Additional cash contingent consideration | 93,700 | |||||||||||||||||
Aggregate quarterly payments of additional cash contingent consideration | $ 38,700 | |||||||||||||||||
Sixth Street PSA | Disposal group, disposed of by sale, not discontinued operations | Minimum | ||||||||||||||||||
Business Acquisition [Line Items] | ||||||||||||||||||
Pre-acquisition reserves (as a percent) | 25.00% | |||||||||||||||||
Howard County Net Acres | ||||||||||||||||||
Business Acquisition [Line Items] | ||||||||||||||||||
Area of land (in acres) | a | 80 | |||||||||||||||||
Glasscock County Net Acres | ||||||||||||||||||
Business Acquisition [Line Items] | ||||||||||||||||||
Area of land (in acres) | a | 80 | |||||||||||||||||
Proceeds after transaction costs | $ 700 | |||||||||||||||||
Number of producing wells sold | well | 2 | |||||||||||||||||
Forecast | Sixth Street PSA | Disposal group, disposed of by sale, not discontinued operations | ||||||||||||||||||
Business Acquisition [Line Items] | ||||||||||||||||||
Balloon payment of additional cash contingent consideration | $ 55,000 | |||||||||||||||||
Howard County Net Acres | ||||||||||||||||||
Business Acquisition [Line Items] | ||||||||||||||||||
Area of land (in acres) | a | 180 | 1,180 | 7,360 | 80 | 2,758 | |||||||||||||
Total purchase price | $ 600 | $ 22,500 | $ 131,700 | $ 11,600 | ||||||||||||||
Fair value of contingent consideration asset (liability) on acquisition date | $ 200 | |||||||||||||||||
Fair value of contingent consideration | $ 6,200 | |||||||||||||||||
Howard County Net Acres | WTI NYMEX | Derivatives not designated as hedges | Oil put: January 2020 - December 2020 | Crude Oil | ||||||||||||||||||
Business Acquisition [Line Items] | ||||||||||||||||||
Notional amount of derivative | $ 20,000 | |||||||||||||||||
Howard County Net Acres | Forecast | WTI NYMEX | Derivatives not designated as hedges | Oil put: January 2021 - December 2022 | Crude Oil | ||||||||||||||||||
Business Acquisition [Line Items] | ||||||||||||||||||
Notional amount of derivative | $ 1,200 | |||||||||||||||||
Acquired evaluated and unevaluated oil and natural gas properties in Howard County, Texas | ||||||||||||||||||
Business Acquisition [Line Items] | ||||||||||||||||||
Production reserve (BOE per day) | Boe | 210 | |||||||||||||||||
Howard County Net Royalty Acres | ||||||||||||||||||
Business Acquisition [Line Items] | ||||||||||||||||||
Area of land (in acres) | a | 750 | |||||||||||||||||
Reagan County Net Acres | ||||||||||||||||||
Business Acquisition [Line Items] | ||||||||||||||||||
Area of land (in acres) | a | 640 | |||||||||||||||||
Total purchase price | $ 2,900 | |||||||||||||||||
Acquired evaluated and unevaluated oil and natural gas properties in Glasscock County, Texas | ||||||||||||||||||
Business Acquisition [Line Items] | ||||||||||||||||||
Area of land (in acres) | a | 4,475 | |||||||||||||||||
Production reserve (BOE per day) | Boe | 1,400 | |||||||||||||||||
Agreed purchase price | $ 64,600 | |||||||||||||||||
Leasehold interests and Working interests | ||||||||||||||||||
Business Acquisition [Line Items] | ||||||||||||||||||
Number of real estate properties | property | 49 |
Acquisitions and divestitures_2
Acquisitions and divestitures - Purchase price (Details) - USD ($) $ / shares in Units, $ in Thousands | Oct. 18, 2021 | Jul. 01, 2021 |
Pioneer Acquisition | ||
Asset Acquisition [Line Items] | ||
Shares of Company common stock (shares) | 959,691 | |
Cash consideration | $ 131,633 | |
Transaction costs | 3,013 | |
Total purchase price | $ 205,567 | |
Pioneer Acquisition | Common stock | ||
Asset Acquisition [Line Items] | ||
Shares of Company common stock (shares) | 959,691 | |
Company common stock price at the Pioneer Closing Date (in USD per share) | $ 73.90 | |
Value of Company common stock consideration | $ 70,921 | |
Sabalo and Shad | ||
Asset Acquisition [Line Items] | ||
Shares of Company common stock (shares) | 2,506,964 | |
Cash consideration | $ 606,126 | |
Transaction costs | 17,020 | |
Total purchase price | $ 863,113 | |
Sabalo and Shad | Common stock | ||
Asset Acquisition [Line Items] | ||
Shares of Company common stock (shares) | 2,506,964 | |
Company common stock price at the Pioneer Closing Date (in USD per share) | $ 95.72 | |
Value of Company common stock consideration | $ 239,967 |
Acquisitions and divestitures_3
Acquisitions and divestitures - Assets acquired and liabilities assumed (Details) - USD ($) $ in Thousands | Oct. 18, 2021 | Jul. 01, 2021 |
Pioneer Acquisition | ||
Asset Acquisition [Line Items] | ||
Revenue suspense liabilities assumed | $ (7,722) | |
Allocated purchase price | 205,567 | |
Pioneer Acquisition | Evaluated Properties | ||
Asset Acquisition [Line Items] | ||
Properties | 139,360 | |
Pioneer Acquisition | Unevaluated Properties | ||
Asset Acquisition [Line Items] | ||
Properties | $ 73,929 | |
Sabalo and Shad | ||
Asset Acquisition [Line Items] | ||
Revenue suspense liabilities assumed | $ (4,269) | |
Inventory | 1,400 | |
Allocated purchase price | 863,113 | |
Sabalo and Shad | Evaluated Properties | ||
Asset Acquisition [Line Items] | ||
Properties | 503,005 | |
Sabalo and Shad | Unevaluated Properties | ||
Asset Acquisition [Line Items] | ||
Properties | $ 362,977 |
Acquisitions and divestitures_4
Acquisitions and divestitures - Business combination (Details) - Acquired evaluated and unevaluated oil and natural gas properties in Glasscock County, Texas $ in Thousands | Dec. 06, 2019USD ($) |
Business Acquisition [Line Items] | |
Total assets acquired | $ 67,349 |
Asset retirement obligations | (2,728) |
Net assets acquired | 64,621 |
Cash consideration | 64,621 |
Evaluated oil and natural gas properties | |
Business Acquisition [Line Items] | |
Property, plant, and equipment acquired | 29,921 |
Unevaluated oil and natural gas properties | |
Business Acquisition [Line Items] | |
Property, plant, and equipment acquired | 34,700 |
Asset retirement cost | |
Business Acquisition [Line Items] | |
Property, plant, and equipment acquired | $ 2,728 |
Leases - Lease costs (Details)
Leases - Lease costs (Details) - USD ($) $ in Thousands | 12 Months Ended | |
Dec. 31, 2021 | Dec. 31, 2020 | |
Leases [Abstract] | ||
Operating lease costs | $ 15,894 | $ 15,094 |
Short-term lease costs | 83,471 | 82,576 |
Variable lease costs | 6,873 | 10,218 |
Sublease income | (1,057) | (1,032) |
Total lease costs, net | $ 105,181 | $ 106,856 |
Leases - Supplemental cash flow
Leases - Supplemental cash flow information (Details) - USD ($) $ in Thousands | 12 Months Ended | |
Dec. 31, 2021 | Dec. 31, 2020 | |
Leases [Abstract] | ||
Operating cash flows from operating leases | $ 4,065 | $ 5,910 |
Investing cash flows from operating leases | $ 12,569 | $ 9,425 |
Leases - Lease terms and discou
Leases - Lease terms and discount rates (Details) | Dec. 31, 2021 | Dec. 31, 2020 |
Operating leases: | ||
Weighted-average remaining lease term | 2 years 9 months 18 days | 2 years 10 months 13 days |
Weighted-average discount rate (as a percent) | 7.41% | 7.72% |
Leases - Maturities of operatin
Leases - Maturities of operating lease liabilities (Details) - USD ($) $ in Thousands | Dec. 31, 2021 | Dec. 31, 2020 |
Operating leases: | ||
2022 | $ 8,399 | |
2023 | 1,925 | |
2024 | 1,428 | |
2025 | 1,423 | |
2026 | 1,348 | |
Thereafter | 666 | |
Total minimum lease payments | 15,189 | |
Less: lease liability expense | (1,721) | |
Present value of future minimum lease payments | 13,468 | |
Less: current operating lease liabilities | (7,742) | $ (11,721) |
Noncurrent operating lease liabilities | $ 5,726 | $ 8,918 |
Property and equipment - Oil an
Property and equipment - Oil and natural gas properties (Details) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2021USD ($)$ / MMcf$ / bbl$ / Boe$ / MMBTU | Dec. 31, 2020USD ($)$ / bbl$ / MMcf$ / Boe$ / MMBTU | Dec. 31, 2019USD ($)$ / MMcf$ / bbl$ / MMBTU$ / Boe | |
Property, Plant and Equipment [Line Items] | |||
Capitalized employee-related costs | $ | $ 18,225 | $ 18,954 | $ 18,299 |
Depletion expense of evaluated oil and natural gas properties | $ | $ 201,691 | $ 203,492 | $ 250,857 |
Depletion per BOE sold (USD per BOE) | $ / Boe | 6.76 | 6.34 | 8.50 |
Discount rate used in calculating full cost ceiling (as a percent) | 10.00% | ||
Non-cash full cost ceiling impairment | $ | $ 0 | $ 889,453 | $ 620,565 |
Crude Oil | |||
Property, Plant and Equipment [Line Items] | |||
Benchmark prices (USD per barrel or MMBtu) | 63.04 | 36.04 | 52.19 |
Realized prices (USD per barrel or Mcf) | 66.37 | 37.69 | 52.12 |
Commodity - NGL | |||
Property, Plant and Equipment [Line Items] | |||
Benchmark prices (USD per barrel or MMBtu) | 34.51 | 16.63 | 21.14 |
Realized prices (USD per barrel or Mcf) | 22.90 | 7.43 | 12.21 |
Commodity - Natural gas | |||
Property, Plant and Equipment [Line Items] | |||
Benchmark prices (USD per barrel or MMBtu) | $ / MMBTU | 3.35 | 1.21 | 0.87 |
Realized prices (USD per barrel or Mcf) | $ / MMcf | 2.61 | 0.79 | 0.53 |
Property and equipment - Midstr
Property and equipment - Midstream service assets (Details) - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2021 | Dec. 31, 2020 | Dec. 31, 2019 | |
Property, Plant and Equipment [Line Items] | |||
Total midstream service assets, net | $ 96,528 | $ 112,697 | |
Depletion, depreciation and amortization | 215,355 | 217,101 | $ 265,746 |
Midstream service assets | |||
Property, Plant and Equipment [Line Items] | |||
Midstream service assets | 165,232 | 181,718 | |
Less accumulated depreciation and impairment | (68,704) | (69,021) | |
Total midstream service assets, net | 96,528 | 112,697 | |
Retired midstream service assets | 18,800 | ||
Accumulated depreciation | 9,400 | ||
Loss on retirement of midstream service assets | 9,400 | ||
Depletion, depreciation and amortization | $ 9,514 | $ 9,838 | $ 10,206 |
Midstream service assets | Minimum | |||
Property, Plant and Equipment [Line Items] | |||
Useful life | 10 years | ||
Midstream service assets | Maximum | |||
Property, Plant and Equipment [Line Items] | |||
Useful life | 20 years |
Property and equipment - Other
Property and equipment - Other fixed assets (Details) - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2021 | Dec. 31, 2020 | Dec. 31, 2019 | |
Property, Plant and Equipment [Line Items] | |||
Total other fixed assets, net | $ 34,590 | $ 32,011 | |
Depreciation and amortization of other fixed assets | 215,355 | 217,101 | $ 265,746 |
Computer hardware and software | |||
Property, Plant and Equipment [Line Items] | |||
Other fixed assets, net | 15,039 | 9,388 | |
Vehicles | |||
Property, Plant and Equipment [Line Items] | |||
Other fixed assets, net | 9,072 | 9,852 | |
Leasehold improvements | |||
Property, Plant and Equipment [Line Items] | |||
Other fixed assets, net | 7,136 | 7,125 | |
Buildings | |||
Property, Plant and Equipment [Line Items] | |||
Other fixed assets, net | 7,039 | 6,982 | |
Other | |||
Property, Plant and Equipment [Line Items] | |||
Other fixed assets, net | 5,095 | 4,107 | |
Depreciable total, net | |||
Property, Plant and Equipment [Line Items] | |||
Other fixed assets, net | 43,381 | 37,454 | |
Less accumulated depreciation and impairment | (27,692) | (24,344) | |
Total other fixed assets, net | 15,689 | 13,110 | |
Land | |||
Property, Plant and Equipment [Line Items] | |||
Total other fixed assets, net | 18,901 | 18,901 | |
Other fixed assets | |||
Property, Plant and Equipment [Line Items] | |||
Depreciation and amortization of other fixed assets | $ 4,150 | $ 3,771 | $ 4,683 |
Minimum | Other fixed assets | |||
Property, Plant and Equipment [Line Items] | |||
Useful life | 3 years | ||
Maximum | Other fixed assets | |||
Property, Plant and Equipment [Line Items] | |||
Useful life | 10 years |
Debt - July 2029 Notes (Details
Debt - July 2029 Notes (Details) - July 2029 Notes - Senior Notes $ in Millions | Jul. 16, 2021USD ($) |
Debt Instrument [Line Items] | |
Face amount of debt | $ 400 |
Stated rate (as a percent) | 7.75% |
Proceeds from issuance of unsecured notes | $ 392 |
Debt - January 2025 Notes and J
Debt - January 2025 Notes and January 2028 Notes (Details) - USD ($) | Jan. 24, 2020 | Dec. 31, 2021 | Dec. 31, 2020 | Dec. 31, 2019 | Nov. 30, 2020 |
Debt Instrument [Line Items] | |||||
Authorized amount of bond repurchase program | $ 50,000,000 | ||||
Extinguishment of debt | $ 0 | $ 846,994,000 | $ 0 | ||
Gain on extinguishment of debt | $ 0 | 8,989,000 | $ 0 | ||
Senior Notes | January 2025 Notes & January 2028 Notes | |||||
Debt Instrument [Line Items] | |||||
Proceeds from issuance of unsecured notes | $ 982,000,000 | ||||
Gain on extinguishment of debt | 22,300,000 | ||||
Senior Notes | January 2025 Notes | |||||
Debt Instrument [Line Items] | |||||
Face amount of debt | $ 600,000,000 | ||||
Stated rate (as a percent) | 9.50% | ||||
Repurchased aggregate principal amount | 22,100,000 | ||||
Extinguishment of debt | 13,900,000 | ||||
Senior Notes | January 2028 Notes | |||||
Debt Instrument [Line Items] | |||||
Face amount of debt | $ 400,000,000 | ||||
Stated rate (as a percent) | 10.125% | ||||
Repurchased aggregate principal amount | 39,000,000 | ||||
Extinguishment of debt | $ 24,200,000 |
Debt - January 2022 Notes and M
Debt - January 2022 Notes and March 2023 Notes (Details) - USD ($) | Mar. 15, 2020 | Feb. 06, 2020 | Jan. 29, 2020 | Jan. 24, 2020 | Dec. 31, 2021 | Dec. 31, 2020 | Dec. 31, 2019 | Mar. 18, 2015 | Jan. 23, 2014 |
Debt Instrument [Line Items] | |||||||||
Outstanding balance | $ 1,425,858,000 | $ 1,179,266,000 | |||||||
Extinguishment of debt | 0 | 846,994,000 | $ 0 | ||||||
Loss on extinguishment of debt | 0 | $ (8,989,000) | $ 0 | ||||||
Senior Notes | January 2022 Notes & March 2023 Notes | |||||||||
Debt Instrument [Line Items] | |||||||||
Loss on extinguishment of debt | $ 13,300,000 | ||||||||
Senior Notes | Senior Note 5.625 Percent Due 2022 | |||||||||
Debt Instrument [Line Items] | |||||||||
Face amount of debt | $ 450,000,000 | ||||||||
Stated rate (as a percent) | 5.625% | ||||||||
Outstanding balance | $ 428,900,000 | ||||||||
Extinguishment of debt | $ 21,100,000 | $ 431,600,000 | |||||||
Redemption price (as a percent) | 100.00% | ||||||||
Senior Notes | Senior Note 6.25 Percent Due 2023 | |||||||||
Debt Instrument [Line Items] | |||||||||
Face amount of debt | $ 350,000,000 | ||||||||
Stated rate (as a percent) | 6.25% | ||||||||
Outstanding balance | $ 299,400,000 | ||||||||
Extinguishment of debt | $ 50,600,000 | $ 304,100,000 | |||||||
Redemption price (as a percent) | 101.563% |
Debt - Senior Secured Credit Fa
Debt - Senior Secured Credit Facility (Details) | Jul. 16, 2021 | Dec. 31, 2020USD ($) | Jun. 30, 2021 | Mar. 31, 2021 | Sep. 30, 2020 | Dec. 31, 2021USD ($) | May 07, 2021USD ($) |
Debt Instrument [Line Items] | |||||||
Unrestricted and unencumbered cash and cash equivalents maximum | $ 50,000,000 | ||||||
Secured Debt | Minimum | Base Rate | |||||||
Debt Instrument [Line Items] | |||||||
Basis spread on variable rate (as a percent) | 1.50% | ||||||
Secured Debt | Maximum | Base Rate | |||||||
Debt Instrument [Line Items] | |||||||
Basis spread on variable rate (as a percent) | 2.50% | ||||||
Secured Debt | Line of Credit | |||||||
Debt Instrument [Line Items] | |||||||
Collateral as a percentage of present value of proved reserves (as a percent) | 85.00% | ||||||
Current ratio requirement (not less than) | 1 | ||||||
Consolidated interest coverage ratio (not less than) | 3.50 | 3.75 | 4 | 4.25 | |||
Secured Debt | Senior Secured Credit Facility | |||||||
Debt Instrument [Line Items] | |||||||
Commitment fee on unused capacity (as a percent) | 0.50% | ||||||
Secured Debt | Senior Secured Credit Facility | Minimum | London Interbank Offered Rate (LIBOR) | |||||||
Debt Instrument [Line Items] | |||||||
Basis spread on variable rate (as a percent) | 2.50% | ||||||
Secured Debt | Senior Secured Credit Facility | Maximum | London Interbank Offered Rate (LIBOR) | |||||||
Debt Instrument [Line Items] | |||||||
Basis spread on variable rate (as a percent) | 3.50% | ||||||
Line of Credit | Secured Debt | |||||||
Debt Instrument [Line Items] | |||||||
Current borrowing capacity | $ 1,000,000,000 | $ 725,000,000 | |||||
Period of extension to maturity | 2 years | ||||||
Borrowing capacity | 2,000,000,000 | ||||||
Aggregate elected commitment | 725,000,000 | ||||||
Line of credit | $ 105,000,000 | ||||||
Credit facility, interest rate at period end (as a percent) | 2.625% | ||||||
Letters of credit | Secured Debt | |||||||
Debt Instrument [Line Items] | |||||||
Borrowing capacity | $ 80,000,000 | ||||||
Letters of credit outstanding | $ 44,100,000 | $ 44,100,000 |
Debt - Debt issuance costs (Det
Debt - Debt issuance costs (Details) - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2021 | Dec. 31, 2020 | Dec. 31, 2019 | |
Debt Instrument [Line Items] | |||
Debt issuance costs capitalized | $ 14,686 | $ 18,479 | $ 0 |
Debt issuance costs write-offs | 0 | 6,163 | 935 |
Write-off of debt issuance costs | 0 | 1,103 | 935 |
Total debt issuance costs, including line of credit | 26,200 | 17,000 | |
Accumulated amortization | 27,200 | 22,100 | |
Debt Issuance Costs, Future Amortization Expense [Abstract] | |||
2022 | 6,165 | ||
2023 | 6,165 | ||
2024 | 6,165 | ||
2025 | 2,894 | ||
2026 | 1,735 | ||
Thereafter | 3,079 | ||
Total | 26,203 | ||
Secured Debt | |||
Debt Instrument [Line Items] | |||
Debt issuance costs capitalized | $ 14,700 | ||
Write-off of debt issuance costs | 1,100 | $ 900 | |
Senior Notes | |||
Debt Instrument [Line Items] | |||
Debt issuance costs capitalized | 18,500 | ||
Write-off of debt issuance costs | $ 5,100 |
Debt - Interest expense (Detail
Debt - Interest expense (Details) - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2021 | Dec. 31, 2020 | Dec. 31, 2019 | |
Debt Disclosure [Abstract] | |||
Cash payments for interest | $ 100,733 | $ 80,420 | $ 59,021 |
Amortization of debt issuance costs and other adjustments | 4,451 | 3,708 | 3,111 |
Change in accrued interest | 14,067 | 23,900 | 220 |
Interest costs incurred | 119,251 | 108,028 | 62,352 |
Less capitalized interest | (5,866) | (3,019) | (805) |
Total interest expense | $ 113,385 | $ 105,009 | $ 61,547 |
Debt - Long-term debt, net (Det
Debt - Long-term debt, net (Details) - USD ($) $ in Thousands | Dec. 31, 2021 | Dec. 31, 2020 |
Debt Instrument [Line Items] | ||
Long-term debt | $ 1,443,957 | $ 1,193,957 |
Debt issuance costs, net | (18,099) | (14,691) |
Long-term debt, net | 1,425,858 | 1,179,266 |
Senior Notes | January 2025 Notes | ||
Debt Instrument [Line Items] | ||
Long-term debt | 577,913 | 577,913 |
Debt issuance costs, net | (6,345) | (8,676) |
Long-term debt, net | 571,568 | 569,237 |
Senior Notes | January 2028 Notes | ||
Debt Instrument [Line Items] | ||
Long-term debt | 361,044 | 361,044 |
Debt issuance costs, net | (5,024) | (6,015) |
Long-term debt, net | 356,020 | 355,029 |
Senior Notes | July 2029 Notes | ||
Debt Instrument [Line Items] | ||
Long-term debt | 400,000 | 0 |
Debt issuance costs, net | (6,730) | 0 |
Long-term debt, net | 393,270 | 0 |
Senior Secured Credit Facility | Line of Credit | ||
Debt Instrument [Line Items] | ||
Long-term debt | 105,000 | 255,000 |
Debt issuance costs, net | 0 | 0 |
Long-term debt, net | 105,000 | 255,000 |
Senior Secured Credit Facility | Line of Credit | Other Noncurrent Assets | ||
Debt Instrument [Line Items] | ||
Debt issuance costs, net | $ 8,100 | $ 2,300 |
Stockholders' equity - Narrativ
Stockholders' equity - Narrative (Details) $ / shares in Units, $ in Millions | Feb. 23, 2021USD ($) | Jun. 01, 2020$ / sharesshares | Dec. 31, 2021$ / sharesshares | Oct. 18, 2021$ / shares | Dec. 31, 2020$ / sharesshares | May 31, 2020shares |
Class of Stock [Line Items] | ||||||
Conversation ratio of reverse stock split | 0.05 | |||||
Common stock authorized (shares) | 22,500,000 | 22,500,000 | 22,500,000 | 450,000,000 | ||
Common stock, par value (USD per share) | $ / shares | $ 0.01 | $ 0.01 | $ 0.01 | $ 0.01 | ||
Preferred stock authorized (shares) | 50,000,000 | 50,000,000 | 50,000,000 | |||
Preferred stock, par value (USD per share) | $ / shares | $ 0.01 | $ 0.01 | $ 0.01 | |||
Capital stock authorized (shares) | 72,500,000 | |||||
At-the-Market Offering | ||||||
Class of Stock [Line Items] | ||||||
Consideration received from sale of stock | $ | $ 75 | |||||
Stock issued in sale (in shares) | 1,438,105 | |||||
Maximum | At-the-Market Offering | ||||||
Class of Stock [Line Items] | ||||||
Consideration received from sale of stock | $ | $ 72.5 |
Compensation plans - Narrative
Compensation plans - Narrative (Details) $ in Millions | Mar. 05, 2020 | Dec. 31, 2021USD ($)anniversaryinstallmentshares | May 20, 2021shares | Jun. 01, 2020shares |
401(k) Plan | ||||
Equity and stock-based compensation | ||||
Tax-deferred contributions of eligible employees as a percentage of their annual compensation (as a percent) | 100.00% | |||
Employer matching contribution (as a percent) | 6.00% | |||
Proportion of employer contributions vested upon receipt (as a percent) | 100.00% | |||
Restricted stock awards | ||||
Equity and stock-based compensation | ||||
Unrecognized equity and stock-based compensation expense | $ | $ 7.2 | |||
Weighted average period over which unrecognized equity and stock-based compensation expense is expected to be recognized (in years) | 1 year 11 months 8 days | |||
Restricted stock awards | One Year From Grant Date | ||||
Equity and stock-based compensation | ||||
Vesting rights (as a percent) | 33.00% | |||
Restricted stock awards | Two Years from Grant Date | ||||
Equity and stock-based compensation | ||||
Vesting rights (as a percent) | 33.00% | |||
Restricted stock awards | Three Years from Grant Date | ||||
Equity and stock-based compensation | ||||
Vesting rights (as a percent) | 34.00% | |||
Stock option awards | ||||
Equity and stock-based compensation | ||||
Requisite service period (in years) | 4 years | |||
Number of installments over which awards vest and are exercisable | installment | 4 | |||
Number of anniversaries over which awards vest and are exercisable | anniversary | 4 | |||
Options, life of award (in years) | 10 years | |||
Post employment, vested awards expiration period (in years) | 1 year | |||
Post employment, vested awards expiration period (in days) | 90 days | |||
Performance share awards | ||||
Equity and stock-based compensation | ||||
Total shareholder return | 3 years | |||
Performance share awards | Minimum | ||||
Equity and stock-based compensation | ||||
Payout range (as a percent) | 0.00% | |||
Performance share awards | Maximum | ||||
Equity and stock-based compensation | ||||
Payout range (as a percent) | 200.00% | |||
Outperformance share award | ||||
Equity and stock-based compensation | ||||
Unrecognized equity and stock-based compensation expense | $ | $ 0.2 | |||
Weighted average period over which unrecognized equity and stock-based compensation expense is expected to be recognized (in years) | 1 year 9 months 10 days | |||
Number of consecutive trading days average closing stock price for payout computation | 50 days | |||
Outperformance share award | Minimum | ||||
Equity and stock-based compensation | ||||
Payout range (shares) | shares | 0 | |||
Outperformance share award | Maximum | ||||
Equity and stock-based compensation | ||||
Payout range (shares) | shares | 50,000 | |||
Outperformance share award | June 3, 2019 | ||||
Equity and stock-based compensation | ||||
Requisite service period (in years) | 3 years | |||
Performance unit awards | ||||
Equity and stock-based compensation | ||||
Unrecognized equity and stock-based compensation expense | $ | $ 10.8 | |||
Weighted average period over which unrecognized equity and stock-based compensation expense is expected to be recognized (in years) | 1 year 10 months 9 days | |||
Requisite service period (in years) | 3 years | |||
Performance unit awards | Minimum | ||||
Equity and stock-based compensation | ||||
Payout range (as a percent) | 0.00% | |||
Performance unit awards | Maximum | ||||
Equity and stock-based compensation | ||||
Payout range (as a percent) | 200.00% | |||
Payout range if ATSR Appreciation is zero or less (as a percent) | 100.00% | |||
Performance unit awards | March 09, 2021 | Minimum | ||||
Equity and stock-based compensation | ||||
Payout rate of market criteria awards (as a percent) | 0.00% | |||
Payout rate of performance criteria awards (as a percent) | 0.00% | |||
Performance unit awards | March 09, 2021 | Maximum | ||||
Equity and stock-based compensation | ||||
Payout rate of market criteria awards (as a percent) | 250.00% | |||
Payout rate of performance criteria awards (as a percent) | 200.00% | |||
Phantom unit awards | ||||
Equity and stock-based compensation | ||||
Unrecognized equity and stock-based compensation expense | $ | $ 1.2 | |||
Weighted average period over which unrecognized equity and stock-based compensation expense is expected to be recognized (in years) | 1 year 4 months 2 days | |||
Ratio of common stock for each phantom unit | 1 | |||
Phantom unit awards | Final Date | ||||
Equity and stock-based compensation | ||||
Vesting rights (as a percent) | 33.00% | |||
Phantom unit awards | First Anniversary of Final Date | ||||
Equity and stock-based compensation | ||||
Vesting rights (as a percent) | 33.00% | |||
Phantom unit awards | Second Anniversary of Final Date | ||||
Equity and stock-based compensation | ||||
Vesting rights (as a percent) | 34.00% | |||
Equity Incentive Plan | ||||
Equity and stock-based compensation | ||||
Number of shares authorized (shares) | shares | 1,492,500 | |||
Equity Incentive Plan | Minimum | ||||
Equity and stock-based compensation | ||||
Number of shares authorized (shares) | shares | 1,492,500 | |||
Equity Incentive Plan | Maximum | ||||
Equity and stock-based compensation | ||||
Number of shares authorized (shares) | shares | 2,432,500 | |||
February 2014, February 2015, May 25, and April 1 Performance Share Awards | Performance share awards | February 2014, February 2015, May 25, and April 1 | ||||
Equity and stock-based compensation | ||||
Unrecognized equity and stock-based compensation expense | $ | $ 0.3 | |||
Weighted average period over which unrecognized equity and stock-based compensation expense is expected to be recognized (in years) | 1 month 28 days | |||
Requisite service period (in years) | 3 years |
Compensation plans - Restricted
Compensation plans - Restricted stock awards activity (Details) - Restricted stock awards - USD ($) $ / shares in Units, shares in Thousands, $ in Millions | 12 Months Ended | ||
Dec. 31, 2021 | Dec. 31, 2020 | Dec. 31, 2019 | |
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Number of Shares [Roll Forward] | |||
Outstanding at the beginning of the period (shares) | 309 | 275 | 210 |
Granted (shares) | 237 | 238 | 381 |
Forfeited (shares) | (42) | (48) | (178) |
Vested (shares) | (154) | (156) | (138) |
Outstanding at the end of the period (shares) | 350 | 309 | 275 |
Weighted-average grant-date fair value (per award) | |||
Outstanding at the beginning of the period (USD per share) | $ 44.88 | $ 85.80 | $ 198.20 |
Granted (USD per share) | 38.86 | 16.54 | 65.20 |
Forfeited (USD per share) | 42.44 | 53.51 | 102.20 |
Vested (USD per share) | 57.37 | 71.25 | 178.40 |
Outstanding at the end of the period (USD per share) | $ 35.57 | $ 44.88 | $ 85.80 |
Intrinsic value of vested restricted stock awards | $ 7.3 |
Compensation plans - Restrict_2
Compensation plans - Restricted stock option awards activity (Details) - Stock option awards - USD ($) $ / shares in Units, shares in Thousands | 12 Months Ended | |||
Dec. 31, 2021 | Dec. 31, 2020 | Dec. 31, 2019 | Dec. 31, 2018 | |
Stock option awards | ||||
Outstanding at the beginning of the period (shares) | 11 | 17 | 127 | |
Exercised (shares) | (2) | (1) | ||
Expired or canceled (shares) | (2) | (6) | (92) | |
Forfeited (shares) | (17) | |||
Outstanding at the end of the period (shares) | 7 | 11 | 17 | 127 |
Weighted-average exercise price (per award) | ||||
Outstanding at the end of the period (USD per share) | $ 257.42 | $ 251.20 | $ 253.80 | |
Exercised (USD per share) | 82 | 82 | ||
Expired or canceled (USD per share) | 374.77 | 238.38 | 271 | |
Forfeited (USD per share) | 172.20 | |||
Outstanding at end of the period (USD per share) | $ 275.88 | $ 257.42 | $ 251.20 | $ 253.80 |
Weighted-average remaining contractual term (years) | ||||
Outstanding at the end of the period | 3 years 2 months 26 days | 4 years | 5 years | 5 years 11 months 26 days |
Intrinsic value, options exercisable | $ 0 |
Compensation plans - Restrict_3
Compensation plans - Restricted stock option awards full years of continuous employment (Details) - Stock option awards | 12 Months Ended |
Dec. 31, 2021 | |
Less than one | |
Equity and stock-based compensation | |
Incremental percentage of option exercisable | 0.00% |
Cumulative percentage of option exercisable | 0.00% |
One | |
Equity and stock-based compensation | |
Incremental percentage of option exercisable | 25.00% |
Cumulative percentage of option exercisable | 25.00% |
Two | |
Equity and stock-based compensation | |
Incremental percentage of option exercisable | 25.00% |
Cumulative percentage of option exercisable | 50.00% |
Three | |
Equity and stock-based compensation | |
Incremental percentage of option exercisable | 25.00% |
Cumulative percentage of option exercisable | 75.00% |
Four | |
Equity and stock-based compensation | |
Incremental percentage of option exercisable | 25.00% |
Cumulative percentage of option exercisable | 100.00% |
Compensation plans - Performanc
Compensation plans - Performance shares award activity (Details) - $ / shares | 12 Months Ended | 36 Months Ended | |||||
Dec. 31, 2021 | Dec. 31, 2020 | Dec. 31, 2019 | Dec. 31, 2021 | Dec. 31, 2020 | Dec. 31, 2019 | Dec. 31, 2018 | |
Performance share awards | |||||||
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Number of Shares [Roll Forward] | |||||||
Outstanding at the beginning of the period (shares) | 97,000 | 115,000 | 172,000 | 172,000 | |||
Granted (shares) | 29,000 | ||||||
Converted from performance unit awards (shares) | 78,000 | ||||||
Forfeited (shares) | (10,000) | (10,000) | (87,000) | ||||
Lapsed (shares) | (8,000) | (77,000) | |||||
Vested (shares) | (15,000) | ||||||
Outstanding at the end of the period (shares) | 72,000 | 97,000 | 115,000 | 72,000 | 97,000 | 115,000 | 172,000 |
Weighted-average grant-date fair value (per award) | |||||||
Outstanding at the beginning of the period (USD per share) | $ 84.06 | $ 106.80 | $ 274.80 | $ 274.80 | |||
Granted (USD per share) | 50.40 | ||||||
Converted from performance unit awards (USD per share) | 74.80 | ||||||
Forfeited (USD per share) | 74.70 | 110.94 | 209.60 | ||||
Lapsed (USD per share) | 379.20 | 346.20 | |||||
Vested (USD per share) | 184.43 | ||||||
Outstanding at the end of the period (USD per share) | $ 64.74 | $ 84.06 | $ 106.80 | $ 64.74 | $ 84.06 | $ 106.80 | $ 274.80 |
Actual payout (as a percent) | 43.00% | ||||||
Performance share conversion (in shares) | 6,343 | ||||||
February 16, 2018 | Performance Shares with Market Criteria | |||||||
Weighted-average grant-date fair value (per award) | |||||||
RTSR Factor weight / TSR Modifier (as a percent) | 25.00% | ||||||
ATSR Factor weight (as a percent) | 25.00% | ||||||
February 16, 2018 | Performance Shares with Performance Criteria | |||||||
Weighted-average grant-date fair value (per award) | |||||||
ROACE Factor weight (as a percent) | 50.00% | ||||||
February 28, 2019 and June 3, 2019 | |||||||
Weighted-average grant-date fair value (per award) | |||||||
Overall payout (as a percent) | 107.00% | ||||||
April 1, 2016 and May 25, 2016 | Performance share awards | 2016 Performance Share Award | |||||||
Weighted-average grant-date fair value (per award) | |||||||
RTSR Factor weight / TSR Modifier (as a percent) | 0.00% | ||||||
February 17, 2017 | Performance share awards | |||||||
Weighted-average grant-date fair value (per award) | |||||||
RTSR Factor weight / TSR Modifier (as a percent) | 0.00% |
Compensation plans - Performa_2
Compensation plans - Performance share awards assumptions used to estimate the fair value (Details) - USD ($) $ / shares in Units, $ in Millions | May 16, 2019 | Dec. 31, 2021 | Dec. 31, 2019 | Mar. 05, 2021 |
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ||||
Closing stock price on grant date (in dollars per share) | $ 34.24 | |||
Performance share awards | ||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ||||
Fair value per performance share award (USD per share) | $ 50.40 | |||
Performance share awards | June 3, 2019 | ||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ||||
Fair value per performance share award (USD per share) | $ 65.94 | |||
Expense per performance share award (in dollars per share) | 65.94 | |||
Performance share awards | February 28, 2019 | ||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ||||
Fair value per performance share award (USD per share) | 95.65 | |||
Expense per performance share award (in dollars per share) | $ 95.65 | |||
Incremental compensation expense | $ 1 | |||
Performance Shares with Market Criteria | June 3, 2019 | ||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ||||
Remaining performance period on grant date | 2 years 6 months 29 days | |||
Risk-free interest rate (as a percent) | 1.78% | |||
Dividend yield (as a percent) | 0.00% | |||
Expected volatility (as a percent) | 55.45% | |||
Closing stock price on grant date (in dollars per share) | $ 51.80 | |||
Fair value per performance share award (USD per share) | 49 | |||
Expense per performance share award (in dollars per share) | $ 49 | |||
Performance Shares with Market Criteria | February 28, 2019 | ||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ||||
Remaining performance period on grant date | 2 years 7 months 17 days | |||
Risk-free interest rate (as a percent) | 2.14% | |||
Dividend yield (as a percent) | 0.00% | |||
Expected volatility (as a percent) | 55.01% | |||
Closing stock price on grant date (in dollars per share) | $ 69.80 | |||
Fair value per performance share award (USD per share) | 79.61 | |||
Expense per performance share award (in dollars per share) | $ 79.61 | |||
RTSR Factor weight / TSR Modifier (as a percent) | 25.00% | |||
ATSR Factor weight (as a percent) | 25.00% | |||
Performance Shares with Performance Criteria | June 3, 2019 | ||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ||||
Closing stock price on grant date (in dollars per share) | $ 51.80 | |||
Fair value per performance share award (USD per share) | $ 51.80 | |||
Estimated payout for expense (as a percent) | 160.00% | |||
Expense per performance share award (in dollars per share) | $ 82.88 | |||
Performance Shares with Performance Criteria | February 28, 2019 | ||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ||||
Closing stock price on grant date (in dollars per share) | 69.80 | |||
Fair value per performance share award (USD per share) | $ 69.80 | |||
Estimated payout for expense (as a percent) | 160.00% | |||
Expense per performance share award (in dollars per share) | $ 111.68 | |||
ROACE Factor weight (as a percent) | 50.00% |
Compensation plans - Outperform
Compensation plans - Outperformance share awards assumptions used to estimate fair value (Details) - USD ($) | 12 Months Ended | |
Dec. 31, 2021 | Mar. 05, 2021 | |
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ||
Closing stock price on grant date (in dollars per share) | $ 34.24 | |
Outperformance share award | June 3, 2019 | ||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ||
Performance period | 3 years | |
Risk-free interest rate (as a percent) | 1.77% | |
Dividend yield (as a percent) | 0.00% | |
Expected volatility (as a percent) | 55.77% | |
Closing stock price on grant date (in dollars per share) | $ 51.80 | |
Total fair value of outperformance share award (in thousands) | $ 670,000 |
Compensation plans - Performa_3
Compensation plans - Performance unit award activity (Details) - shares shares in Thousands | 12 Months Ended | |
Dec. 31, 2021 | Dec. 31, 2020 | |
March 09, 2021 | ||
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Number of Shares [Roll Forward] | ||
EBITDAX/Total Debt Component (as a percent) | 25.00% | |
Inventory Growth Component (as a percent) | 25.00% | |
Performance Share Unit Matrix | 50.00% | |
Performance unit awards | ||
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Number of Shares [Roll Forward] | ||
Outstanding at the beginning of the period (shares) | 99 | 0 |
Granted (shares) | 110 | 123 |
Forfeited (shares) | (24) | |
Outstanding at the end of the period (shares) | 209 | 99 |
Compensation plans - Assumption
Compensation plans - Assumptions used to estimate fair value of performance unit awards (Details) - $ / shares | 12 Months Ended | |
Dec. 31, 2021 | Mar. 05, 2021 | |
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ||
Closing stock price on grant date (in dollars per share) | $ 34.24 | |
March 09, 2021 | ||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ||
Performance Share Unit Matrix | 50.00% | |
EBITDAX/Total Debt Component (as a percent) | 25.00% | |
Inventory Growth Component (as a percent) | 25.00% | |
Performance unit awards | March 5, 2020 | ||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ||
Fair value per performance share award (USD per share) | $ 91.31 | |
Expense per performance share award (in dollars per share) | 91.31 | |
Performance unit awards | March 09, 2021 | ||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ||
Fair value per performance share award (USD per share) | 90.92 | |
Expense per performance share award (in dollars per share) | $ 90.92 | |
Performance unit awards with market criteria | March 5, 2020 | ||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ||
Expected option life (in years) | 1 year | |
Risk-free interest rate (as a percent) | 0.39% | |
Dividend yield (as a percent) | 0.00% | |
Expected volatility (as a percent) | 86.17% | |
Closing stock price on grant date (in dollars per share) | $ 60.13 | |
Fair value per performance share award (USD per share) | 195.77 | |
Expense per performance share award (in dollars per share) | $ 195.77 | |
Performance unit awards with market criteria | March 09, 2021 | ||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ||
Expected option life (in years) | 2 years | |
Risk-free interest rate (as a percent) | 0.73% | |
Dividend yield (as a percent) | 0.00% | |
Expected volatility (as a percent) | 135.42% | |
Closing stock price on grant date (in dollars per share) | $ 60.13 | |
Fair value per performance share award (USD per share) | 121.72 | |
Expense per performance share award (in dollars per share) | 121.72 | |
Performance unit awards with performance criteria | March 5, 2020 | ||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ||
Closing stock price on grant date (in dollars per share) | $ 60.13 | |
Estimated payout for expense (as a percent) | 130.00% | |
Fair value per performance share award (USD per share) | $ 60.13 | |
Expense per performance share award (in dollars per share) | 78.17 | |
Performance unit awards with performance criteria | March 09, 2021 | ||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ||
Closing stock price on grant date (in dollars per share) | $ 60.13 | |
Estimated payout for expense (as a percent) | 100.00% | |
Fair value per performance share award (USD per share) | $ 60.13 | |
Expense per performance share award (in dollars per share) | $ 60.13 |
Compensation plans - Phantom un
Compensation plans - Phantom unit award activity (Details) - $ / shares shares in Thousands | 12 Months Ended | ||
Dec. 31, 2021 | Dec. 31, 2020 | Mar. 05, 2021 | |
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Number of Shares [Roll Forward] | |||
Stock price (in USD per share) | $ 34.24 | ||
Phantom unit awards | |||
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Number of Shares [Roll Forward] | |||
Outstanding at the beginning of the period (shares) | 75 | 0 | |
Granted (shares) | 5 | 75 | |
Forfeited (shares) | (22) | ||
Vested (shares) | (25) | ||
Outstanding at the end of the period (shares) | 33 | 75 | |
Fair value (USD per share) | $ 60.13 | ||
Performance Shares with Performance Criteria | February 28, 2019 | |||
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Number of Shares [Roll Forward] | |||
Stock price (in USD per share) | $ 69.80 | ||
ROACE Factor weight (as a percent) | 50.00% |
Compensation plans - Equity-bas
Compensation plans - Equity-based compensation (Details) - 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] | |||
Less amounts capitalized | $ (1,583) | $ (3,418) | $ (4,470) |
Equity-based compensation | 16,028 | 9,207 | 8,290 |
Share-settled | |||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||
Total share-settled equity-based compensation, gross | 9,258 | 11,635 | 12,760 |
Less amounts capitalized | (1,583) | (3,418) | (4,470) |
Equity-based compensation | 7,675 | 8,217 | 8,290 |
Restricted stock awards | |||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||
Total share-settled equity-based compensation, gross | 7,594 | 8,839 | 13,169 |
Performance share awards | |||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||
Total share-settled equity-based compensation, gross | 1,482 | 2,545 | (1,250) |
Outperformance share award | |||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||
Total share-settled equity-based compensation, gross | 175 | 174 | 101 |
Stock option awards | |||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||
Total share-settled equity-based compensation, gross | 7 | 77 | 740 |
Cash-settled | |||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||
Total share-settled equity-based compensation, gross | 8,718 | 1,153 | 0 |
Less amounts capitalized | (365) | (163) | 0 |
Equity-based compensation | 8,353 | 990 | 0 |
Performance unit awards | |||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||
Total share-settled equity-based compensation, gross | 7,480 | 749 | 0 |
Phantom unit awards | |||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||
Total share-settled equity-based compensation, gross | $ 1,238 | $ 404 | $ 0 |
Compensation plans - Cost recog
Compensation plans - Cost recognized for the Company's 401(k) plan (Details) - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2021 | Dec. 31, 2020 | Dec. 31, 2019 | |
401(k) Plan | |||
Defined Contribution Plan Disclosure [Line Items] | |||
Contributions | $ 1,652 | $ 1,649 | $ 1,742 |
Derivatives - Narrative (Detail
Derivatives - Narrative (Details) $ in Thousands | 12 Months Ended | |||||
Dec. 31, 2021USD ($)derivative$ / bblbbl | Dec. 31, 2020USD ($) | Dec. 31, 2019USD ($) | Jun. 30, 2027USD ($) | Dec. 31, 2022USD ($) | Jul. 01, 2021USD ($) | |
Derivative [Line Items] | ||||||
Number of types of derivative instruments | derivative | 3 | |||||
Premiums paid (received) for derivative financial instruments | $ (9,041) | $ 51,070 | $ 9,063 | |||
Settlements received (paid) for early-terminated commodity derivatives, net | 0 | 6,340 | $ (5,409) | |||
Disposal group, disposed of by sale, not discontinued operations | Sixth Street PSA | ||||||
Derivative [Line Items] | ||||||
Aggregate quarterly payments of additional cash contingent consideration | $ 38,700 | |||||
Balloon payment of additional cash contingent consideration | 55,000 | |||||
Fair value of contingent consideration | 35,900 | 33,800 | ||||
Maximum | Disposal group, disposed of by sale, not discontinued operations | Sixth Street PSA | ||||||
Derivative [Line Items] | ||||||
Additional cash contingent consideration | 93,700 | |||||
Aggregate quarterly payments of additional cash contingent consideration | 38,700 | |||||
Maximum | Disposal group, disposed of by sale, not discontinued operations | Glasscock and Reagan County - Working Interest Sale in Oil and Gas Properties | ||||||
Derivative [Line Items] | ||||||
Additional cash contingent consideration | $ 93,700 | |||||
Derivatives not designated as hedges | Commodity derivatives | ||||||
Derivative [Line Items] | ||||||
Settlements received (paid) for early-terminated commodity derivatives, net | 6,300 | (5,400) | ||||
Derivatives not designated as hedges | Commodity derivatives | Level 3 | ||||||
Derivative [Line Items] | ||||||
Present value of deferred premiums upon early termination | $ 7,200 | |||||
Forecast | Disposal group, disposed of by sale, not discontinued operations | Sixth Street PSA | ||||||
Derivative [Line Items] | ||||||
Balloon payment of additional cash contingent consideration | $ 55,000 | |||||
Crude Oil | Brent ICE | Put | Derivatives Sold | ||||||
Derivative [Line Items] | ||||||
Aggregate volumes (Bbl) | bbl | 2,254,500 | |||||
Weighted-average price ($/Bbl) | $ / bbl | 55 | |||||
Premiums paid (received) for derivative financial instruments | $ (9,000) | |||||
Crude Oil | Brent ICE | Swap | Derivatives Sold | ||||||
Derivative [Line Items] | ||||||
Aggregate volumes (Bbl) | bbl | 2,254,500 | |||||
Weighted-average price ($/Bbl) | $ / bbl | 55.09 | |||||
Premiums paid (received) for derivative financial instruments | $ 50,600 | |||||
Crude Oil | WTI NYMEX | Derivatives not designated as hedges | Oil put: January 2021 - December 2022 | Howard County Net Acres | ||||||
Derivative [Line Items] | ||||||
Notional amount of derivative | $ 1,200 | |||||
Crude Oil | WTI NYMEX | Derivatives not designated as hedges | Oil put: January 2020 - December 2020 | Howard County Net Acres | ||||||
Derivative [Line Items] | ||||||
Notional amount of derivative | $ 20,000 | |||||
Crude Oil | Forecast | WTI NYMEX | Derivatives not designated as hedges | Oil put: January 2021 - December 2022 | Howard County Net Acres | ||||||
Derivative [Line Items] | ||||||
Notional amount of derivative | $ 1,200 |
Derivatives - Gain (Loss) on De
Derivatives - Gain (Loss) on Derivatives (Details) - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2021 | Dec. 31, 2020 | Dec. 31, 2019 | |
Derivative [Line Items] | |||
Gain (loss) on derivatives, net | $ (452,175) | $ 80,114 | $ 79,151 |
Commodity | |||
Derivative [Line Items] | |||
Gain (loss) on derivatives, net | (453,784) | 73,662 | 80,351 |
Interest rate | |||
Derivative [Line Items] | |||
Gain (loss) on derivatives, net | (30) | (343) | 0 |
Contingent consideration | |||
Derivative [Line Items] | |||
Gain (loss) on derivatives, net | $ 1,639 | $ 6,795 | $ (1,200) |
Derivatives - Derivatives termi
Derivatives - Derivatives terminated (Details) - Early Contract Termination - WTI NYMEX - Crude Oil | 12 Months Ended |
Dec. 31, 2021$ / bblbbl | |
Swap | |
Derivative [Line Items] | |
Aggregate volumes (Bbl) | bbl | 389,180 |
Weighted-average floor price ($/Bbl) | 60.25 |
Weighted-average ceiling price ($/Bbl) | 60.25 |
Collar Option January 2021 to December 2021 | |
Derivative [Line Items] | |
Aggregate volumes (Bbl) | bbl | 912,500 |
Weighted-average floor price ($/Bbl) | 45 |
Weighted-average ceiling price ($/Bbl) | 71 |
Oil puts: April 2019 - December 2019 | |
Derivative [Line Items] | |
Aggregate volumes (Bbl) | bbl | 5,087,500 |
Weighted-average floor price ($/Bbl) | 46.03 |
Weighted-average ceiling price ($/Bbl) | 0 |
Oil put: January 2020 - December 2020 | |
Derivative [Line Items] | |
Aggregate volumes (Bbl) | bbl | 366,000 |
Weighted-average floor price ($/Bbl) | 45 |
Weighted-average ceiling price ($/Bbl) | 0 |
Oil collars: January 2020 - December 2020 | |
Derivative [Line Items] | |
Aggregate volumes (Bbl) | bbl | 1,134,600 |
Weighted-average floor price ($/Bbl) | 45 |
Weighted-average ceiling price ($/Bbl) | 76.13 |
Derivatives - Summary (Details)
Derivatives - Summary (Details) $ in Thousands | 12 Months Ended | ||||
Dec. 31, 2023MMBTU$ / bbl$ / MMBTUbbl | Dec. 31, 2022MMBTU$ / bbl$ / MMBTUbbl | Dec. 31, 2021USD ($) | Dec. 31, 2020USD ($) | Dec. 31, 2019USD ($) | |
Derivative [Line Items] | |||||
Premiums paid (received) for derivative financial instruments | $ | $ (9,041) | $ 51,070 | $ 9,063 | ||
Forecast | Outstanding at End of Period | Derivatives not designated as hedges | Swap | Purity Ethane | Commodity - NGL | |||||
Derivative [Line Items] | |||||
Aggregate volumes (Bbl) | bbl | 0 | 1,533,000 | |||
Weighted-average price ($/Bbl) | 0 | 11.42 | |||
Forecast | Outstanding at End of Period | Derivatives not designated as hedges | Swap | Propane | Commodity - NGL | |||||
Derivative [Line Items] | |||||
Aggregate volumes (Bbl) | bbl | 0 | 1,168,000 | |||
Weighted-average price ($/Bbl) | 0 | 35.91 | |||
Forecast | Outstanding at End of Period | Derivatives not designated as hedges | Swap | Butane | Commodity - NGL | |||||
Derivative [Line Items] | |||||
Aggregate volumes (Bbl) | bbl | 0 | 365,000 | |||
Weighted-average price ($/Bbl) | 0 | 41.58 | |||
Forecast | Outstanding at End of Period | Derivatives not designated as hedges | Swap | Isobutane | Commodity - NGL | |||||
Derivative [Line Items] | |||||
Aggregate volumes (Bbl) | bbl | 0 | 109,500 | |||
Weighted-average price ($/Bbl) | 0 | 42 | |||
Forecast | Outstanding at End of Period | Derivatives not designated as hedges | Swap | Natural Gasoline | Commodity - NGL | |||||
Derivative [Line Items] | |||||
Aggregate volumes (Bbl) | bbl | 0 | 365,000 | |||
Weighted-average price ($/Bbl) | 0 | 60.65 | |||
Forecast | Outstanding at End of Period | Derivatives not designated as hedges | Commodity | Commodity - NGL | |||||
Derivative [Line Items] | |||||
Aggregate volumes (Bbl) | bbl | 0 | 3,540,500 | |||
Forecast | Outstanding at End of Period | Derivatives not designated as hedges | WTI NYMEX | Crude Oil | |||||
Derivative [Line Items] | |||||
Aggregate volumes (Bbl) | bbl | 730,000 | 4,479,500 | |||
Forecast | Outstanding at End of Period | Derivatives not designated as hedges | WTI NYMEX | Floor | Crude Oil | |||||
Derivative [Line Items] | |||||
Weighted-average price ($/Bbl) | 60 | 60.54 | |||
Forecast | Outstanding at End of Period | Derivatives not designated as hedges | WTI NYMEX | Ceiling | Crude Oil | |||||
Derivative [Line Items] | |||||
Weighted-average price ($/Bbl) | 75.66 | 69 | |||
Forecast | Outstanding at End of Period | Derivatives not designated as hedges | WTI NYMEX | Swap | Crude Oil | |||||
Derivative [Line Items] | |||||
Aggregate volumes (Bbl) | bbl | 0 | 1,085,000 | |||
Weighted-average price ($/Bbl) | 0 | 67.77 | |||
Forecast | Outstanding at End of Period | Derivatives not designated as hedges | WTI NYMEX | Collar | Crude Oil | |||||
Derivative [Line Items] | |||||
Aggregate volumes (Bbl) | bbl | 730,000 | 3,394,500 | |||
Forecast | Outstanding at End of Period | Derivatives not designated as hedges | WTI NYMEX | Collar | Floor | Crude Oil | |||||
Derivative [Line Items] | |||||
Weighted-average price ($/Bbl) | 60 | 58.23 | |||
Forecast | Outstanding at End of Period | Derivatives not designated as hedges | WTI NYMEX | Collar | Ceiling | Crude Oil | |||||
Derivative [Line Items] | |||||
Weighted-average price ($/Bbl) | 75.66 | 69.39 | |||
Forecast | Outstanding at End of Period | Derivatives not designated as hedges | Brent ICE | Swap | Crude Oil | |||||
Derivative [Line Items] | |||||
Aggregate volumes (Bbl) | bbl | 0 | 4,124,500 | |||
Weighted-average price ($/Bbl) | 0 | 48.34 | |||
Forecast | Outstanding at End of Period | Derivatives not designated as hedges | Brent ICE | Collar | Crude Oil | |||||
Derivative [Line Items] | |||||
Aggregate volumes (Bbl) | bbl | 0 | 1,551,250 | |||
Forecast | Outstanding at End of Period | Derivatives not designated as hedges | Brent ICE | Collar | Floor | Crude Oil | |||||
Derivative [Line Items] | |||||
Weighted-average price ($/Bbl) | 0 | 56.65 | |||
Forecast | Outstanding at End of Period | Derivatives not designated as hedges | Brent ICE | Collar | Ceiling | Crude Oil | |||||
Derivative [Line Items] | |||||
Weighted-average price ($/Bbl) | 0 | 65.44 | |||
Forecast | Outstanding at End of Period | Derivatives not designated as hedges | Brent ICE | Commodity | Floor | Crude Oil | |||||
Derivative [Line Items] | |||||
Aggregate volumes (Bbl) | bbl | 0 | 5,675,750 | |||
Weighted-average price ($/Bbl) | 0 | 50.61 | |||
Forecast | Outstanding at End of Period | Derivatives not designated as hedges | Brent ICE | Commodity | Ceiling | Crude Oil | |||||
Derivative [Line Items] | |||||
Weighted-average price ($/Bbl) | 0 | 53.01 | |||
Forecast | Outstanding at End of Period | Derivatives not designated as hedges | Henry Hub NYMEX | Swap | Natural gas (MMcf) | |||||
Derivative [Line Items] | |||||
Weighted-average price ($/Bbl) | $ / MMBTU | 0 | 2.73 | |||
Volume (MMBtu) | MMBTU | 0 | 3,650,000 | |||
Forecast | Outstanding at End of Period | Derivatives not designated as hedges | Henry Hub NYMEX | Collar | Natural gas (MMcf) | |||||
Derivative [Line Items] | |||||
Volume (MMBtu) | MMBTU | 3,650,000 | 29,200,000 | |||
Forecast | Outstanding at End of Period | Derivatives not designated as hedges | Henry Hub NYMEX | Collar | Floor | Natural gas (MMcf) | |||||
Derivative [Line Items] | |||||
Weighted-average price ($/Bbl) | $ / MMBTU | 3 | 3.09 | |||
Forecast | Outstanding at End of Period | Derivatives not designated as hedges | Henry Hub NYMEX | Collar | Ceiling | Natural gas (MMcf) | |||||
Derivative [Line Items] | |||||
Weighted-average price ($/Bbl) | $ / MMBTU | 4.45 | 3.84 | |||
Forecast | Outstanding at End of Period | Derivatives not designated as hedges | Henry Hub NYMEX | Commodity | Floor | Natural gas (MMcf) | |||||
Derivative [Line Items] | |||||
Weighted-average price ($/Bbl) | $ / MMBTU | 3 | 3.05 | |||
Volume (MMBtu) | MMBTU | 3,650,000 | 32,850,000 | |||
Forecast | Outstanding at End of Period | Derivatives not designated as hedges | Henry Hub NYMEX | Commodity | Ceiling | Natural gas (MMcf) | |||||
Derivative [Line Items] | |||||
Weighted-average price ($/Bbl) | $ / MMBTU | 4.45 | 3.71 | |||
Forecast | Outstanding at End of Period | Derivatives not designated as hedges | Waha Inside FERC to Henry Hub NYMEX | Basis Swap | Natural gas (MMcf) | |||||
Derivative [Line Items] | |||||
Weighted-average price ($/Bbl) | $ / MMBTU | 0 | (0.36) | |||
Volume (MMBtu) | MMBTU | 0 | 29,017,500 |
Derivatives - Derivatives enter
Derivatives - Derivatives entered into (Details) - Interest rate swap - Derivatives not designated as hedges $ in Thousands | Dec. 31, 2021USD ($) |
Derivative [Line Items] | |
Notional amount of derivative | $ 100,000 |
Fixed rate (as a percent) | 0.345% |
Fair value measurements - Fair
Fair value measurements - Fair value hierarchy (Details) - USD ($) $ in Thousands | Dec. 31, 2021 | Dec. 31, 2020 |
Assets: | ||
Net fair value presented on the consolidated balance sheets | $ 4,346 | $ 7,893 |
Net fair value presented on the consolidated balance sheets | 32,963 | 0 |
Liabilities: | ||
Net fair value presented on the consolidated balance sheets | (179,809) | (31,826) |
Net fair value presented on the consolidated balance sheets | 0 | (12,051) |
Net derivative liability positions | (142,500) | (35,984) |
Contingent Consideration | ||
Assets: | ||
Net fair value presented on the consolidated balance sheets | 0 | |
Liabilities: | ||
Net fair value presented on the consolidated balance sheets | (665) | |
Net fair value presented on the consolidated balance sheets | (115) | |
Interest rate - LIBOR | ||
Liabilities: | ||
Net fair value presented on the consolidated balance sheets | (52) | (206) |
Net fair value presented on the consolidated balance sheets | 0 | (63) |
Level 1 | ||
Liabilities: | ||
Net derivative liability positions | 0 | 0 |
Level 2 | ||
Liabilities: | ||
Net derivative liability positions | (178,361) | (35,984) |
Level 3 | ||
Liabilities: | ||
Net derivative liability positions | 35,861 | 0 |
Commodity - Oil | Commodity derivatives | ||
Assets: | ||
Net fair value presented on the consolidated balance sheets | 0 | 8,028 |
Net fair value presented on the consolidated balance sheets | 1,196 | 0 |
Liabilities: | ||
Net fair value presented on the consolidated balance sheets | (153,096) | (188) |
Net fair value presented on the consolidated balance sheets | 0 | (10,932) |
Commodity - Oil | Contingent Consideration | ||
Assets: | ||
Net fair value presented on the consolidated balance sheets | 4,346 | 0 |
Net fair value presented on the consolidated balance sheets | 31,515 | |
Liabilities: | ||
Net fair value presented on the consolidated balance sheets | 0 | |
Net fair value presented on the consolidated balance sheets | 0 | |
Commodity - NGL | Commodity derivatives | ||
Assets: | ||
Net fair value presented on the consolidated balance sheets | 0 | 0 |
Net fair value presented on the consolidated balance sheets | 0 | 0 |
Liabilities: | ||
Net fair value presented on the consolidated balance sheets | (17,581) | (13,465) |
Net fair value presented on the consolidated balance sheets | 0 | 0 |
Commodity - Natural gas | Commodity derivatives | ||
Assets: | ||
Net fair value presented on the consolidated balance sheets | 0 | (135) |
Net fair value presented on the consolidated balance sheets | 252 | 0 |
Liabilities: | ||
Net fair value presented on the consolidated balance sheets | (9,080) | (17,302) |
Net fair value presented on the consolidated balance sheets | 0 | (941) |
Current Assets | Contingent Consideration | ||
Assets: | ||
Total gross fair value | 0 | |
Amounts offset | 0 | |
Current Assets | Level 1 | Contingent Consideration | ||
Assets: | ||
Total gross fair value | 0 | |
Current Assets | Level 2 | Contingent Consideration | ||
Assets: | ||
Total gross fair value | 0 | |
Current Assets | Level 3 | Contingent Consideration | ||
Assets: | ||
Total gross fair value | 0 | |
Current Assets | Commodity - Oil | Commodity derivatives | ||
Assets: | ||
Total gross fair value | 14,653 | 32,958 |
Amounts offset | (14,653) | (24,930) |
Current Assets | Commodity - Oil | Contingent Consideration | ||
Assets: | ||
Total gross fair value | 4,346 | |
Amounts offset | 0 | |
Current Assets | Commodity - Oil | Level 1 | Commodity derivatives | ||
Assets: | ||
Total gross fair value | 0 | 0 |
Current Assets | Commodity - Oil | Level 1 | Contingent Consideration | ||
Assets: | ||
Total gross fair value | 0 | |
Current Assets | Commodity - Oil | Level 2 | Commodity derivatives | ||
Assets: | ||
Total gross fair value | 14,653 | 32,958 |
Current Assets | Commodity - Oil | Level 2 | Contingent Consideration | ||
Assets: | ||
Total gross fair value | 0 | |
Current Assets | Commodity - Oil | Level 3 | Commodity derivatives | ||
Assets: | ||
Total gross fair value | 0 | 0 |
Current Assets | Commodity - Oil | Level 3 | Contingent Consideration | ||
Assets: | ||
Total gross fair value | 4,346 | |
Current Assets | Commodity - NGL | Commodity derivatives | ||
Assets: | ||
Total gross fair value | 0 | 2,720 |
Amounts offset | 0 | (2,720) |
Current Assets | Commodity - NGL | Level 1 | Commodity derivatives | ||
Assets: | ||
Total gross fair value | 0 | 0 |
Current Assets | Commodity - NGL | Level 2 | Commodity derivatives | ||
Assets: | ||
Total gross fair value | 0 | 2,720 |
Current Assets | Commodity - NGL | Level 3 | Commodity derivatives | ||
Assets: | ||
Total gross fair value | 0 | 0 |
Current Assets | Commodity - Natural gas | Commodity derivatives | ||
Assets: | ||
Total gross fair value | 7,018 | 521 |
Amounts offset | (7,018) | (656) |
Current Assets | Commodity - Natural gas | Level 1 | Commodity derivatives | ||
Assets: | ||
Total gross fair value | 0 | 0 |
Current Assets | Commodity - Natural gas | Level 2 | Commodity derivatives | ||
Assets: | ||
Total gross fair value | 7,018 | 521 |
Current Assets | Commodity - Natural gas | Level 3 | Commodity derivatives | ||
Assets: | ||
Total gross fair value | 0 | 0 |
Noncurrent Assets | Contingent Consideration | ||
Assets: | ||
Total gross fair value | 0 | |
Amounts offset | 0 | |
Noncurrent Assets | Level 1 | Contingent Consideration | ||
Assets: | ||
Total gross fair value | 0 | |
Noncurrent Assets | Level 2 | Contingent Consideration | ||
Assets: | ||
Total gross fair value | 0 | |
Noncurrent Assets | Level 3 | Contingent Consideration | ||
Assets: | ||
Total gross fair value | 0 | |
Noncurrent Assets | Commodity - Oil | Commodity derivatives | ||
Assets: | ||
Total gross fair value | 1,196 | 0 |
Amounts offset | 0 | 0 |
Noncurrent Assets | Commodity - Oil | Contingent Consideration | ||
Assets: | ||
Total gross fair value | 31,515 | |
Amounts offset | 0 | |
Noncurrent Assets | Commodity - Oil | Level 1 | Commodity derivatives | ||
Assets: | ||
Total gross fair value | 0 | 0 |
Noncurrent Assets | Commodity - Oil | Level 1 | Contingent Consideration | ||
Assets: | ||
Total gross fair value | 0 | |
Noncurrent Assets | Commodity - Oil | Level 2 | Commodity derivatives | ||
Assets: | ||
Total gross fair value | 1,196 | 0 |
Noncurrent Assets | Commodity - Oil | Level 2 | Contingent Consideration | ||
Assets: | ||
Total gross fair value | 0 | |
Noncurrent Assets | Commodity - Oil | Level 3 | Commodity derivatives | ||
Assets: | ||
Total gross fair value | 0 | 0 |
Noncurrent Assets | Commodity - Oil | Level 3 | Contingent Consideration | ||
Assets: | ||
Total gross fair value | 31,515 | |
Noncurrent Assets | Commodity - NGL | Commodity derivatives | ||
Assets: | ||
Total gross fair value | 0 | 0 |
Amounts offset | 0 | 0 |
Noncurrent Assets | Commodity - NGL | Level 1 | Commodity derivatives | ||
Assets: | ||
Total gross fair value | 0 | 0 |
Noncurrent Assets | Commodity - NGL | Level 2 | Commodity derivatives | ||
Assets: | ||
Total gross fair value | 0 | 0 |
Noncurrent Assets | Commodity - NGL | Level 3 | Commodity derivatives | ||
Assets: | ||
Total gross fair value | 0 | 0 |
Noncurrent Assets | Commodity - Natural gas | Commodity derivatives | ||
Assets: | ||
Total gross fair value | 252 | 535 |
Amounts offset | 0 | (535) |
Noncurrent Assets | Commodity - Natural gas | Level 1 | Commodity derivatives | ||
Assets: | ||
Total gross fair value | 0 | 0 |
Noncurrent Assets | Commodity - Natural gas | Level 2 | Commodity derivatives | ||
Assets: | ||
Total gross fair value | 252 | 535 |
Noncurrent Assets | Commodity - Natural gas | Level 3 | Commodity derivatives | ||
Assets: | ||
Total gross fair value | 0 | 0 |
Current Liabilities | Contingent Consideration | ||
Liabilities: | ||
Total gross fair value | (665) | |
Amounts offset | 0 | |
Current Liabilities | Interest rate - LIBOR | ||
Liabilities: | ||
Total gross fair value | (52) | (206) |
Amounts offset | 0 | 0 |
Current Liabilities | Level 1 | Contingent Consideration | ||
Liabilities: | ||
Total gross fair value | 0 | |
Current Liabilities | Level 1 | Interest rate - LIBOR | ||
Liabilities: | ||
Total gross fair value | 0 | 0 |
Current Liabilities | Level 2 | Contingent Consideration | ||
Liabilities: | ||
Total gross fair value | (665) | |
Current Liabilities | Level 2 | Interest rate - LIBOR | ||
Liabilities: | ||
Total gross fair value | (52) | (206) |
Current Liabilities | Level 3 | Contingent Consideration | ||
Liabilities: | ||
Total gross fair value | 0 | |
Current Liabilities | Level 3 | Interest rate - LIBOR | ||
Liabilities: | ||
Total gross fair value | 0 | 0 |
Current Liabilities | Commodity - Oil | Commodity derivatives | ||
Liabilities: | ||
Total gross fair value | (167,749) | (25,118) |
Amounts offset | 14,653 | 24,930 |
Current Liabilities | Commodity - Oil | Contingent Consideration | ||
Liabilities: | ||
Total gross fair value | 0 | |
Amounts offset | 0 | |
Current Liabilities | Commodity - Oil | Level 1 | Commodity derivatives | ||
Liabilities: | ||
Total gross fair value | 0 | 0 |
Current Liabilities | Commodity - Oil | Level 1 | Contingent Consideration | ||
Liabilities: | ||
Total gross fair value | 0 | |
Current Liabilities | Commodity - Oil | Level 2 | Commodity derivatives | ||
Liabilities: | ||
Total gross fair value | (167,749) | (25,118) |
Current Liabilities | Commodity - Oil | Level 2 | Contingent Consideration | ||
Liabilities: | ||
Total gross fair value | 0 | |
Current Liabilities | Commodity - Oil | Level 3 | Commodity derivatives | ||
Liabilities: | ||
Total gross fair value | 0 | 0 |
Current Liabilities | Commodity - Oil | Level 3 | Contingent Consideration | ||
Liabilities: | ||
Total gross fair value | 0 | |
Current Liabilities | Commodity - NGL | Commodity derivatives | ||
Liabilities: | ||
Total gross fair value | (17,581) | (16,185) |
Amounts offset | 0 | 2,720 |
Current Liabilities | Commodity - NGL | Level 1 | Commodity derivatives | ||
Liabilities: | ||
Total gross fair value | 0 | 0 |
Current Liabilities | Commodity - NGL | Level 2 | Commodity derivatives | ||
Liabilities: | ||
Total gross fair value | (17,581) | (16,185) |
Current Liabilities | Commodity - NGL | Level 3 | Commodity derivatives | ||
Liabilities: | ||
Total gross fair value | 0 | 0 |
Current Liabilities | Commodity - Natural gas | Commodity derivatives | ||
Liabilities: | ||
Total gross fair value | (16,098) | (17,958) |
Amounts offset | 7,018 | 656 |
Current Liabilities | Commodity - Natural gas | Level 1 | Commodity derivatives | ||
Liabilities: | ||
Total gross fair value | 0 | 0 |
Current Liabilities | Commodity - Natural gas | Level 2 | Commodity derivatives | ||
Liabilities: | ||
Total gross fair value | (16,098) | (17,958) |
Current Liabilities | Commodity - Natural gas | Level 3 | Commodity derivatives | ||
Liabilities: | ||
Total gross fair value | 0 | 0 |
Noncurrent Liabilities | Contingent Consideration | ||
Liabilities: | ||
Total gross fair value | (115) | |
Amounts offset | 0 | |
Noncurrent Liabilities | Interest rate - LIBOR | ||
Liabilities: | ||
Total gross fair value | 0 | (63) |
Amounts offset | 0 | 0 |
Noncurrent Liabilities | Level 1 | Contingent Consideration | ||
Liabilities: | ||
Total gross fair value | 0 | |
Noncurrent Liabilities | Level 1 | Interest rate - LIBOR | ||
Liabilities: | ||
Total gross fair value | 0 | 0 |
Noncurrent Liabilities | Level 2 | Contingent Consideration | ||
Liabilities: | ||
Total gross fair value | (115) | |
Noncurrent Liabilities | Level 2 | Interest rate - LIBOR | ||
Liabilities: | ||
Total gross fair value | 0 | (63) |
Noncurrent Liabilities | Level 3 | Contingent Consideration | ||
Liabilities: | ||
Total gross fair value | 0 | |
Noncurrent Liabilities | Level 3 | Interest rate - LIBOR | ||
Liabilities: | ||
Total gross fair value | 0 | 0 |
Noncurrent Liabilities | Commodity - Oil | Commodity derivatives | ||
Liabilities: | ||
Total gross fair value | 0 | (10,932) |
Amounts offset | 0 | 0 |
Noncurrent Liabilities | Commodity - Oil | Contingent Consideration | ||
Liabilities: | ||
Total gross fair value | 0 | |
Amounts offset | 0 | |
Noncurrent Liabilities | Commodity - Oil | Level 1 | Commodity derivatives | ||
Liabilities: | ||
Total gross fair value | 0 | 0 |
Noncurrent Liabilities | Commodity - Oil | Level 1 | Contingent Consideration | ||
Liabilities: | ||
Total gross fair value | 0 | |
Noncurrent Liabilities | Commodity - Oil | Level 2 | Commodity derivatives | ||
Liabilities: | ||
Total gross fair value | 0 | (10,932) |
Noncurrent Liabilities | Commodity - Oil | Level 2 | Contingent Consideration | ||
Liabilities: | ||
Total gross fair value | 0 | |
Noncurrent Liabilities | Commodity - Oil | Level 3 | Commodity derivatives | ||
Liabilities: | ||
Total gross fair value | 0 | 0 |
Noncurrent Liabilities | Commodity - Oil | Level 3 | Contingent Consideration | ||
Liabilities: | ||
Total gross fair value | 0 | |
Noncurrent Liabilities | Commodity - NGL | Commodity derivatives | ||
Liabilities: | ||
Total gross fair value | 0 | 0 |
Amounts offset | 0 | 0 |
Noncurrent Liabilities | Commodity - NGL | Level 1 | Commodity derivatives | ||
Liabilities: | ||
Total gross fair value | 0 | 0 |
Noncurrent Liabilities | Commodity - NGL | Level 2 | Commodity derivatives | ||
Liabilities: | ||
Total gross fair value | 0 | 0 |
Noncurrent Liabilities | Commodity - NGL | Level 3 | Commodity derivatives | ||
Liabilities: | ||
Total gross fair value | 0 | 0 |
Noncurrent Liabilities | Commodity - Natural gas | Commodity derivatives | ||
Liabilities: | ||
Total gross fair value | 0 | (1,476) |
Amounts offset | 0 | 535 |
Noncurrent Liabilities | Commodity - Natural gas | Level 1 | Commodity derivatives | ||
Liabilities: | ||
Total gross fair value | 0 | 0 |
Noncurrent Liabilities | Commodity - Natural gas | Level 2 | Commodity derivatives | ||
Liabilities: | ||
Total gross fair value | 0 | (1,476) |
Noncurrent Liabilities | Commodity - Natural gas | Level 3 | Commodity derivatives | ||
Liabilities: | ||
Total gross fair value | $ 0 | $ 0 |
Fair value measurements - Chang
Fair value measurements - Changes in net assets classified as Level 3 (Details) - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2021 | Dec. 31, 2020 | Dec. 31, 2019 | |
Deferred Premiums | |||
Changes in assets classified as Level 3 measurements | |||
Balance of Level 3 at beginning of year | $ 0 | $ (477) | $ (16,565) |
Change in net present value of commodity derivative deferred premiums | 0 | 0 | (139) |
Settlements of commodity derivative deferred premiums | 0 | 477 | 16,227 |
Balance of Level 3 at end of year | $ 0 | $ 0 | (477) |
Deferred Premiums - Early Termination | |||
Changes in assets classified as Level 3 measurements | |||
Settlements of commodity derivative deferred premiums | $ 7,200 |
Fair value measurements - Cha_2
Fair value measurements - Changes in contingent consideration (Details) - Contingent Consideration Derivative - Level 3 - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2021 | Dec. 31, 2020 | Dec. 31, 2019 | |
Fair Value, Liabilities Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward] | |||
Balance of Level 3 at beginning of year | $ 0 | $ 0 | $ 0 |
Sixth Street Contingent Consideration valuation as of Sixth Street Closing Date | 33,832 | 0 | 0 |
Change in net present value of Sixth Street Contingent Consideration | 2,029 | 0 | 0 |
Balance of Level 3 at end of year | $ 35,861 | $ 0 | $ 0 |
Fair value measurements - Narra
Fair value measurements - Narrative (Details) - USD ($) | 12 Months Ended | ||||
Dec. 31, 2021 | Dec. 31, 2020 | Dec. 31, 2019 | Apr. 30, 2020 | Dec. 12, 2019 | |
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||||
Fair value of contingent consideration | $ 800,000 | $ 200,000 | |||
Impairment expense | $ 1,613,000 | 899,039,000 | $ 620,889,000 | ||
Acquisitions of oil and natural gas properties | 763,411,000 | 35,786,000 | 199,284,000 | ||
WTI NYMEX | Crude Oil | Howard County Net Acres | Oil put: January 2021 - December 2022 | Derivatives not designated as hedges | |||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||||
Notional amount of derivative | 1,200,000 | ||||
Nonrecurring | Level 3 | |||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||||
Acquisitions of oil and natural gas properties | 0 | 0 | |||
Line-Fill and Other Inventories | Nonrecurring | Level 2 | |||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||||
Impairment expense | 1,600,000 | 1,400,000 | 300,000 | ||
Long-Lived Assets | Nonrecurring | Level 3 | |||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||||
Impairment expense | $ 0 | $ 8,200,000 | $ 0 | ||
Howard County Net Acres | |||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||||
Fair value of contingent consideration | $ 6,200,000 |
Fair value measurements - Carry
Fair value measurements - Carrying amounts and fair values of debt (Details) - USD ($) $ in Thousands | Dec. 31, 2021 | Dec. 31, 2020 |
Carrying Value | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Fair value disclosure of debt | $ 1,443,957 | $ 1,193,957 |
Carrying Value | Senior Notes | January 2025 Notes | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Fair value disclosure of debt | 577,913 | 577,913 |
Carrying Value | Senior Notes | January 2028 Notes | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Fair value disclosure of debt | 361,044 | 361,044 |
Carrying Value | Senior Notes | July 2029 Notes | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Fair value disclosure of debt | 400,000 | 0 |
Carrying Value | Secured Debt | Line of Credit | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Fair value disclosure of debt | 105,000 | 255,000 |
Fair Value | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Fair value disclosure of debt | 1,463,089 | 1,054,153 |
Fair Value | Senior Notes | January 2025 Notes | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Fair value disclosure of debt | 589,471 | 499,299 |
Fair Value | Senior Notes | January 2028 Notes | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Fair value disclosure of debt | 378,578 | 299,667 |
Fair Value | Senior Notes | July 2029 Notes | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Fair value disclosure of debt | 390,000 | 0 |
Fair Value | Secured Debt | Line of Credit | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Fair value disclosure of debt | $ 105,040 | $ 255,187 |
Net income (loss) per common _3
Net income (loss) per common share - Summary (Details) - USD ($) $ / shares in Units, shares in Thousands, $ in Thousands | 3 Months Ended | 12 Months Ended | |||||||||
Dec. 31, 2021 | Sep. 30, 2021 | Jun. 30, 2021 | Mar. 31, 2021 | Dec. 31, 2020 | Sep. 30, 2020 | Jun. 30, 2020 | Mar. 31, 2020 | Dec. 31, 2021 | Dec. 31, 2020 | Dec. 31, 2019 | |
Net income (numerator): | |||||||||||
Net income (loss) | $ 216,276 | $ 136,832 | $ (132,661) | $ (75,439) | $ (165,932) | $ (237,432) | $ (545,455) | $ 74,646 | $ 145,008 | $ (874,173) | $ (342,459) |
Weighted-average common shares outstanding (denominator): | |||||||||||
Basic (shares) | 14,240 | 11,668 | 11,565 | ||||||||
Diluted (shares) | 14,464 | 11,668 | 11,565 | ||||||||
Net income (loss) per common share: | |||||||||||
Basic (USD per share) | $ 13.07 | $ 8.68 | $ (10.47) | $ (6.33) | $ (14.18) | $ (20.32) | $ (46.75) | $ 6.43 | $ 10.18 | $ (74.92) | $ (29.61) |
Diluted (USD per share) | $ 12.84 | $ 8.56 | $ (10.47) | $ (6.33) | $ (14.18) | $ (20.32) | $ (46.75) | $ 6.39 | $ 10.03 | $ (74.92) | $ (29.61) |
Non-vested restricted stock awards | |||||||||||
Weighted-average common shares outstanding (denominator): | |||||||||||
Non-vested and outstanding awards (shares) | 181 | 0 | 0 | ||||||||
Performance share awards | |||||||||||
Weighted-average common shares outstanding (denominator): | |||||||||||
Non-vested and outstanding awards (shares) | 43 | 0 | 0 |
Income taxes - Income tax (expe
Income taxes - Income tax (expense) benefit (Details) - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2021 | Dec. 31, 2020 | Dec. 31, 2019 | |
Current income tax (expense) benefit: | |||
Federal | $ 0 | $ 0 | $ 0 |
State | (1,324) | 0 | 0 |
Deferred income tax (expense) benefit: | |||
Federal | 0 | 0 | 0 |
State | (2,321) | 3,946 | 2,588 |
Total income tax (expense) benefit | $ (3,645) | $ 3,946 | $ 2,588 |
Income taxes - Deferred income
Income taxes - Deferred income tax reconciliation (Details) - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2021 | Dec. 31, 2020 | Dec. 31, 2019 | |
Income Tax Disclosure [Abstract] | |||
Income tax (expense) benefit computed by applying the statutory rate | $ (31,217) | $ 184,405 | $ 72,460 |
Change in deferred tax valuation allowance | 45,717 | (182,634) | (69,316) |
Non-deductible equity-based compensation | (13,640) | 0 | 0 |
State income tax and change in valuation allowance | (3,274) | 2,903 | 1,863 |
Other items | (1,231) | (728) | (2,419) |
Total income tax (expense) benefit | $ (3,645) | $ 3,946 | $ 2,588 |
Income taxes - Net deferred tax
Income taxes - Net deferred tax asset (liability) (Details) - USD ($) $ in Thousands | Dec. 31, 2021 | Dec. 31, 2020 |
Significant components of deferred tax assets | ||
Net operating loss carryforward | $ 445,426 | $ 444,031 |
Oil and natural gas properties, midstream service assets and other fixed assets | (39,504) | |
Oil and natural gas properties, midstream service assets and other fixed assets | 22,231 | |
Equity-based compensation | 11,123 | 22,494 |
Derivatives | 36,639 | 7,166 |
Loss on sale of assets | (14,364) | (8,458) |
Other | 3,227 | 3,130 |
Net deferred tax asset before valuation allowance | 442,547 | 490,594 |
Valuation allowance | (443,390) | (489,116) |
Texas net deferred tax (liability) asset | $ (843) | |
Texas net deferred tax (liability) asset | $ 1,478 |
Income taxes - Operating losses
Income taxes - Operating losses (Details) - USD ($) $ in Thousands | Dec. 31, 2021 | Dec. 31, 2020 |
Operating Loss Carryforwards [Line Items] | ||
Total federal net operating loss carryforwards | $ 445,426 | $ 444,031 |
Federal | ||
Operating Loss Carryforwards [Line Items] | ||
Total expiring federal net operating loss carryforwards | 1,737,098 | |
Non-expiring federal net operating loss carryforwards | 376,212 | |
Total federal net operating loss carryforwards | 2,113,310 | |
2026 | Federal | ||
Operating Loss Carryforwards [Line Items] | ||
Total expiring federal net operating loss carryforwards | 2,741 | |
2027 | Federal | ||
Operating Loss Carryforwards [Line Items] | ||
Total expiring federal net operating loss carryforwards | 38,651 | |
2028 | Federal | ||
Operating Loss Carryforwards [Line Items] | ||
Total expiring federal net operating loss carryforwards | 228,661 | |
2029 | Federal | ||
Operating Loss Carryforwards [Line Items] | ||
Total expiring federal net operating loss carryforwards | 101,932 | |
2030 | Federal | ||
Operating Loss Carryforwards [Line Items] | ||
Total expiring federal net operating loss carryforwards | 80,963 | |
Thereafter | Federal | ||
Operating Loss Carryforwards [Line Items] | ||
Total expiring federal net operating loss carryforwards | $ 1,284,150 |
Income taxes - Narrative (Detai
Income taxes - Narrative (Details) - USD ($) $ in Thousands | 12 Months Ended | |||
Dec. 31, 2021 | Dec. 31, 2020 | Dec. 31, 2019 | Dec. 31, 2017 | |
Income Tax Examination [Line Items] | ||||
Amount of federal net operating loss carry-forward limited in future periods | $ 376,200 | |||
Current tax expense | (1,324) | $ 0 | $ 0 | |
Valuation allowance (decrease) | 443,390 | 489,116 | ||
Net deferred tax liability | (843) | |||
AMT credit carryforward | $ 4,100 | |||
AMT credit carryforward received during period | $ 2,100 | $ 2,000 | ||
Federal | ||||
Income Tax Examination [Line Items] | ||||
Net operating loss carry-forwards | 2,100,000 | |||
Oklahoma | State | ||||
Income Tax Examination [Line Items] | ||||
Net operating loss carry-forwards | 34,600 | |||
Texas | ||||
Income Tax Examination [Line Items] | ||||
Current tax expense | (1,300) | |||
Texas | State | ||||
Income Tax Examination [Line Items] | ||||
Net deferred tax liability | $ (800) |
Credit risk - Narrative (Detail
Credit risk - Narrative (Details) - USD ($) $ in Thousands | Dec. 31, 2021 | Dec. 31, 2020 |
Concentration Risk [Line Items] | ||
Net fair value presented on the consolidated balance sheets | $ 179,809 | $ 31,826 |
Estimate of Fair Value Measurement | ||
Concentration Risk [Line Items] | ||
Net fair value presented on the consolidated balance sheets | $ (178,400) |
Credit risk - Concentration Ris
Credit risk - Concentration Risk (Details) - Customer Concentration Risk | 12 Months Ended | ||
Dec. 31, 2021 | Dec. 31, 2020 | Dec. 31, 2019 | |
Purchaser A | Oil, NGL, and Natural Gas Sales | |||
Concentration Risk [Line Items] | |||
Concentration risk (as a percent) | 29.00% | 33.00% | 59.00% |
Purchaser A | Purchased Oil Sales | |||
Concentration Risk [Line Items] | |||
Concentration risk (as a percent) | 47.00% | 69.00% | 26.00% |
Purchaser B | Oil, NGL, and Natural Gas Sales | |||
Concentration Risk [Line Items] | |||
Concentration risk (as a percent) | 24.00% | 24.00% | 18.00% |
Purchaser B | Purchased Oil Sales | |||
Concentration Risk [Line Items] | |||
Concentration risk (as a percent) | 31.00% | 16.00% | 70.00% |
Purchaser C | Oil, NGL, and Natural Gas Sales | |||
Concentration Risk [Line Items] | |||
Concentration risk (as a percent) | 17.00% | 14.00% | |
Purchaser C | Purchased Oil Sales | |||
Concentration Risk [Line Items] | |||
Concentration risk (as a percent) | 22.00% | 14.00% | |
Purchaser D | Oil, NGL, and Natural Gas Sales | |||
Concentration Risk [Line Items] | |||
Concentration risk (as a percent) | 10.00% | ||
Purchaser E | Oil, NGL, and Natural Gas Sales | |||
Concentration Risk [Line Items] | |||
Concentration risk (as a percent) | 15.00% | ||
Purchaser F | Oil, NGL, and Natural Gas Sales | |||
Concentration Risk [Line Items] | |||
Concentration risk (as a percent) | 14.00% |
Commitments and contingencies (
Commitments and contingencies (Details) | 12 Months Ended | ||
Dec. 31, 2021USD ($)operating_lease | Dec. 31, 2020USD ($) | Dec. 31, 2019USD ($) | |
Unrecorded Unconditional Purchase Obligation [Line Items] | |||
Litigation settlement | $ 0 | $ 0 | $ 42,500,000 |
Minimum volume commitment deficiency payments | 4,400,000 | 4,000,000 | 900,000 |
Minimum volume commitments deficiency payments liability | 4,700,000 | 3,500,000 | |
Accrual for environmental loss contingencies | $ 0 | 0 | |
Sand purchase commitment | |||
Unrecorded Unconditional Purchase Obligation [Line Items] | |||
Purchase and supply commitment period | 1 year | ||
Minimum purchase commitment shortfall payment | $ 5,300,000 | ||
Drilling Contracts | |||
Unrecorded Unconditional Purchase Obligation [Line Items] | |||
Number of operating leases | operating_lease | 2 | ||
Penalties incurred for early contract termination | $ 0 | $ 0 | $ 0 |
Firm sale and transportation commitments | |||
Unrecorded Unconditional Purchase Obligation [Line Items] | |||
Future drilling contracts commitments | $ 213,300,000 |
Related parties (Details)
Related parties (Details) - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2021 | Dec. 31, 2020 | Dec. 31, 2019 | |
Related Party Transaction [Line Items] | |||
Capital expenditures for oil and natural gas properties | $ 418,362 | $ 347,359 | $ 458,985 |
Halliburton | Affiliated Entity | |||
Related Party Transaction [Line Items] | |||
Capital expenditures for oil and natural gas properties | $ 69,670 | $ 63,886 |
Organizational restructurings -
Organizational restructurings - Narrative (Details) $ in Thousands | Jun. 29, 2021senior_officer | Jun. 17, 2020employee | Sep. 27, 2019USD ($) | Apr. 08, 2019 | Dec. 31, 2021USD ($) | Dec. 31, 2020USD ($) | Dec. 31, 2019USD ($) | Apr. 02, 2019senior_officer |
Restructuring Cost and Reserve [Line Items] | ||||||||
Workforce reduction (positions eliminated) | 14 | 22 | ||||||
Workforce reduction (as a percent) | 5.00% | 20.00% | ||||||
Organizational restructuring expenses | $ 9,800 | $ 4,200 | $ 16,371 | |||||
Number of senior officers retired | senior_officer | 2 | |||||||
Chief Executive Officer | One-time Termination Benefits | ||||||||
Restructuring Cost and Reserve [Line Items] | ||||||||
Organizational restructuring expenses | $ 5,900 | |||||||
Period of COBRA employer contributions | 18 months |
Organizational restructurings_2
Organizational restructurings - Organizational restructuring expenses (Details) - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2021 | Dec. 31, 2020 | Dec. 31, 2019 | |
Restructuring and Related Activities [Abstract] | |||
Organizational restructuring expenses | $ 9,800 | $ 4,200 | $ 16,371 |
Organizational restructurings_3
Organizational restructurings - Gross equity-based compensation expense reversals (Details) - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2021 | Dec. 31, 2020 | Dec. 31, 2019 | |
Restructuring Cost and Reserve [Line Items] | |||
Gross equity-based compensation expense reversals | $ 16,028 | $ 9,207 | $ 8,290 |
Share-Based Compensation Awards Forfeited | |||
Restructuring Cost and Reserve [Line Items] | |||
Gross equity-based compensation expense reversals | $ (1,088) | $ (793) | $ (11,706) |
Subsequent events - Narrative (
Subsequent events - Narrative (Details) - USD ($) $ in Thousands | Jan. 31, 2022 | Jan. 14, 2022 | Dec. 31, 2021 | Dec. 31, 2020 | Dec. 31, 2019 | Feb. 21, 2022 |
Subsequent Event [Line Items] | ||||||
Payments on senior secured credit facility | $ 720,000 | $ 200,000 | $ 90,000 | |||
Secured Debt | Line of Credit | ||||||
Subsequent Event [Line Items] | ||||||
Line of credit | $ 105,000 | |||||
Secured Debt | Line of Credit | Subsequent event | ||||||
Subsequent Event [Line Items] | ||||||
Proceeds from lines of credit | $ 50,000 | |||||
Payments on senior secured credit facility | $ 10,000 | |||||
Line of credit | $ 145,000 |
Subsequent events - Derivatives
Subsequent events - Derivatives (Details) - Forecast - Subsequent to End of Period - Derivatives not designated as hedges - Crude Oil | 12 Months Ended | |
Dec. 31, 2023$ / bblbbl | Dec. 31, 2022$ / bblbbl | |
WTI NYMEX | Swap | ||
Subsequent Event [Line Items] | ||
Aggregate volumes (Bbl) | bbl | 0 | 1,878,000 |
Weighted-average price ($/Bbl) | 0 | 76.11 |
WTI NYMEX | Collar | ||
Subsequent Event [Line Items] | ||
Aggregate volumes (Bbl) | bbl | 3,632,000 | 3,394,500 |
WTI NYMEX | Collar | Minimum | ||
Subsequent Event [Line Items] | ||
Weighted-average price ($/Bbl) | 65.50 | 58.23 |
WTI NYMEX | Collar | Maximum | ||
Subsequent Event [Line Items] | ||
Weighted-average price ($/Bbl) | 79.94 | 69.39 |
WTI NYMEX | Commodity | ||
Subsequent Event [Line Items] | ||
Aggregate volumes (Bbl) | bbl | 3,632,000 | 5,272,500 |
WTI NYMEX | Commodity | Minimum | ||
Subsequent Event [Line Items] | ||
Weighted-average price ($/Bbl) | 65.50 | 64.60 |
WTI NYMEX | Commodity | Maximum | ||
Subsequent Event [Line Items] | ||
Weighted-average price ($/Bbl) | 79.94 | 71.78 |
Brent ICE | Swap | ||
Subsequent Event [Line Items] | ||
Aggregate volumes (Bbl) | bbl | 0 | 4,124,500 |
Weighted-average price ($/Bbl) | 0 | 48.34 |
Brent ICE | Collar | ||
Subsequent Event [Line Items] | ||
Aggregate volumes (Bbl) | bbl | 0 | 1,551,250 |
Brent ICE | Collar | Minimum | ||
Subsequent Event [Line Items] | ||
Weighted-average price ($/Bbl) | 0 | 56.65 |
Brent ICE | Collar | Maximum | ||
Subsequent Event [Line Items] | ||
Weighted-average price ($/Bbl) | 0 | 65.44 |
Brent ICE | Commodity | ||
Subsequent Event [Line Items] | ||
Aggregate volumes (Bbl) | bbl | 0 | 5,675,750 |
Brent ICE | Commodity | Minimum | ||
Subsequent Event [Line Items] | ||
Weighted-average price ($/Bbl) | 0 | 50.61 |
Brent ICE | Commodity | Maximum | ||
Subsequent Event [Line Items] | ||
Weighted-average price ($/Bbl) | 0 | 53.01 |
Supplemental oil, NGL and nat_3
Supplemental oil, NGL and natural gas disclosures (unaudited) - Incurred Capital Expenditures in oil and natural gas property acquisition, exploration and development activities (Details) - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2021 | Dec. 31, 2020 | Dec. 31, 2019 | |
Property acquisition costs: | |||
Evaluated | $ 899,128 | $ 11,368 | $ 126,372 |
Unevaluated | 198,770 | 25,549 | 83,738 |
Exploration costs | 33,482 | 17,337 | 19,954 |
Development costs | 410,855 | 326,823 | 450,501 |
Total oil and natural gas properties incurred capital expenditures | $ 1,542,235 | $ 381,077 | $ 680,565 |
Supplemental oil, NGL and nat_4
Supplemental oil, NGL and natural gas disclosures (unaudited) - Aggregate capitalized oil, NGL and natural gas costs (Details) - USD ($) $ in Thousands | 12 Months Ended | |||
Dec. 31, 2021 | Dec. 31, 2020 | Dec. 31, 2019 | Dec. 31, 2018 | |
Gross capitalized costs: | ||||
Evaluated properties | $ 8,968,668 | $ 7,874,932 | ||
Unevaluated properties not being depleted | 170,033 | 70,020 | ||
Total gross capitalized costs | 9,138,701 | 7,944,952 | ||
Less accumulated depletion and impairment | (7,019,670) | (6,817,949) | ||
Net capitalized costs | 2,119,031 | 1,127,003 | ||
Oil and natural gas property costs not being amortized | ||||
Unevaluated properties not being depleted | 166,158 | 784 | $ 1,902 | $ 1,189 |
Unevaluated properties not being depleted | $ 170,033 | $ 70,020 |
Supplemental oil, NGL and nat_5
Supplemental oil, NGL and natural gas disclosures (unaudited) - Results of operations of oil, NGL and natural gas producing activities (Details) - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2021 | Dec. 31, 2020 | Dec. 31, 2019 | |
Revenues: | |||
Oil, NGL and natural gas sales | $ 1,147,143 | $ 496,355 | $ 706,548 |
Production costs: | |||
Lease operating expenses | 101,994 | 82,020 | 90,786 |
Production and ad valorem taxes | 68,742 | 33,050 | 40,712 |
Transportation and marketing expenses | 47,916 | 49,927 | 25,397 |
Total production costs | 218,652 | 164,997 | 156,895 |
Other costs: | |||
Depletion | 201,691 | 203,492 | 250,857 |
Accretion of asset retirement obligation | 4,018 | 4,227 | 3,926 |
Impairment expense | 0 | 889,453 | 620,565 |
Income tax expense (benefit) | 14,456 | 0 | (3,257) |
Total other costs | 220,165 | 1,097,172 | 872,091 |
Results of operations | $ 708,326 | $ (765,814) | $ (322,438) |
Effective tax rate (as a percent) | 2.00% | 0.00% | 1.00% |
Supplemental oil, NGL and nat_6
Supplemental oil, NGL and natural gas disclosures (unaudited) - Net proved oil, NGL and natural gas reserves - (unaudited) - Narrative (Details) Boe in Thousands | 12 Months Ended | |||
Dec. 31, 2021Boelocationreserve_stream | Dec. 31, 2020Boereserve_stream | Dec. 31, 2019Boereserve_streamlocation | May 07, 2021 | |
Net proved oil and natural gas reserves | ||||
Percentage of proved reserves estimated by independent reserve engineers (percent) | 100.00% | 100.00% | 100.00% | |
Number of reportable reserves streams | reserve_stream | 3 | 3 | 3 | |
Revisions of previous estimates (MBOE) | 38,709 | 1,430 | 9,049 | |
Development wells drilled, net productive | location | 6 | |||
Development wells drilled, net nonproductive | location | 12 | |||
Extensions, discoveries and other additions (MBOE) | 19,369 | 7,888 | 40,078 | |
Sale of reserves (MBOE) | 88,125 | |||
Average working interest (as a percent) | 96.00% | 96.00% | ||
Acquisitions of reserves in place (MBOE) | 100,286 | 7,650 | 35,605 | |
Number of new proved undeveloped locations | location | 86 | |||
Disposal group, disposed of by sale, not discontinued operations | ||||
Net proved oil and natural gas reserves | ||||
Average working interest (as a percent) | 37.50% | |||
Performance, Pricing and Other Decreases | ||||
Net proved oil and natural gas reserves | ||||
Revisions of previous estimates (MBOE) | 3,622 | 16,265 | 12,417 | |
Negative Revision from Decrease in Estimated Quantities of Proved Undeveloped Locations | ||||
Net proved oil and natural gas reserves | ||||
Revisions of previous estimates (MBOE) | 2,885 | 3,140 | ||
Performance, Pricing and Other Increases | ||||
Net proved oil and natural gas reserves | ||||
Revisions of previous estimates (MBOE) | 37,341 | 29,080 | 20,858 | |
Reinterpretation of Undeveloped Locations | ||||
Net proved oil and natural gas reserves | ||||
Revisions of previous estimates (MBOE) | 7,875 | 608 | ||
Drilling of New Wells | ||||
Net proved oil and natural gas reserves | ||||
Extensions, discoveries and other additions (MBOE) | 6,724 | 5,347 | 24,629 | |
Horizontal Proved Undeveloped Properties | ||||
Net proved oil and natural gas reserves | ||||
Extensions, discoveries and other additions (MBOE) | 12,645 | 2,541 | 15,449 | |
New Proved Developed Locations | ||||
Net proved oil and natural gas reserves | ||||
Acquisitions of reserves in place (MBOE) | 47,310 | 367 | ||
Additional Acreage Acquired under Proved Locations | ||||
Net proved oil and natural gas reserves | ||||
Acquisitions of reserves in place (MBOE) | 52,976 | 4,016 | ||
Negative Revision due to Proved Undeveloped Locations Removed due to Year-End Pricing | ||||
Net proved oil and natural gas reserves | ||||
Revisions of previous estimates (MBOE) | 8,245 | |||
New Proved Undeveloped Locations | ||||
Net proved oil and natural gas reserves | ||||
Acquisitions of reserves in place (MBOE) | 3,267 | 34,299 | ||
New Proved Developed Producing Locations | ||||
Net proved oil and natural gas reserves | ||||
Acquisitions of reserves in place (MBOE) | 1,306 |
Supplemental oil, NGL and nat_7
Supplemental oil, NGL and natural gas disclosures (unaudited) - Net proved oil, NGL and natural gas reserves - (unaudited) (Details) bbl in Thousands, Mcf in Thousands, Boe in Thousands | 12 Months Ended | ||
Dec. 31, 2021BoebblMcf | Dec. 31, 2020BoebblMcf | Dec. 31, 2019BoeMcfbbl | |
Proved developed and undeveloped reserves: | |||
Beginning of year (MBOE) | Boe | 278,228 | 293,377 | 238,167 |
Revisions of previous estimates (MBOE) | Boe | 38,709 | 1,430 | 9,049 |
Extensions, discoveries and other additions (MBOE) | Boe | 19,369 | 7,888 | 40,078 |
Acquisitions of reserves in place (MBOE) | Boe | 100,286 | 7,650 | 35,605 |
Divestitures of reserves in place (MBOE) | Boe | (88,125) | ||
Production (MBOE) | Boe | (29,827) | (32,117) | (29,522) |
End of year (MBOE) | Boe | 318,640 | 278,228 | 293,377 |
Proved developed reserves: | |||
Beginning of year (energy) | Boe | 253,586 | 243,628 | 217,105 |
End of year (energy) | Boe | 232,048 | 253,586 | 243,628 |
Proved undeveloped reserves: | |||
Beginning of year (energy) | Boe | 24,642 | 49,749 | 21,062 |
End of year (energy) | Boe | 86,592 | 24,642 | 49,749 |
Oil (MBbl) | |||
Proved developed and undeveloped reserves: | |||
Beginning of year | 67,759 | 78,639 | 61,894 |
Revisions of previous estimates | 4,740 | (10,517) | (7,865) |
Extensions, discoveries and other additions | 10,354 | 4,282 | 13,573 |
Acquisitions of reserves in place | 65,572 | 5,182 | 21,413 |
Divestitures of reserves in place | (15,904) | ||
Production | (11,619) | (9,827) | (10,376) |
End of year | 120,902 | 67,759 | 78,639 |
Proved developed reserves: | |||
Beginning of year (volume) | 51,751 | 52,711 | 55,893 |
End of year (volume) | 70,727 | 51,751 | 52,711 |
Proved undeveloped reserves: | |||
Beginning of year (volume) | 16,008 | 25,928 | 6,001 |
End of year (volume) | 50,175 | 16,008 | 25,928 |
NGL (MBbl) | |||
Proved developed and undeveloped reserves: | |||
Beginning of year | 100,922 | 102,198 | 86,647 |
Revisions of previous estimates | 16,952 | 6,218 | 5,301 |
Extensions, discoveries and other additions | 5,269 | 1,811 | 12,614 |
Acquisitions of reserves in place | 19,711 | 1,310 | 6,754 |
Divestitures of reserves in place | (34,129) | ||
Production | (8,678) | (10,615) | (9,118) |
End of year | 100,047 | 100,922 | 102,198 |
Proved developed reserves: | |||
Beginning of year (volume) | 96,251 | 90,861 | 79,241 |
End of year (volume) | 78,908 | 96,251 | 90,861 |
Proved undeveloped reserves: | |||
Beginning of year (volume) | 4,671 | 11,337 | 7,406 |
End of year (volume) | 21,139 | 4,671 | 11,337 |
Natural gas (MMcf) | |||
Proved developed and undeveloped reserves: | |||
Beginning of year | Mcf | 657,284 | 675,237 | 537,756 |
Revisions of previous estimates | Mcf | 102,080 | 34,376 | 69,678 |
Extensions, discoveries and other additions | Mcf | 22,479 | 10,772 | 83,345 |
Acquisitions of reserves in place | Mcf | 90,023 | 6,948 | 44,627 |
Divestitures of reserves in place | Mcf | (228,546) | ||
Production | Mcf | (57,175) | (70,049) | (60,169) |
End of year | Mcf | 586,145 | 657,284 | 675,237 |
Proved developed reserves: | |||
Beginning of year (volume) | Mcf | 633,503 | 600,334 | 491,828 |
End of year (volume) | Mcf | 494,476 | 633,503 | 600,334 |
Proved undeveloped reserves: | |||
Beginning of year (volume) | Mcf | 23,781 | 74,903 | 45,928 |
End of year (volume) | Mcf | 91,669 | 23,781 | 74,903 |
Supplemental oil, NGL and nat_8
Supplemental oil, NGL and natural gas disclosures (unaudited) - Standardized measure of discounted future net cash flows (Details) - USD ($) $ in Thousands | 12 Months Ended | |||
Dec. 31, 2021 | Dec. 31, 2020 | Dec. 31, 2019 | Dec. 31, 2018 | |
Oil and Gas Exploration and Production Industries Disclosures [Abstract] | ||||
Future cash inflows | $ 11,846,148 | $ 3,824,104 | $ 5,702,580 | |
Future production costs | (3,595,524) | (1,740,537) | (1,994,732) | |
Future development costs | (1,064,527) | (351,568) | (615,839) | |
Future income tax expenses | (774,461) | (20,076) | (24,392) | |
Future net cash flows | 6,411,636 | 1,711,923 | 3,067,617 | |
10% discount for estimated timing of cash flows | (2,986,324) | (697,069) | (1,405,356) | |
Standardized measure of discounted future net cash flows | $ 3,425,312 | 1,014,854 | 1,662,261 | $ 2,114,237 |
Future net cash flow discount rate for impairment of oil and gas properties (as a percent) | 10.00% | |||
Non-cash full cost ceiling impairment | $ 0 | $ 889,453 | $ 620,565 |
Supplemental oil, NGL and nat_9
Supplemental oil, NGL and natural gas disclosures (unaudited) - Changes in the standardized measure of discounted future net cash flows (Details) - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2021 | Dec. 31, 2020 | Dec. 31, 2019 | |
Standardized measure of discounted future net cash flows relating to proved oil and natural gas reserves | |||
Standardized measure of discounted future net cash flows, beginning of year | $ 1,014,854 | $ 1,662,261 | $ 2,114,237 |
Changes in the year resulting from: | |||
Sales, less production costs | (934,440) | (331,358) | (549,653) |
Revisions of previous quantity estimates | 426,060 | 199 | 36,182 |
Extensions, discoveries and other additions | 293,511 | 60,004 | 361,479 |
Net change in prices and production costs | 1,572,662 | (770,885) | (900,019) |
Changes in estimated future development costs | 134,091 | 64,146 | 14,876 |
Previously estimated development incurred capital expenditures during the period | 169,376 | 186,261 | 158,631 |
Acquisitions of reserves in place | 1,509,087 | 14,208 | 207,636 |
Divestitures of reserves in place | (369,601) | 0 | 0 |
Accretion of discount | 102,607 | 167,227 | 217,119 |
Net change in income taxes | (279,722) | (1,205) | 46,939 |
Timing differences and other | (213,173) | (36,004) | (45,166) |
Standardized measure of discounted future net cash flows, end of year | $ 3,425,312 | $ 1,014,854 | $ 1,662,261 |
Supplemental quarterly financ_3
Supplemental quarterly financial data (unaudited) (Details) - USD ($) $ / shares in Units, $ in Thousands | 3 Months Ended | 12 Months Ended | |||||||||
Dec. 31, 2021 | Sep. 30, 2021 | Jun. 30, 2021 | Mar. 31, 2021 | Dec. 31, 2020 | Sep. 30, 2020 | Jun. 30, 2020 | Mar. 31, 2020 | Dec. 31, 2021 | Dec. 31, 2020 | Dec. 31, 2019 | |
Quarterly Financial Data [Abstract] | |||||||||||
Revenues | $ 470,224 | $ 379,250 | $ 294,371 | $ 250,230 | $ 188,065 | $ 173,547 | $ 110,588 | $ 204,992 | $ 1,394,075 | $ 677,192 | $ 837,281 |
Operating income | 243,449 | 265,736 | 108,347 | 102,803 | (78,031) | (167,678) | (434,052) | (181,972) | 720,335 | (861,733) | (408,591) |
Net income (loss) | $ 216,276 | $ 136,832 | $ (132,661) | $ (75,439) | $ (165,932) | $ (237,432) | $ (545,455) | $ 74,646 | $ 145,008 | $ (874,173) | $ (342,459) |
Net income (loss) per common share: | |||||||||||
Basic (USD per share) | $ 13.07 | $ 8.68 | $ (10.47) | $ (6.33) | $ (14.18) | $ (20.32) | $ (46.75) | $ 6.43 | $ 10.18 | $ (74.92) | $ (29.61) |
Diluted (USD per share) | $ 12.84 | $ 8.56 | $ (10.47) | $ (6.33) | $ (14.18) | $ (20.32) | $ (46.75) | $ 6.39 | $ 10.03 | $ (74.92) | $ (29.61) |