Document and Entity Information
Document and Entity Information - USD ($) | 12 Months Ended | ||
Dec. 31, 2021 | Feb. 22, 2022 | Jun. 30, 2021 | |
Document and Entity Information [Abstract] | |||
Document Type | 10-K | ||
Document Annual Report | true | ||
Document Period End Date | Dec. 31, 2021 | ||
Document Transition Report | false | ||
Entity File Number | 001-35410 | ||
Entity Registrant Name | Matador Resources Company | ||
Entity Incorporation, State or Country Code | TX | ||
Entity Address, Address Line Two | Suite 1500 | ||
Entity Tax Identification Number | 27-4662601 | ||
Entity Address, Address Line One | 5400 LBJ Freeway, | ||
Entity Address, City or Town | Dallas, | ||
Entity Address, State or Province | TX | ||
Entity Address, Postal Zip Code | 75240 | ||
City Area Code | 972 | ||
Local Phone Number | 371-5200 | ||
Title of 12(b) Security | Common Stock, par value $0.01 per share | ||
Trading Symbol | MTDR | ||
Security Exchange Name | NYSE | ||
Entity Well-known Seasoned Issuer | Yes | ||
Entity Voluntary Filers | No | ||
Entity Current Reporting Status | Yes | ||
Entity Interactive Data Current | Yes | ||
Entity Filer Category | Large Accelerated Filer | ||
Entity Small Business | false | ||
Entity Emerging Growth Company | false | ||
ICFR Auditor Attestation Flag | true | ||
Entity Shell Company | false | ||
Entity Public Float | $ 3,979,787,498 | ||
Entity Common Stock, Shares Outstanding | 118,043,776 | ||
Entity Central Index Key | 0001520006 | ||
Amendment Flag | false | ||
Document Fiscal Year Focus | 2021 | ||
Document Fiscal Period Focus | FY | ||
Current Fiscal Year End Date | --12-31 | ||
Documents Incorporated by Reference | The information required by Part III of this Annual Report on Form 10-K, to the extent not set forth herein, is incorporated by reference to the registrant’s definitive proxy statement relating to the 2022 Annual Meeting of Shareholders, which will be filed with the Securities and Exchange Commission within 120 days after the end of the fiscal year to which this Annual Report on Form 10-K relates. |
Audit Information
Audit Information | 12 Months Ended |
Dec. 31, 2021 | |
Audit Information [Abstract] | |
Auditor Name | KPMG LLP |
Auditor Location | Dallas, TX |
Auditor Firm ID | 185 |
Consolidated Balance Sheets
Consolidated Balance Sheets - USD ($) $ in Thousands | Dec. 31, 2021 | Dec. 31, 2020 |
Current assets | ||
Cash | $ 48,135 | $ 57,916 |
Restricted cash | 38,785 | 33,467 |
Accounts receivable | ||
Oil and natural gas revenues | 164,242 | 85,098 |
Joint interest billings | 48,366 | 34,823 |
Other | 28,808 | 17,212 |
Derivative instruments | 1,971 | 6,727 |
Lease and well equipment inventory | 12,188 | 10,584 |
Prepaid expenses and other current assets | 28,810 | 15,802 |
Total current assets | 371,305 | 261,629 |
Oil and natural gas properties, full-cost method | ||
Evaluated | 6,007,325 | 5,295,931 |
Unproved and unevaluated | 964,714 | 902,133 |
Midstream properties | 900,979 | 841,695 |
Midstream properties | 30,123 | 29,561 |
Less accumulated depletion, depreciation and amortization | (4,046,456) | (3,701,551) |
Net property and equipment | 3,856,685 | 3,367,769 |
Other assets | ||
Derivative instruments | 0 | 2,570 |
Other long-term assets | 34,163 | 55,312 |
Total assets | 4,262,153 | 3,687,280 |
Current liabilities | ||
Accounts payable | 26,256 | 13,982 |
Accrued liabilities | 253,283 | 119,158 |
Royalties payable | 94,359 | 66,049 |
Amounts due to affiliates | 27,324 | 4,934 |
Derivative instruments | 16,849 | 45,186 |
Advances from joint interest owners | 18,074 | 4,191 |
Other current liabilities | 28,692 | 37,436 |
Total current liabilities | 464,837 | 290,936 |
Long-term liabilities | ||
Borrowings under Credit Agreement | 100,000 | 440,000 |
Borrowings under San Mateo Credit Facility | 385,000 | 334,000 |
Senior unsecured notes payable | 1,042,580 | 1,040,998 |
Asset retirement obligations | 41,689 | 37,919 |
Deferred income taxes | 77,938 | 0 |
Other long-term liabilities | 22,721 | 30,402 |
Total long-term liabilities | 1,669,928 | 1,883,319 |
Commitments and contingencies (Note 14) | ||
Shareholders' equity | ||
Common stock — $0.01 par value, 160,000,000 shares authorized; 117,861,923 and 116,847,003 shares issued; and 117,850,233 and 116,844,768 shares outstanding, respectively | 1,179 | 1,169 |
Additional paid-in capital | 2,077,592 | 2,027,069 |
Accumulated deficit | (171,318) | (741,705) |
Treasury stock, at cost, 11,945 and 2,235 shares, respectively | (243) | (3) |
Total shareholders' equity | 1,907,210 | 1,286,530 |
Non-controlling interest in subsidiaries | 220,178 | 226,495 |
Total shareholders’ equity | 2,127,388 | 1,513,025 |
Total liabilities and shareholders’ equity | $ 4,262,153 | $ 3,687,280 |
Consolidated Balance Sheets (Pa
Consolidated Balance Sheets (Parenthetical) - $ / shares | Dec. 31, 2021 | Dec. 31, 2020 |
Statement of Financial Position [Abstract] | ||
Common stock, par value (usd per share) | $ 0.01 | $ 0.01 |
Common stock, shares authorized (in shares) | 160,000,000 | 160,000,000 |
Common stock, shares issued (in shares) | 117,861,923 | 116,847,003 |
Common stock, shares outstanding (in shares) | 117,850,233 | 116,844,768 |
Treasury stock (in shares) | 11,945 | 2,235 |
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 | |||
Revenues | $ 1,862,075 | $ 851,135 | $ 1,026,204 |
Lease bonus - mineral acreage | 0 | 4,062 | 1,711 |
Realized (loss) gain on derivatives | (220,105) | 38,937 | 9,482 |
Unrealized gain (loss) on derivatives | 21,011 | (32,008) | (53,727) |
Total revenues | 1,662,981 | 862,126 | 983,670 |
Expenses | |||
Production taxes, transportation and processing | 178,987 | 93,338 | 92,273 |
Lease operating | 108,964 | 104,953 | 117,305 |
Purchased natural gas | 77,126 | 32,734 | 69,398 |
Depletion, depreciation and amortization | 344,905 | 361,831 | 350,540 |
Accretion of asset retirement obligations | 2,068 | 1,948 | 1,822 |
Full-cost ceiling impairment | 0 | 684,743 | 0 |
General and administrative | 96,396 | 62,578 | 80,054 |
Total expenses | 869,905 | 1,383,625 | 748,190 |
Operating income (loss) | 793,076 | (521,499) | 235,480 |
Other income (expense) | |||
Net loss on asset sales and impairment | (331) | (2,832) | (967) |
Interest expense | (74,687) | (76,692) | (73,873) |
Other (expense) income | (2,712) | 1,864 | (2,126) |
Total other expense | (77,730) | (77,660) | (76,966) |
Income (loss) before income taxes | 715,346 | (599,159) | 158,514 |
Income tax provision (benefit) | |||
Deferred | 74,710 | (45,599) | 35,532 |
Total income tax provision (benefit) | 74,710 | (45,599) | 35,532 |
Net income (loss) | 584,968 | (593,205) | 87,777 |
Net income attributable to non-controlling interest in subsidiaries | (55,668) | (39,645) | (35,205) |
Net income (loss) attributable to Matador Resources Company shareholders | $ 640,636 | $ (553,560) | $ 122,982 |
Earnings (loss) per common share attributable to Matador Resources Company shareholders | |||
Basic (usd per share) | $ 5 | $ (5.11) | $ 0.75 |
Diluted (usd per share) | $ 4.91 | $ (5.11) | $ 0.75 |
Weighted average common shares outstanding | |||
Basic (in shares) | 116,999 | 116,068 | 116,555 |
Diluted (in shares) | 119,163 | 116,068 | 117,063 |
Oil and natural gas revenues | |||
Revenues | |||
Revenues | $ 1,700,542 | $ 744,461 | $ 892,325 |
Third-party midstream services revenues | |||
Revenues | |||
Revenues | 75,499 | 64,932 | 59,110 |
Expenses | |||
Cost of Goods and Services Sold | 61,459 | 41,500 | 36,798 |
Sales of purchased natural gas | |||
Revenues | |||
Revenues | $ 86,034 | $ 41,742 | $ 74,769 |
Consolidated Statements of Chan
Consolidated Statements of Changes in Shareholders' Equity - USD ($) | Total | Common stock | Additional paid-in capital | Accumulated deficit | Treasury stock | Parent | Noncontrolling Interest | San Mateo I | San Mateo IAdditional paid-in capital | San Mateo IParent | San Mateo II | San Mateo IIAdditional paid-in capital | San Mateo IIParent | San Mateo IINoncontrolling Interest |
Beginning Balance at Dec. 31, 2018 | $ 1,779,657,000 | $ 1,164,000 | $ 1,924,408,000 | $ (236,277,000) | $ (415,000) | $ 1,688,880,000 | $ 90,777,000 | |||||||
Beginning Balance, shares (in shares) at Dec. 31, 2018 | 116,375,000 | 21,000 | ||||||||||||
Increase (Decrease) in Stockholders' Equity [Roll Forward] | ||||||||||||||
Issuance of common stock pursuant to employee stock compensation plan, shares | 240,000 | |||||||||||||
Issuance of common stock pursuant to employee stock compensation plan | 0 | $ 2,000 | (2,000) | 0 | ||||||||||
Issuance of Class A common stock to Board member and advisors, shares | 50,000 | |||||||||||||
Issuance of Class A common stock to Board member and advisors | 0 | $ 0 | 0 | 0 | ||||||||||
Stock options expense related to equity based awards | 23,396,000 | 23,396,000 | 23,396,000 | |||||||||||
Stock options exercised, shares | 220,000 | |||||||||||||
Stock options exercised, net of options forfeited in net share settlements | 3,300,000 | $ 2,000 | 3,298,000 | 3,300,000 | ||||||||||
Liability-Based Stock Option Awards Settled, Shares | 1,000 | |||||||||||||
Liability-Based Stock Option Awards Settled | 11,000 | 11,000 | 11,000 | |||||||||||
Restricted stock forfeited, shares | 222,000 | |||||||||||||
Restricted stock forfeited | (3,691,000) | $ (3,691,000) | (3,691,000) | |||||||||||
Contributions related to formation of San Mateo I (see Note 6) | $ 11,613,000 | $ 11,613,000 | $ 11,613,000 | $ 0 | $ (506,000) | $ (506,000) | $ 506,000 | |||||||
Contributions from non-controlling interest owners of less-than-wholly-owned subsidiaries | 71,384,000 | 22,874,000 | 22,874,000 | 48,510,000 | ||||||||||
Distributions to non-controlling interest owners of less-than wholly-owned subsidiaries | (39,200,000) | (39,200,000) | ||||||||||||
Cancellation of treasury stock, shares | (242,000) | (242,000) | ||||||||||||
Cancellation of treasury stock | 0 | $ (2,000) | (4,078,000) | $ 4,080,000 | 0 | |||||||||
Net (loss) income | 122,982,000 | 87,777,000 | 87,777,000 | 35,205,000 | ||||||||||
Ending Balance, shares (in shares) at Dec. 31, 2019 | 116,644,000 | 1,000 | ||||||||||||
Ending Balance at Dec. 31, 2019 | 1,969,452,000 | $ 1,166,000 | 1,981,014,000 | (148,500,000) | $ (26,000) | 1,833,654,000 | 135,798,000 | |||||||
Increase (Decrease) in Stockholders' Equity [Roll Forward] | ||||||||||||||
Contribution related to formation of San Mateo, I, tax | 3,100,000 | |||||||||||||
Contributions from non-controlling interest owners of less-than-wholly-owned subsidiaries, tax | 5,900,000 | |||||||||||||
Issuance of common stock pursuant to employee stock compensation plan, shares | 244,000 | |||||||||||||
Issuance of common stock pursuant to employee stock compensation plan | 0 | $ 2,000 | (2,000) | 0 | ||||||||||
Stock Issued During Period, Shares, Issued for Services | 85,000 | |||||||||||||
Stock Issued During Period, Value, Issued for Services | 0 | $ 1,000 | (1,000) | |||||||||||
Stock options expense related to equity based awards | 17,452,000 | 17,452,000 | 17,452,000 | |||||||||||
Stock options exercised, shares | 0 | |||||||||||||
APIC, Share-based Payment Arrangement, Recognition and Exercise | (24,000) | $ 0 | (24,000) | (24,000) | ||||||||||
Liability-Based Stock Option Awards Settled, Shares | 22,000 | |||||||||||||
Liability-Based Stock Option Awards Settled | 297,000 | |||||||||||||
Restricted stock forfeited, shares | 149,000 | |||||||||||||
Restricted stock forfeited | (1,489,000) | $ (1,489,000) | (1,489,000) | |||||||||||
Contributions related to formation of San Mateo I (see Note 6) | 11,613,000 | 11,613,000 | 11,613,000 | |||||||||||
Contributions from non-controlling interest owners of less-than-wholly-owned subsidiaries | 114,854,000 | 18,232,000 | 18,232,000 | 96,622,000 | ||||||||||
Distributions to non-controlling interest owners of less-than wholly-owned subsidiaries | (45,570,000) | (45,570,000) | ||||||||||||
Cancellation of treasury stock, shares | (148,000) | (148,000) | ||||||||||||
Cancellation of treasury stock | $ 0 | (1,512,000) | $ 1,512,000 | |||||||||||
Net (loss) income | $ (553,560,000) | (593,205,000) | (593,205,000) | 39,645,000 | ||||||||||
Ending Balance, shares (in shares) at Dec. 31, 2020 | 116,844,768 | 116,847,000 | 2,000 | |||||||||||
Ending Balance at Dec. 31, 2020 | $ 1,513,025,000 | $ 1,169,000 | 2,027,069,000 | (741,705,000) | $ (3,000) | 1,286,530,000 | 226,495,000 | |||||||
Increase (Decrease) in Stockholders' Equity [Roll Forward] | ||||||||||||||
Contribution related to formation of San Mateo, I, tax | 3,100,000 | |||||||||||||
Contributions from non-controlling interest owners of less-than-wholly-owned subsidiaries, tax | 4,800,000 | |||||||||||||
Dividends, common stock, cash | 14,581,000 | 14,581,000 | 14,581,000 | |||||||||||
Issuance of common stock pursuant to employee stock compensation plan, shares | 768,000 | |||||||||||||
Issuance of common stock pursuant to employee stock compensation plan | 0 | $ 7,000 | (7,000) | |||||||||||
Issuance of Class A common stock to Board member and advisors, shares | 81,000 | |||||||||||||
Issuance of Class A common stock to Board member and advisors | 0 | $ 1,000 | (1,000) | |||||||||||
Stock options expense related to equity based awards | $ 12,113,000 | 12,113,000 | 12,113,000 | |||||||||||
Stock options exercised, shares | 1,368,000 | 312,000 | ||||||||||||
APIC, Share-based Payment Arrangement, Recognition and Exercise | $ (4,255,000) | $ 3,000 | (4,258,000) | (4,255,000) | ||||||||||
Restricted stock forfeited, shares | 156,000 | |||||||||||||
Restricted stock forfeited | (2,621,000) | $ (2,621,000) | (2,621,000) | |||||||||||
Contributions related to formation of San Mateo I (see Note 6) | $ 45,056,000 | $ 45,056,000 | $ 45,056,000 | |||||||||||
Distributions to non-controlling interest owners of less-than wholly-owned subsidiaries | (61,985,000) | (61,985,000) | ||||||||||||
Cancellation of treasury stock, shares | (146,000) | (146,000) | ||||||||||||
Cancellation of treasury stock | 0 | $ 1,000 | (2,380,000) | $ 2,381,000 | ||||||||||
Net (loss) income | $ 640,636,000 | 584,968,000 | 584,968,000 | 55,668,000 | ||||||||||
Ending Balance, shares (in shares) at Dec. 31, 2021 | 117,850,233 | 117,862,000 | 12,000 | |||||||||||
Ending Balance at Dec. 31, 2021 | $ 2,127,388,000 | $ 1,179,000 | $ 2,077,592,000 | $ (171,318,000) | $ (243,000) | $ 1,907,210,000 | $ 220,178,000 | |||||||
Increase (Decrease) in Stockholders' Equity [Roll Forward] | ||||||||||||||
Contribution related to formation of San Mateo, I, tax | $ 3,600,000 |
Consolidated Statements of Cash
Consolidated Statements of Cash Flows - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2021 | Dec. 31, 2020 | Dec. 31, 2019 | |
Operating activities | |||
Net income (loss) | $ 640,636 | $ (553,560) | $ 122,982 |
Adjustments to reconcile net income (loss) to net cash provided by operating activities | |||
Unrealized (gain) loss on derivatives | (21,011) | 32,008 | 53,727 |
Depletion, depreciation and amortization | 344,905 | 361,831 | 350,540 |
Accretion of asset retirement obligations | 2,068 | 1,948 | 1,822 |
Full-cost ceiling impairment | 0 | 684,743 | 0 |
Stock-based compensation expense | 9,039 | 13,625 | 18,505 |
Net deferred income tax provision (benefit) | 74,710 | (45,599) | 35,532 |
Amortization of debt issuance cost | 3,659 | 2,832 | 2,484 |
Net loss on asset sales and impairment | 331 | 2,832 | 967 |
Changes in operating assets and liabilities | |||
Accounts receivable | (98,456) | 53,001 | (43,261) |
Lease and well equipment inventory | (1,537) | (655) | 4,777 |
Prepaid expenses | (11,786) | (3,010) | (4,844) |
Other assets | 56 | 1,681 | 678 |
Accounts payable, accrued liabilities and other current liabilities | 76,891 | (43,844) | (19,004) |
Royalties payable | 28,310 | (19,144) | 20,417 |
Advances from joint interest owners | 7,018 | (10,646) | 3,869 |
Other long-term liabilities | (1,478) | (461) | 2,851 |
Net cash provided by operating activities | 1,053,355 | 477,582 | 552,042 |
Investing activities | |||
Drilling, completion and equipping capital expenditures | (431,136) | (471,087) | (679,395) |
Acquisition of oil and natural gas properties | (238,609) | (72,809) | (50,766) |
Midstream capital expenditures | (63,359) | (234,359) | (192,035) |
Expenditures for other property and equipment | (376) | (2,200) | (3,701) |
Proceeds from sale of assets | 4,215 | 4,789 | 21,921 |
Net cash used in investing activities | (729,265) | (775,666) | (903,976) |
Financing activities | |||
Repayments of borrowings under Credit Agreement | (600,000) | (35,000) | (35,000) |
Borrowings under Credit Agreement | 260,000 | 220,000 | 250,000 |
Repayments of borrowings under San Mateo Credit Facility | (84,000) | 0 | 0 |
Borrowings under San Mateo Credit Facility | 135,000 | 46,000 | 68,000 |
Cost to enter into or amend credit facilities | (4,108) | (660) | (1,443) |
Proceeds from stock options exercised | 1,335 | 45 | 3,300 |
Dividends paid | (14,581) | ||
Contributions related to formation of San Mateo | 48,626 | 14,700 | 14,700 |
Contributions from non-controlling interest owners of less-than-wholly-owned subsidiaries | 0 | 119,700 | 77,330 |
Distributions to non-controlling interest owners of less-than-wholly-owned subsidiaries | (61,985) | (45,570) | (39,200) |
Taxes paid related to net share settlement of stock-based compensation | (8,211) | (1,556) | (3,691) |
Other | (629) | 6,680 | (918) |
Net cash (used in) provided by financing activities | (328,553) | 324,339 | 333,078 |
(Decrease) increase in cash and restricted cash | (4,463) | 26,255 | (18,856) |
Cash and restricted cash at beginning of period | 91,383 | 65,128 | 83,984 |
Cash and restricted cash at end of period | $ 86,920 | $ 91,383 | $ 65,128 |
Consolidated Statements of Ch_2
Consolidated Statements of Changes in Shareholders' Equity (Parenthetical) - USD ($) $ in Thousands | 1 Months Ended | 3 Months Ended | 12 Months Ended | ||
Oct. 31, 2021 | Dec. 31, 2021 | Dec. 31, 2021 | Dec. 31, 2020 | Dec. 31, 2019 | |
Statement of Stockholders' Equity [Abstract] | |||||
Contribution related to formation of San Mateo, I, tax | $ 3,600 | $ 3,100 | $ 3,100 | ||
Contributions from non-controlling interest owners of less-than-wholly-owned subsidiaries, tax | $ 4,800 | $ 5,900 | |||
Common stock, dividends (in usd per share) | $ 0.05 | $ 0.025 | $ 0.125 | ||
Dividends, common stock, cash | $ (14,581) |
Nature of Operations
Nature of Operations | 12 Months Ended |
Dec. 31, 2021 | |
Organization, Consolidation and Presentation of Financial Statements [Abstract] | |
NATURE OF OPERATIONS | NATURE OF OPERATIONS Matador Resources Company, a Texas corporation (“Matador” and, collectively with its subsidiaries, the “Company”), is an independent energy company engaged in the exploration, development, production and acquisition of oil and natural gas resources in the United States, with an emphasis on oil and natural gas shale and other unconventional plays. The Company’s current operations are focused primarily on the oil and liquids-rich portion of the Wolfcamp and Bone Spring plays in the Delaware Basin in Southeast New Mexico and West Texas. The Company also operates in the Eagle Ford shale play in South Texas and the Haynesville shale and Cotton Valley plays in Northwest Louisiana. Additionally, the Company conducts midstream operations, primarily through its midstream joint venture, San Mateo Midstream, LLC (collectively with its subsidiaries, “San Mateo”), in support of the Company’s exploration, development and production operations and provides natural gas processing, oil transportation services, oil, natural gas and produced water gathering services and produced water disposal services to third parties. |
Summary of Significant Accounti
Summary of Significant Accounting Policies | 12 Months Ended |
Dec. 31, 2020 | |
Accounting Policies [Abstract] | |
SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES | Basis of Presentation The consolidated financial statements include the accounts of Matador and its wholly-owned and majority-owned subsidiaries. These consolidated financial statements have been prepared in accordance with generally accepted accounting principles in the United States of America (“U.S. GAAP”). Accordingly, the Company consolidates certain subsidiaries and joint ventures that are less-than-wholly-owned and are not involved in oil and natural gas exploration, including San Mateo, and the net income and equity attributable to the non-controlling interest in these subsidiaries have been reported separately as required by Accounting Standards Codification (“ASC”), Consolidation (Topic 810) . The Company proportionately consolidates certain joint ventures that are less-than-wholly-owned and are involved in oil and natural gas exploration. All intercompany balances and transactions have been eliminated in consolidation. Use of Estimates The preparation of financial statements in conformity with U.S. GAAP requires management to make estimates and assumptions that affect the amounts reported in the financial statements and accompanying notes. These estimates and assumptions may also affect 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. The Company’s consolidated financial statements are based on a number of significant estimates, including oil and natural gas revenues, accrued assets and liabilities, stock-based compensation, valuation of derivative instruments, deferred tax assets and liabilities, purchase price allocations and oil and natural gas reserves. The estimates of oil and natural gas reserves quantities and future net cash flows are the basis for the calculations of depletion and impairment of oil and natural gas properties, as well as estimates of asset retirement obligations and certain tax accruals. The Company’s oil and natural gas reserves estimates, which are inherently imprecise and based upon many factors that are beyond the Company’s control, including oil and natural gas prices, are prepared by the Company’s engineering staff in accordance with guidelines established by the Securities and Exchange Commission (“SEC”) and then audited for their reasonableness and conformance with SEC guidelines by Netherland, Sewell & Associates, Inc., independent reservoir engineers. While the Company believes its estimates are reasonable, changes in facts and assumptions or the discovery of new information may result in revised estimates. Actual results could differ from these estimates. Restricted Cash Restricted cash represents a portion of the cash associated with the Company’s less-than-wholly-owned subsidiaries, primarily San Mateo. By contractual agreement, the cash in the accounts held by the Company’s less-than-wholly-owned subsidiaries is not to be commingled with other Company cash and is to be used only to fund the capital expenditures and operations of these less-than-wholly-owned subsidiaries. Accounts Receivable The Company sells its operated oil, natural gas and natural gas liquid (“NGL”) production to various purchasers (see “—Revenues” below). In addition, the Company may participate with industry partners in the drilling, completion and operation of oil and natural gas wells. Substantially all of the Company’s accounts receivable are due from purchasers of oil, natural gas and NGLs, participants in oil and natural gas wells for which the Company serves as the operator, San Mateo’s customers or the Company’s derivative counterparties. Accounts receivable are typically due within 30 to 60 days of the production date and 30 days of the billing date and are stated at amounts due from purchasers and industry partners. Amounts are considered past due if they have been outstanding for 60 days or more. No interest is typically charged on past due amounts. The Company reviews its need for an allowance for doubtful accounts on a periodic basis and determines the allowance, if any, by considering the length of time past due, previous loss history, future net revenues associated with the debtor’s ownership interest in oil and natural gas properties operated by the Company and the debtor’s ability to pay its obligations, among other things. The Company has no allowance for doubtful accounts related to its accounts receivable for any reporting period presented. For the year ended December 31, 2021, three significant purchasers accounted for 72% of the Company’s total oil, natural gas and NGL revenues: Plains Marketing, L.P. (29%), Exxon Mobil Corporation (33%) and BP America Production Company (10%). For the year ended December 31, 2020, two significant purchasers accounted for 65% of the Company’s total oil, natural gas and NGL revenues: Plains Marketing, L.P. (57%) and Exxon Mobil Corporation (8%). For the year ended December 31, 2019, two significant purchasers accounted for 67% of the Company’s total oil, natural gas and NGL revenues: Plains Marketing, L.P. (53%) and BP America Production Company (14%). If the Company lost one or more of these significant purchasers and were unable to sell its production to other purchasers on terms it considers acceptable, it could materially and adversely affect the Company’s business, financial condition, results of operations and cash flows. At December 31, 2021, 2020 and 2019, approximately 39%, 35% and 31%, respectively, of the Company’s accounts receivable, including joint interest billings, related to these purchasers. Lease and Well Equipment Inventory Lease and well equipment inventory is stated at the lower of cost or market and consists entirely of materials or equipment scheduled for use in future well or midstream operations. Oil and Natural Gas Properties The Company uses the full-cost method of accounting for its investments in oil and natural gas properties. Under this method, all costs associated with the acquisition, exploration and development of oil and natural gas properties and reserves, including unproved and unevaluated property costs, are capitalized as incurred and accumulated in a single cost center representing the Company’s activities, which are undertaken exclusively in the United States. Such costs include lease acquisition costs, geological and geophysical expenditures, lease rentals on undeveloped properties, costs of drilling both productive and non-productive wells, capitalized interest on qualifying projects and general and administrative expenses directly related to acquisition, exploration and development activities, but do not include any costs related to production, selling or general corporate administrative activities. The Company capitalized $38.4 million, $30.0 million and $31.1 million of its general and administrative costs into oil and natural gas properties in 2021, 2020 and 2019, respectively. The Company capitalized $4.8 million, $5.0 million and $7.6 million of its interest expense into oil and natural gas properties for the years ended December 31, 2021, 2020 and 2019, respectively. Capitalized costs of oil and natural gas properties are amortized using the unit-of-production method based upon production and estimates of proved reserves quantities. For the years ended December 31, 2021, 2020 and 2019, the Company recorded depletion expense of $310.1 million, $334.8 million and $330.7 million, respectively. Unproved and unevaluated property costs are excluded from the amortization base used to determine depletion. Unproved and unevaluated properties are assessed for possible impairment on a periodic basis based upon changes in operating or economic conditions. This assessment includes consideration of the following factors, among others: the assignment of proved reserves, geological and geophysical evaluations, intent to drill, remaining lease term and drilling activity and results. Upon impairment, the costs of the unproved and unevaluated properties are immediately included in the amortization base. Exploratory dry holes are included in the amortization base immediately upon determination that the well is not productive. Sales of oil and natural gas properties are accounted for as adjustments to net capitalized costs with no gain or loss recognized, unless such adjustments would significantly alter the relationship between net capitalized costs and proved reserves of oil and natural gas. All costs related to production activities and maintenance and repairs are expensed as incurred. Significant workovers that increase the properties’ reserves are capitalized. Ceiling Test The net capitalized costs of oil and natural gas properties are limited to the lower of unamortized costs less related deferred income taxes or the cost center “ceiling.” The cost center ceiling is defined as the sum of: (a) the present value, discounted at 10%, of future net revenues of proved oil and natural gas reserves, reduced by the estimated costs of developing these reserves, plus (b) unproved and unevaluated property costs not being amortized, plus (c) the lower of cost or estimated fair value of unproved and unevaluated properties included in the costs being amortized, if any, less (d) any income tax effects related to the properties involved. Any excess of the Company’s net capitalized costs above the cost center ceiling as described above is charged to operations as a full-cost ceiling impairment. The Company’s derivative instruments are not considered in the ceiling test computations as the Company does not designate these instruments as hedge instruments for accounting purposes. The estimated present value of after-tax future net cash flows from proved oil and natural gas reserves is highly dependent upon the quantities of proved reserves, the estimation of which requires substantial judgment. The associated commodity prices and the applicable discount rate used in these estimates are in accordance with guidelines established by the SEC. Under these guidelines, oil and natural gas reserves are estimated using then-current operating and economic conditions, with no provision for price and cost changes in future periods except by contractual arrangements. Future net revenues are calculated using prices that represent the arithmetic averages of the first-day-of-the-month oil and natural gas prices for the previous 12-month period, and a 10% discount factor is used to determine the present value of future net revenues. For the period from January through December 2021, these average oil and natural gas prices were $63.04 per Bbl and $3.60 per MMBtu, respectively. For the period from January through December 2020, these average oil and natural gas prices were $36.04 per Bbl and $1.99 per MMBtu, respectively. For the period from January through December 2019, these average oil and natural gas prices were $52.19 per Bbl and $2.58 per MMBtu, respectively. In estimating the present value of after-tax future net cash flows from proved oil and natural gas reserves, the average oil prices were further adjusted by property for quality, transportation and marketing fees and regional price differentials, and the average natural gas prices were further adjusted by property for energy content, transportation and marketing fees and regional price differentials. During the years ended December 31, 2021 and 2019, the Company’s full-cost ceiling exceeded the net capitalized costs less related deferred income taxes. As a result, the Company recorded no impairment to its net capitalized costs during the years ended December 31, 2021 and 2019. For the year ended December 31, 2020, the Company’s net capitalized costs less related deferred income taxes exceeded the full-cost ceiling. As a result, the Company recorded an impairment charge of $684.7 million, exclusive of tax effect, to its consolidated statement of operations for the year ended December 31, 2020 with the related deferred income tax benefit recorded net of a valuation allowance (see Note 8). As a non-cash item, the full-cost ceiling impairment impacts the accumulated depletion and the net carrying value of the Company’s assets on its consolidated balance sheets, as well as the corresponding shareholders’ equity, but it has no impact on the Company’s net cash flows as reported. Changes in oil and natural gas production rates, oil and natural gas prices, reserves estimates, future development costs and other factors will determine the Company’s actual ceiling test computation and impairment analyses in future periods. Midstream Properties and Other Property and Equipment Midstream properties and other property and equipment are recorded at historical cost and include midstream equipment and facilities, including the Company’s pipelines, processing facilities and produced water disposal systems, and corporate assets, including furniture, fixtures, equipment, land and leasehold improvements. Midstream equipment and facilities are depreciated over a 30-year useful life using the straight-line, mid-month convention method. Leasehold improvements are depreciated over the lesser of their useful lives or the term of the lease. Software, furniture, fixtures and other equipment are depreciated over their useful life ( five The Company evaluates midstream properties and other property and equipment for potential impairment whenever events or changes in circumstances indicate that their carrying value may not be recoverable. The carrying amount of a long-lived asset is not recoverable when it exceeds the undiscounted sum of the future cash flows expected to result from the use and eventual disposition of the asset. Expected future cash flows represent management’s estimates based on reasonable and supportable assumptions. Gains and losses associated with the disposition of midstream properties and other property and equipment are recognized as a component of other income (expense) in the consolidated statements of operations. Asset Retirement Obligations The Company recognizes the fair value of an asset retirement obligation in the period in which it is incurred if a reasonable estimate of fair value can be made. The asset retirement obligation is recorded as a liability at its estimated present value, with an offsetting increase recognized in oil and natural gas properties, midstream properties or other property and equipment on the consolidated balance sheets. Periodic accretion of the discounted value of the estimated liability is recorded as an expense in the consolidated statements of operations. Derivative Financial Instruments From time to time, the Company uses derivative financial instruments to mitigate its exposure to commodity price risk associated with oil, natural gas and NGL prices. The Company’s derivative financial instruments are recorded on the consolidated balance sheets as either an asset or a liability measured at fair value. The Company has elected not to apply hedge accounting for its existing derivative financial instruments, and as a result, the Company recognizes the change in derivative fair value between reporting periods currently in its consolidated statements of operations. The fair value of the Company’s derivative financial instruments is determined using industry-standard models that consider various inputs including: (i) quoted forward prices for commodities, (ii) time value of money and (iii) current market and contractual prices for the underlying instruments, as well as other relevant economic measures. Realized gains and losses from the settlement of derivative financial instruments and unrealized gains and unrealized losses from valuation changes in the remaining unsettled derivative financial instruments are reported as a component of revenues in the consolidated statements of operations. See Note 12 for additional information about the Company’s derivative instruments. Revenues The Company enters into contracts with customers to sell its oil and natural gas production. Revenue from these contracts is recognized when the Company’s performance obligations under these contracts are satisfied, which generally occurs with the transfer of control of the oil and natural gas to the purchaser. Control is generally considered transferred when the following criteria are met: (i) transfer of physical custody, (ii) transfer of title, (iii) transfer of risk of loss and (iv) relinquishment of any repurchase rights or other similar rights. Given the nature of the products sold, revenue is recognized at a point in time based on the amount of consideration the Company expects to receive in accordance with the price specified in the contract. Consideration under oil and natural gas marketing contracts is typically received from the purchaser one The majority of the Company’s oil marketing contracts transfer physical custody and title at or near the wellhead or a central delivery point, which is generally when control of the oil has been transferred to the purchaser. The majority of the oil produced is sold under contracts using market-based pricing, which price is then adjusted for differentials based upon delivery location and oil quality. To the extent the differentials are incurred at or after the transfer of control of the oil, the differentials are included in oil revenues on the statements of operations, as they represent part of the transaction price of the contract. If the differentials, or other related costs, are incurred prior to the transfer of control of the oil, those costs are included in production taxes, transportation and processing expenses on the Company’s consolidated statements of operations, as they represent payment for services performed outside of the contract with the customer. The Company’s natural gas is sold at the lease location, at the inlet or outlet of a natural gas processing plant or at an interconnect near a marketing hub following transportation from a processing plant. The majority of the Company’s natural gas is sold under fee-based contracts. When the natural gas is sold at the lease, the purchaser gathers the natural gas via pipeline to natural gas processing plants where, if necessary, NGLs are extracted. The NGLs and remaining residue gas are then sold by the purchaser, or if the Company elects to take in-kind the natural gas or the NGLs, the Company sells the natural gas or the NGLs to a third party. Under the fee-based contracts, the Company receives NGL and residue gas value, less the fee component, or is invoiced the fee component. To the extent control of the natural gas transfers upstream of the gathering and processing activities, revenue is recognized as the net amount received from the purchaser. To the extent that control transfers downstream of those services, revenue is recognized on a gross basis, and the related costs are included in production taxes, transportation and processing expenses on the Company’s consolidated statements of operations. The Company recognizes midstream services revenues at the time services have been rendered and the price is fixed and determinable. Third-party midstream services revenues are those revenues from midstream operations related to third parties, including working interest owners in the Company’s operated wells. All midstream services revenues related to the Company’s working interest are eliminated in consolidation. Since the Company has a right to payment from its customers in amounts that correspond directly to the value that the customer receives from the performance completed on each contract, the Company applies the practical expedient in Accounting Standards Update 2014-09, Revenue from Contracts with Customers (Topic 606) (“ASC 606”) that allows recognition of revenue in the amount for which there is a right to invoice the customer without estimating a transaction price for each contract and allocating that transaction price to the performance obligations within each contract. The Company periodically enters into natural gas purchase transactions with third parties whereby the Company (i) purchases the third party’s natural gas and subsequently sells the natural gas to other purchasers or (ii) processes the third party’s natural gas at San Mateo’s Black River cryogenic natural gas processing plant in Eddy County, New Mexico (the “Black River Processing Plant”) and then purchases, and subsequently sells, the residue gas and NGLs to other purchasers. Revenues and expenses from these transactions are presented on a gross basis on the Company’s consolidated statements of operations as the Company acts as a principal in the transactions by assuming the risk and rewards of ownership, including credit risk, of the natural gas purchased and by assuming the responsibility to deliver and process the natural gas volumes to be sold. From time to time, the Company, as an owner of mineral interests, may enter into or extend a lease to a third-party lessee to develop the oil and natural gas attributable to certain of its mineral interests in return for a specified payment or lease bonus. In those instances, revenue is recognized in the period when the lease is signed and the Company has no further obligation to the lessee. The Company records these payments as “Lease bonus - mineral acreage” revenues on its consolidated statements of operations. The following table summarizes the Company’s total revenues and revenues from contracts with customers on a disaggregated basis for the years ended December 31, 2021, 2020 and 2019 (in thousands). Year Ended December 31, 2021 2020 2019 Revenues from contracts with customers $ 1,862,075 $ 851,135 $ 1,026,204 Lease bonus - mineral acreage — 4,062 1,711 Realized (loss) gain on derivatives (220,105) 38,937 9,482 Unrealized gain (loss) on derivatives 21,011 (32,008) (53,727) Total revenues $ 1,662,981 $ 862,126 $ 983,670 Year Ended December 31, 2021 2020 2019 Oil revenues $ 1,205,608 $ 595,507 $ 759,811 Natural gas revenues 494,934 148,954 132,514 Third-party midstream services revenues 75,499 64,932 59,110 Sales of purchased natural gas 86,034 41,742 74,769 Total revenues from contracts with customers $ 1,862,075 $ 851,135 $ 1,026,204 The Company does not disclose the value of unsatisfied performance obligations under its contracts with customers as it applies the practical expedient in accordance with ASC 606. The expedient, as described in ASC 606-10-50-14(a), applies to variable consideration that is recognized as control of the product is transferred to the customer. Since each unit of product represents a separate performance obligation, future volumes are wholly unsatisfied and disclosure of the transaction price allocated to remaining performance obligations is not required. Stock-Based Compensation The Company may grant equity-based and liability-based common stock, stock options, restricted stock, restricted stock units, performance stock units and other awards permitted under any long-term incentive plan of the Company then in effect to members of its Board of Directors and certain employees, contractors and advisors. All equity-based awards are measured at fair value on the date of grant and are recognized on a straight-line basis over the awards’ vesting periods as either a component of general and administrative expenses in the consolidated statements of operations or capitalized in accordance with the Company’s policy on capitalizing general and administrative expenses for employees involved in acquisition, exploration and development activities. Awards that are expected to be settled in cash are liability-based awards, which are measured at fair value at each reporting date and are recognized over the awards’ vesting periods either as a component of general and administrative expenses in the consolidated statements of operations or capitalized in accordance with the Company’s policy on capitalizing general and administrative expenses for employees involved in acquisition, exploration and development activities. The Company uses the Black Scholes Merton option pricing model to measure the fair value of stock options and the Monte Carlo simulation method to measure the fair value of performance units. The closing price of Matador’s common stock on the grant date is used to measure the fair value of restricted stock and restricted stock unit awards granted under the 2012 Long-Term Incentive Plan (as subsequently amended and restated, the “2012 Incentive Plan”), while the closing price of Matador’s common stock on the trading day prior to the grant date is used to measure the fair value of restricted stock and restricted stock unit awards granted under the 2019 Long-Term Incentive Plan (the “2019 Incentive Plan”). The Company’s consolidated statements of operations for the years ended December 31, 2021, 2020 and 2019 include a stock-based compensation (non-cash) expense of $9.0 million, $13.6 million and $18.5 million, respectively. This stock-based compensation expense includes common stock issuances and restricted stock units expense totaling $0.9 million, $1.0 million and $1.4 million for the years ended December 31, 2021, 2020 and 2019, respectively, paid to independent members of the Board of Directors and advisors as compensation for their services to the Company. The Company’s consolidated statement of operations for the years ended December 31, 2021, 2020 and 2019 also includes $20.4 million, $4.0 million and $3.2 million, respectively, related to liability-based awards expected to be settled in cash. Income Taxes The Company accounts for income taxes using the asset and liability approach for financial accounting and reporting. The Company evaluates the probability of realizing the future benefits of its deferred tax assets and records a valuation allowance for the portion of any deferred tax assets when it is more likely than not that the benefit from the deferred tax asset will not be realized. The Company recognizes the tax benefit of an uncertain tax position only if it is more likely than not that the tax position will be sustained upon examination by the taxing authorities based on the technical merits of the position. For tax positions meeting the more likely than not threshold, the amount recognized in the financial statements is the benefit that has a greater than 50% likelihood of being realized upon ultimate settlement with the relevant tax authority. At December 31, 2021, 2020 and 2019, the Company had not established any reserves for, nor recorded any unrecognized tax benefits related to, uncertain tax positions. When necessary, the Company would include interest assessed by taxing authorities in “Interest expense” and penalties related to income taxes in “Other expense” on its consolidated statements of operations. The Company did not record any interest or penalties related to income taxes for the years ended December 31, 2021, 2020 and 2019. Allocation of Purchase Price in Business Combinations As part of the Company’s business strategy, it periodically pursues the acquisition of oil and natural gas properties. The purchase price in a business combination is allocated to the assets acquired and liabilities assumed based on their fair values as of the acquisition date, which may occur many months after the announcement date. Therefore, while the consideration to be paid may be fixed, the fair value of the assets acquired and liabilities assumed is subject to change during the period between the announcement date and the acquisition date. The most significant estimates in the allocation typically relate to the value assigned to proved oil and natural gas reserves and unproved and unevaluated properties. As the allocation of the purchase price is subject to significant estimates and subjective judgments, the accuracy of this assessment is inherently uncertain. Earnings Per Common Share The Company reports basic earnings attributable to Matador Resources Company shareholders per common share, which excludes the effect of potentially dilutive securities, and diluted earnings attributable to Matador Resources Company shareholders per common share, which includes the effect of all potentially dilutive securities, unless their impact is anti-dilutive. The following are reconciliations of the numerators and denominators used to compute the Company’s basic and diluted earnings per common share as reported for the years ended December 31, 2021, 2020 and 2019 (in thousands, except per share data). Year Ended December 31, 2021 2020 2019 Net income (loss) attributable to Matador Resources Company shareholders — numerator $ 584,968 $ (593,205) $ 87,777 Weighted average common shares outstanding — denominator Basic 116,999 116,068 116,555 Dilutive effect of options and restricted stock units 2,164 — 508 Diluted weighted average common shares outstanding 119,163 116,068 117,063 Earnings (loss) per common share attributable to Matador Resources Company shareholders Basic $ 5.00 $ (5.11) $ 0.75 Diluted $ 4.91 $ (5.11) $ 0.75 A total of 2.5 million and 2.6 million options to purchase shares of Matador’s common stock were excluded from the diluted weighted average common shares outstanding for the years ended December 31, 2020 and 2019, respectively, because their effects were anti-dilutive. Additionally, 0.7 million restricted shares, which are participating securities, were excluded from the calculations above for the year ended December 31, 2020 as the security holders do not have the obligation to share in the losses of the Company. Credit Risk The Company’s cash is held in financial institutions and at times these amounts exceed the insurance limits of the Federal Deposit Insurance Corporation. Management believes, however, that the Company’s counterparty risks are minimal based on the reputation and history of the institutions selected. The Company uses derivative financial instruments to mitigate its exposure to oil, natural gas and NGL price volatility. These transactions expose the Company to potential credit risk from its counterparties. The Company manages counterparty credit risk through established internal derivatives policies that are reviewed on an ongoing basis. Additionally, the Company’s commodity derivative contracts at December 31, 2021 were with The Bank of Nova Scotia, BMO Harris Financing, Inc. (Bank of Montreal), PNC Bank and Royal Bank of Canada (or affiliates thereof), and all but BMO Harris Financing, Inc. (Bank of Montreal) were parties that are lenders (or affiliates thereof) under the Company’s reserves-based revolving credit agreement. Accounts receivable constitute the principal component of additional credit risk to which the Company may be exposed. The Company attempts to minimize credit risk exposure to counterparties by monitoring the financial condition and payment history of its purchasers and joint interest partners. |
Property and Equipment
Property and Equipment | 12 Months Ended |
Dec. 31, 2021 | |
Property, Plant and Equipment [Abstract] | |
PROPERTY AND EQUIPMENT | The following table presents a summary of the Company’s property and equipment balances as of December 31, 2021 and 2020 (in thousands). December 31, 2021 2020 Oil and natural gas properties Evaluated (subject to amortization) $ 6,007,325 $ 5,295,931 Unproved and unevaluated (not subject to amortization) 964,714 902,133 Total oil and natural gas properties 6,972,039 6,198,064 Accumulated depletion (3,933,355) (3,623,265) Net oil and natural gas properties 3,038,684 2,574,799 Midstream properties Midstream equipment and facilities 900,979 841,695 Accumulated depreciation (92,574) (61,113) Net midstream properties 808,405 780,582 Other property and equipment Furniture, fixtures and other equipment 10,923 10,591 Software 8,225 8,116 Leasehold improvements 10,975 10,854 Total other property and equipment 30,123 29,561 Accumulated depreciation (20,527) (17,173) Net other property and equipment 9,596 12,388 Net property and equipment $ 3,856,685 $ 3,367,769 The following table provides a breakdown of the Company’s unproved and unevaluated property costs not subject to amortization as of December 31, 2021 and the year in which these costs were incurred (in thousands). Description 2021 2020 2019 2018 2017 and prior Total Costs incurred for Property acquisition $ 111,120 $ 40,355 $ 40,140 $ 417,114 $ 287,666 $ 896,395 Exploration wells 14,738 411 1,199 123 274 16,745 Development wells 46,232 2,027 3,245 60 10 51,574 Total $ 172,090 $ 42,793 $ 44,584 $ 417,297 $ 287,950 $ 964,714 Property acquisition costs are costs incurred to purchase, lease or otherwise acquire oil and natural gas properties, but may also include broker and legal expenses, geological and geophysical expenses and capitalized internal costs associated with developing oil and natural gas prospects on these properties. Property acquisition costs are transferred into the amortization base on an ongoing basis as these properties are evaluated and proved reserves are established or impairment is determined. Unproved and unevaluated properties are assessed for possible impairment on a periodic basis based upon changes in operating or economic conditions. Property acquisition costs incurred that remain in unproved and unevaluated property at December 31, 2021 are related to the Company’s leasehold and mineral acquisitions in the Delaware Basin in Southeast New Mexico and West Texas. These costs are associated with acreage for which proved reserves have yet to be assigned. A significant portion of these costs are associated with properties that are held by production or have automatic lease renewal options. As the Company drills wells and assigns proved reserves to these properties or determines that certain portions of this acreage, if any, cannot be assigned proved reserves, portions of these costs are transferred to the amortization base. Costs excluded from amortization also include those costs associated with exploration and development wells in progress or awaiting completion at year-end. These costs are transferred into the amortization base on an ongoing basis as these wells are completed and proved reserves are established or confirmed. These costs totaled $68.3 million at December 31, 2021. Of this total, $16.7 million was associated with exploration wells and $51.6 million was associated with development wells. The |
Leases
Leases | 12 Months Ended |
Dec. 31, 2021 | |
Leases [Abstract] | |
Leases | LEASES The Company determines if an arrangement is a lease at inception of the contract. If an arrangement is a lease, the present value of the related lease payments is recorded as a liability, and an equal amount is capitalized as a right of use asset on the Company’s consolidated balance sheets. The Company elected to include payments for non-lease components associated with certain leases when determining the present value of the lease payments. Right of use assets represent the Company’s right to use an underlying asset for the lease term and lease liabilities represent the Company’s obligation to make lease payments arising from the lease. The Company’s estimated incremental borrowing rate, determined at the lease commencement date using the Company’s average secured borrowing rate, is used to calculate present value. The weighted average estimated incremental borrowing rates used for the year ended December 31, 2021 were 2.73% and 1.99% for operating leases and financing leases, respectively. For these purposes, the lease term includes options to extend the lease when it is reasonably certain that the Company will exercise such option. Leases with terms of 12 months or less at inception are not recorded on the consolidated balance sheets unless there is a significant cost to terminate the lease, including the cost of removal of the leased asset. As the Company is the responsible party under these arrangements, the Company records the resulting assets and liabilities on a gross basis in its consolidated balance sheets. The following table presents supplemental consolidated statement of operations information related to lease expenses, on a gross basis, for the years ended December 31, 2021 and 2020, respectively (in thousands). Lease payments represent gross payments to vendors, which, for certain of the Company’s operating assets, are partially offset by amounts received from other working interest owners in the Company’s operated wells. Year Ended December 31, 2021 2020 Operating leases Lease operating $ 11,393 $ 12,994 Plant and other midstream services 36 28 General and administrative 3,645 3,698 Total operating leases (1) 15,074 16,720 Short-term leases Lease operating 11,234 12,890 Plant and other midstream services 4,037 5,689 General and administrative 37 47 Total short-term leases (2)(3) 15,308 18,626 Financing leases Depreciation of assets 566 747 Interest on lease liabilities 138 123 Total financing leases 704 870 Total lease expense $ 31,086 $ 36,216 _____________________ (1) Does not include gross payments related to drilling rig leases of $31.9 million and $33.6 million for the years ended December 31, 2021 and 2020, respectively, that were capitalized and recorded in “Oil and natural gas properties, full-cost method” in the consolidated balance sheets at December 31, 2021 and 2020, respectively. (2) These costs are related to leases that are not recorded as right of use assets or lease liabilities in the consolidated balance sheets as they are short-term leases. (3) Does not include gross payments related to short-term drilling rig leases and other equipment rentals of $61.7 million and $65.3 million for the years ended December 31, 2021 and 2020, respectively, that were capitalized and recorded in “Oil and natural gas properties, full-cost method” in the consolidated balance sheets at December 31, 2021 and 2020, respectively. The following table presents supplemental consolidated balance sheet information related to leases as of December 31, 2021 and 2020, respectively (in thousands). December 31, 2021 2020 Operating leases Other long-term assets $ 29,519 $ 51,528 Other current liabilities $ (19,649) $ (35,716) Other long-term liabilities (15,340) (21,598) Total operating lease liabilities $ (34,989) $ (57,314) Financing leases Other property and equipment, at cost $ 5,914 $ 3,673 Accumulated depreciation (3,485) (2,134) Net property and equipment $ 2,429 $ 1,539 Other current liabilities $ (378) $ (621) Other long-term liabilities (45) (256) Total financing lease liabilities $ (423) $ (877) The following table presents supplemental consolidated cash flow information related to lease payments for the year ended December 31, 2021 and 2020, respectively (in thousands). Year Ended December 31, 2021 2020 Cash paid related to lease liabilities Operating cash payments for operating leases $ 14,430 $ 15,664 Investing cash payments for operating leases $ 31,967 $ 33,556 Financing cash payments for financing leases $ 629 $ 790 Right of use assets obtained in exchange for lease obligations entered into during the period Operating leases $ 18,454 $ 12,474 Financing leases $ 2,241 $ 996 The following table presents the maturities of lease liabilities at December 31, 2021 (in years). Weighted-Average Remaining Lease Term December 31, 2021 Operating leases 2.5 Financing leases 1.7 The following table presents a schedule of future minimum lease payments required under all lease agreements as of December 31, 2021 (in thousands). December 31, 2021 Operating Leases Financing Leases 2022 $ 19,649 $ 378 2023 6,830 180 2024 4,217 37 2025 4,287 — 2026 1,553 — Thereafter — — Total lease payments 36,536 595 Less imputed interest (1,547) (172) Total lease obligations 34,989 423 Less current obligations (19,649) (378) Long-term lease obligations $ 15,340 $ 45 |
Leases | LEASES The Company determines if an arrangement is a lease at inception of the contract. If an arrangement is a lease, the present value of the related lease payments is recorded as a liability, and an equal amount is capitalized as a right of use asset on the Company’s consolidated balance sheets. The Company elected to include payments for non-lease components associated with certain leases when determining the present value of the lease payments. Right of use assets represent the Company’s right to use an underlying asset for the lease term and lease liabilities represent the Company’s obligation to make lease payments arising from the lease. The Company’s estimated incremental borrowing rate, determined at the lease commencement date using the Company’s average secured borrowing rate, is used to calculate present value. The weighted average estimated incremental borrowing rates used for the year ended December 31, 2021 were 2.73% and 1.99% for operating leases and financing leases, respectively. For these purposes, the lease term includes options to extend the lease when it is reasonably certain that the Company will exercise such option. Leases with terms of 12 months or less at inception are not recorded on the consolidated balance sheets unless there is a significant cost to terminate the lease, including the cost of removal of the leased asset. As the Company is the responsible party under these arrangements, the Company records the resulting assets and liabilities on a gross basis in its consolidated balance sheets. The following table presents supplemental consolidated statement of operations information related to lease expenses, on a gross basis, for the years ended December 31, 2021 and 2020, respectively (in thousands). Lease payments represent gross payments to vendors, which, for certain of the Company’s operating assets, are partially offset by amounts received from other working interest owners in the Company’s operated wells. Year Ended December 31, 2021 2020 Operating leases Lease operating $ 11,393 $ 12,994 Plant and other midstream services 36 28 General and administrative 3,645 3,698 Total operating leases (1) 15,074 16,720 Short-term leases Lease operating 11,234 12,890 Plant and other midstream services 4,037 5,689 General and administrative 37 47 Total short-term leases (2)(3) 15,308 18,626 Financing leases Depreciation of assets 566 747 Interest on lease liabilities 138 123 Total financing leases 704 870 Total lease expense $ 31,086 $ 36,216 _____________________ (1) Does not include gross payments related to drilling rig leases of $31.9 million and $33.6 million for the years ended December 31, 2021 and 2020, respectively, that were capitalized and recorded in “Oil and natural gas properties, full-cost method” in the consolidated balance sheets at December 31, 2021 and 2020, respectively. (2) These costs are related to leases that are not recorded as right of use assets or lease liabilities in the consolidated balance sheets as they are short-term leases. (3) Does not include gross payments related to short-term drilling rig leases and other equipment rentals of $61.7 million and $65.3 million for the years ended December 31, 2021 and 2020, respectively, that were capitalized and recorded in “Oil and natural gas properties, full-cost method” in the consolidated balance sheets at December 31, 2021 and 2020, respectively. The following table presents supplemental consolidated balance sheet information related to leases as of December 31, 2021 and 2020, respectively (in thousands). December 31, 2021 2020 Operating leases Other long-term assets $ 29,519 $ 51,528 Other current liabilities $ (19,649) $ (35,716) Other long-term liabilities (15,340) (21,598) Total operating lease liabilities $ (34,989) $ (57,314) Financing leases Other property and equipment, at cost $ 5,914 $ 3,673 Accumulated depreciation (3,485) (2,134) Net property and equipment $ 2,429 $ 1,539 Other current liabilities $ (378) $ (621) Other long-term liabilities (45) (256) Total financing lease liabilities $ (423) $ (877) The following table presents supplemental consolidated cash flow information related to lease payments for the year ended December 31, 2021 and 2020, respectively (in thousands). Year Ended December 31, 2021 2020 Cash paid related to lease liabilities Operating cash payments for operating leases $ 14,430 $ 15,664 Investing cash payments for operating leases $ 31,967 $ 33,556 Financing cash payments for financing leases $ 629 $ 790 Right of use assets obtained in exchange for lease obligations entered into during the period Operating leases $ 18,454 $ 12,474 Financing leases $ 2,241 $ 996 The following table presents the maturities of lease liabilities at December 31, 2021 (in years). Weighted-Average Remaining Lease Term December 31, 2021 Operating leases 2.5 Financing leases 1.7 The following table presents a schedule of future minimum lease payments required under all lease agreements as of December 31, 2021 (in thousands). December 31, 2021 Operating Leases Financing Leases 2022 $ 19,649 $ 378 2023 6,830 180 2024 4,217 37 2025 4,287 — 2026 1,553 — Thereafter — — Total lease payments 36,536 595 Less imputed interest (1,547) (172) Total lease obligations 34,989 423 Less current obligations (19,649) (378) Long-term lease obligations $ 15,340 $ 45 |
Asset Retirement Obligations
Asset Retirement Obligations | 12 Months Ended |
Dec. 31, 2021 | |
Asset Retirement Obligation Disclosure [Abstract] | |
ASSET RETIREMENT OBLIGATIONS | ASSET RETIREMENT OBLIGATIONS The Company’s asset retirement obligations primarily relate to future costs associated with plugging and abandonment of its oil, natural gas and salt water disposal wells, removal of pipelines, equipment and facilities from leased acreage and returning such land to its original condition. The amounts recognized are based on numerous estimates and assumptions, including future retirement costs, future recoverable quantities of oil and natural gas, future inflation rates and the Company’s credit-adjusted risk-free interest rate. Revisions to the liability can occur due to changes in these estimates and assumptions or if federal or state regulators enact new plugging and abandonment requirements. At the time of the actual plugging and abandonment of its oil and natural gas wells, the Company includes any gain or loss associated with the operation in the amortization base to the extent the actual costs are different from the estimated liability. The following table summarizes the changes in the Company’s asset retirement obligations for the years ended December 31, 2021 and 2020 (in thousands). Year Ended December 31, 2021 2020 Beginning asset retirement obligations $ 38,542 $ 36,211 Liabilities incurred during period 2,294 2,548 Liabilities settled during period (151) (290) Revisions in estimated cash flows 86 (1,875) Divestitures during the period (880) — Accretion expense 2,068 1,948 Ending asset retirement obligations 41,959 38,542 Less: current asset retirement obligations (1) (270) (623) Long-term asset retirement obligations $ 41,689 $ 37,919 __________________ (1) Included in “Accrued liabilities” in the Company’s consolidated balance sheets at December 31, 2021 and 2020. |
Business Combinations and Dives
Business Combinations and Divestitures | 12 Months Ended |
Dec. 31, 2021 | |
Business Combinations [Abstract] | |
BUSINESS COMBINATIONS AND DIVESTITURES | Business Combination On December 14, 2021, the Company completed an acquisition of assets from a private operator. This acquisition was accounted for as a business combination in accordance with ASC Topic 805, which requires the assets acquired and liabilities assumed to be recorded at fair value as of the respective acquisition date. The Company obtained certain oil and natural gas producing properties and undeveloped acreage located in Lea and Eddy Counties, New Mexico, strategically located primarily within the Company’s existing acreage in its Ranger and Arrowhead asset areas. As consideration for the business combination, the Company paid approximately $161.7 million in cash and will pay an additional $6.5 million, net of customary working capital adjustments, including adjusting for production, revenues, operating expenses and capital expenditures from August 1, 2021 to closing. In addition, the Company will increase the purchase price by $5.0 million for each quarter during 2022 in which the average oil price, as defined in the purchase and sale agreement, is greater than $75.00 per barrel. The Company recorded this contingent consideration at fair value on the date of the business combination and will record the change in the fair value in future periods as “Other income (expense)” in its consolidated statements of operations. The fair value of the contingent consideration increased between December 14, 2021 and December 31, 2021 by $1.5 million, which was recorded as “Other expense” for the year ended December 31, 2021. The Company used the Monte Carlo simulation method to measure the fair value of the contingent consideration, which has unobservable inputs and is thus classified at Level 3 in the fair value hierarchy (see Note 13 for discussion of the fair value hierarchy). In addition, the Company acquired oil and natural gas production of approximately 3,500 BOE per day at the date of acquisition, which increased the Company’s revenues and net income for the period from December 15, 2021 through December 31, 2021 by $4.0 million and $3.2 million, respectively. The pro forma impact of this business combination to revenues and net income for the remainder of 2021 would not be material to the Company’s 2021 revenues and net income as reported. The preliminary allocation of the consideration given related to this business combination was as follows (in thousands). The Company anticipates that the allocation of the consideration given should be finalized during 2022 upon determination of the final customary purchase price adjustments. Consideration given Allocation Cash $161,680 Working capital adjustments to be paid in 2022 6,500 Fair value of contingent consideration at December 14, 2021 6,718 Total consideration given $174,898 Allocation of purchase price Oil and natural gas properties Evaluated $139,312 Unproved and unevaluated 43,204 Accrued liabilities (360) Advances from joint interest owners (6,865) Asset retirement obligations (393) Net assets acquired $174,898 Joint Ventures At December 31, 2021, the Company owned 51% of San Mateo, a midstream joint venture with a subsidiary of Five Point Energy LLC (“Five Point”) in portions of Eddy County, New Mexico and Loving County, Texas. At December 31, 2021, Five Point owned the remaining 49% of San Mateo. The midstream assets include (i) the Black River Processing Plant, (ii) 14 salt water disposal wells and associated commercial salt water disposal facilities and (iii) approximately 370 miles of oil gathering and transportation pipelines, natural gas gathering pipelines and produced water pipelines. The Company operates San Mateo, and San Mateo is consolidated in the Company’s financial statements, with Five Point’s interest being accounted for as a non-controlling interest. As part of the joint venture agreement with Five Point, the Company had the potential to earn two different sets of performance incentives. These performance incentives are recorded as additional contributions related to the formation of San Mateo as they are received. Beginning in 2017, the Company had the potential to earn up to $73.5 million in performance incentives related to the Company’s performance in its Rustler Breaks asset area in Eddy County and its Wolf asset area in Loving County over a five-year period, which in October 2020 was extended by an additional year to January 31, 2023. At December 31, 2021, the Company had earned $58.8 million of the potential $73.5 million in performance incentives and Five Point had paid $14.7 million in performance incentives in each of the first quarters of 2018, 2019, 2020 and 2021. The Company may earn up to the remaining $14.7 million in performance incentives until January 31, 2023. Beginning in 2019, the Company had the potential to earn up to $150.0 million in additional deferred performance incentives in its Stebbins area and surrounding leaseholds in the southern portion of its Arrowhead asset area (the “Greater Stebbins Area”) and Stateline asset area over the next several years, plus additional performance incentives for securing volumes from third-party customers. During the year ended December 31, 2021, Five Point paid $33.9 million in these additional performance incentives. The Company dedicated to San Mateo its current and certain future leasehold interests in the Rustler Breaks and Wolf asset areas and acreage in the Greater Stebbins Area and Stateline asset area pursuant to 15-year, fixed-fee oil transportation, oil, natural gas and produced water gathering and produced water disposal agreements. In addition, the Company dedicated to San Mateo its current and certain future leasehold interests in the Rustler Breaks asset area and acreage in the Greater Stebbins Area and the Stateline asset area pursuant to 15-year, fixed-fee natural gas processing agreements (see Note 14). During the years ended December 31, 2021 and 2020, San Mateo distributed $64.5 million and $47.4 million, respectively, to the Company and $62.0 million and $45.6 million, respectively, to Five Point. During the year ended December 31, 2021, neither the Company nor Five Point contributed cash to San Mateo. During the year ended December 31, 2020, the Company contributed $75.0 million and Five Point contributed $119.7 million of cash to San Mateo, of which $23.1 million was paid to carry Matador’s proportionate interest in San Mateo Midstream II, LLC (“San Mateo II”). Five Point agreed to carry a portion of Matador’s proportionate interest as part of the formation agreement for San Mateo II. The amount that Five Point paid to carry Matador’s proportionate interest in San Mateo was recorded in “Additional paid-in capital” in the Company’s consolidated balance sheets at December 31, 2020, net of the $4.8 million deferred tax impact to Matador related to this equity contribution. During the year ended December 31, 2019, the Company contributed $24.2 million and Five Point contributed $77.3 million of cash to San Mateo, of which $28.4 million was paid to carry Matador’s proportionate interest in San Mateo II and was recorded in “Additional paid-in capital” in the consolidated balance sheet, net of the $5.9 million deferred tax impact to Matador related to this equity contribution. In the first quarter of 2019, the Company also contributed $1.0 million of property to San Mateo II. San Mateo II was merged with and into San Mateo effective October 1, 2020. Divestitures During 2021 and 2020, the Company converted approximately $4.2 million and $4.8 million, respectively, of non-core assets to cash. These properties were primarily located in South Texas and Northwest Louisiana. |
Debt
Debt | 12 Months Ended |
Dec. 31, 2021 | |
Debt Disclosure [Abstract] | |
DEBT | DEBT At December 31, 2021, the Company had (i) $1.05 billion of outstanding senior notes due 2026, (ii) $100.0 million in borrowings outstanding under its reserves-based revolving credit facility, (iii) approximately $45.8 million in outstanding letters of credit issued pursuant to its revolving credit facility and (iv) $7.5 million outstanding under an unsecured U.S. Small Business Administration loan. At December 31, 2021, San Mateo had $385.0 million in borrowings outstanding under its revolving credit facility and approximately $9.0 million in outstanding letters of credit issued pursuant to its revolving credit facility. Credit Agreements MRC Energy Company On November 18, 2021, the Company entered into its Fourth Amended and Restated credit facility with the lenders party thereto, led by Royal Bank of Canada (“RBC”) as administrative agent (the “Credit Agreement”). MRC Energy Company (“MRC”), a subsidiary of Matador that directly or indirectly holds the ownership interests in the Company’s other operating subsidiaries, other than its less-than-wholly-owned subsidiaries, is the borrower under the Credit Agreement. Borrowings are secured by mortgages on at least 85% of MRC’s and the Restricted Subsidiaries’ (as defined in the Credit Agreement) proved oil and natural gas properties and by the equity interests of certain of MRC’s wholly-owned subsidiaries, which are also guarantors. San Mateo and its subsidiaries are not guarantors of the Credit Agreement. In addition, all obligations under the Credit Agreement are guaranteed by Matador, the parent corporation. Various commodity hedging agreements with certain of the lenders under the Credit Agreement (or affiliates thereof) are also secured by the collateral of and guaranteed by certain eligible subsidiaries of MRC. The Credit Agreement matures on October 31, 2026 or, if earlier, the date that is 180 days prior to the earliest stated redemption date of any senior notes of the Company with an outstanding principal balance in excess of $25.0 million. The borrowing base under the Credit Agreement is determined semi-annually as of May 1 and November 1 by the lenders based primarily on the estimated value of the Company’s proved oil and natural gas reserves at December 31 and June 30 of each year, respectively. The Company and the lenders may each request an unscheduled redetermination of the borrowing base once between scheduled redetermination dates. In November 2021, the lenders completed their review of the Company’s proved oil and natural gas reserves, and, as a result, the borrowing base was increased from $900.0 million to $1.35 billion. The Company elected to keep the borrowing commitment at $700.0 million, and the maximum facility amount remained $1.5 billion. Borrowings under the Credit Agreement are limited to the lowest of the borrowing base, the maximum facility amount and the elected borrowing commitment (subject to compliance with the covenants noted below). In the event of an increase in the elected commitment, the Company is required to pay a fee to the lenders equal to a percentage of the amount of the increase, which is determined based on market conditions at the time of the increase. If, upon a redetermination of the borrowing base, the borrowing base were to be less than the outstanding borrowings under the Credit Agreement at such time, the Company would be required to provide additional collateral satisfactory in nature and value to the lenders to increase the borrowing base to an amount sufficient to cover such excess or to repay the deficit in equal installments over a period of six months. Total deferred loan costs were $3.9 million at December 31, 2021, and these costs are being amortized over the term of the Credit Agreement. The Company’s effective interest rate under the Credit Agreement was 1.85% at December 31, 2021. At December 31, 2021, the Company had $100.0 million in borrowings outstanding under the Credit Agreement and approximately $45.8 million in outstanding letters of credit issued pursuant to the Credit Agreement. Between December 31, 2021 and February 28, 2022, the Company repaid $25.0 million of borrowings outstanding under the Credit Agreement. Borrowings under the Credit Agreement may be in the form of a base rate loan or a Eurodollar loan. If MRC borrows funds as a base rate loan, such borrowings will bear interest at a rate equal to the greatest of (i) the prime rate for such day, (ii) the Federal Funds Effective Rate (as defined in the Credit Agreement) on such day, plus 0.50%, and (iii) the daily adjusting LIBOR rate (as defined in the Credit Agreement) plus 1.0% plus, in each case, an amount ranging from 0.75% to 1.75% per annum depending on the level of borrowings under the Credit Agreement. If MRC borrows funds as a Eurodollar loan, such borrowings will bear interest at a rate equal to (x) the LIBOR Rate (as defined in the Credit Agreement) plus (y) an amount ranging from 1.75% to 2.75% per annum depending on the level of borrowings under the Credit Agreement. The interest period for Eurodollar borrowings may be one, three or six months as designated by MRC. If MRC has outstanding borrowings under the Credit Agreement and interest rates increase, so will MRC’s interest costs, which may have a material adverse effect on the Company’s results of operations and financial condition. A commitment fee of 0.375% to 0.50% per annum, depending on the level of borrowings under the Credit Agreement, is also paid quarterly in arrears. The Company includes this commitment fee, any amortization of deferred financing costs (including origination, borrowing base increase and amendment fees) and annual agency fees, if any, as interest expense and in its interest rate calculations and related disclosures. The Credit Agreement requires the Company to maintain (i) a current ratio, which is defined as (x) total consolidated current assets plus the unused availability under the Credit Agreement divided by (y) total consolidated current liabilities less current maturities under the Credit Agreement, of not less than 1.0 to 1.0 at the end of each fiscal quarter and (ii) a debt to EBITDA ratio, which is defined as debt outstanding (net of up to $75 million of cash or cash equivalents) divided by a rolling four quarter EBITDA calculation, of 3.50 to 1.0 or less. Subject to certain exceptions, the Credit Agreement contains various covenants that limit MRC’s and its Restricted Subsidiaries’ (as defined in the Credit Agreement) ability to take certain actions, including, but not limited to, the following: • incur indebtedness or grant liens on any of its assets; • enter into commodity hedging agreements or interest rate agreements; • declare or pay dividends, distributions or redemptions; • merge or consolidate; • make any loans or investments; • engage in transactions with affiliates; • engage in certain asset dispositions, including a sale of all or substantially all of MRC’s assets; and • take certain actions with respect to the Company’s senior unsecured notes. If an event of default exists under the Credit Agreement, the lenders will be able to accelerate the maturity of the borrowings and exercise other rights and remedies. Events of default include, but are not limited to, the following events: • failure to pay any principal on the outstanding borrowings when due or any interest on the outstanding borrowings, any reimbursement obligation under any letter of credit or any fees or other amounts within certain grace periods; • failure to perform or otherwise comply with the covenants and obligations in the Credit Agreement or other loan documents, subject, in certain instances, to certain grace periods; • bankruptcy or insolvency events involving the Company or any of the Restricted Subsidiaries; and • a change of control, as defined in the Credit Agreement. The Company believes that it was in compliance with the terms of the Credit Agreement at December 31, 2021. San Mateo Midstream, LLC On December 19, 2018, San Mateo entered into a $250.0 million credit facility with the lenders party thereto, currently led by Truist Bank as administrative agent (the “San Mateo Credit Facility”). The San Mateo Credit Facility matures December 19, 2023 and was amended in June 2021 to increase the lender commitments under the revolving credit facility from $375.0 million to $450.0 million (subject to San Mateo’s compliance with the covenants noted below) and to increase the borrowing rate for a base rate loan or a Eurodollar loan under such facility by 0.50%. The San Mateo Credit Facility includes an accordion feature, which, after the aforementioned amendment, provides for potential increases in lender commitments to up to $700.0 million. The San Mateo Credit Facility is non-recourse with respect to Matador and its wholly-owned subsidiaries, but is guaranteed by San Mateo’s subsidiaries and secured by substantially all of San Mateo’s assets, including real property. Total deferred loan costs were $1.9 million at December 31, 2021, and these costs are being amortized over the term of the San Mateo Credit Facility. San Mateo’s effective interest rate under the San Mateo Credit Facility was 2.11% at December 31, 2021. At December 31, 2021, San Mateo had $385.0 million in borrowings outstanding under the San Mateo Credit Facility and $9.0 million in outstanding letters of credit issued pursuant to the San Mateo Credit Facility. Between December 31, 2021 and February 22, 2022, San Mateo repaid $30.0 million of borrowings outstanding under the San Mateo Credit Facility. Borrowings under the San Mateo Credit Facility may be in the form of a base rate loan or a Eurodollar loan. If San Mateo borrows funds as a base rate loan, such borrowings will bear interest at a rate equal to the greatest of (i) the prime rate for such day, (ii) the Federal Funds Effective Rate (as defined in the San Mateo Credit Facility) on such day, plus 0.50%, and (iii) the Adjusted LIBO Rate (as defined in the San Mateo Credit Facility) plus 1.0% plus, in each case, an amount ranging from 1.00% to 2.00% per annum depending on San Mateo’s Consolidated Total Leverage Ratio (as defined in the San Mateo Credit Facility). If San Mateo borrows funds as a Eurodollar loan, such borrowings will bear interest at a rate equal to (x) the Adjusted LIBO Rate for the chosen interest period plus (y) an amount ranging from 2.00% to 3.00% per annum depending on San Mateo’s Consolidated Total Leverage Ratio. If San Mateo has outstanding borrowings under the San Mateo Credit Facility and interest rates increase, so will San Mateo’s interest costs, which may have a material adverse effect on San Mateo’s results of operations and financial condition. A commitment fee of 0.30% to 0.50% per annum, depending on the unused availability under the San Mateo Credit Facility, is also paid quarterly in arrears. The Company includes this commitment fee, any amortization of deferred financing costs (including origination and amendment fees) and annual agency fees, if any, as interest expense and in its interest rate calculations and related disclosures. The San Mateo Credit Facility requires San Mateo to maintain a debt to EBITDA ratio, which is defined as total consolidated funded indebtedness outstanding (as defined in the San Mateo Credit Facility) divided by a rolling four quarter EBITDA calculation, of 5.00 or less, subject to certain exceptions. The San Mateo Credit Facility also requires San Mateo to maintain an interest coverage ratio, which is defined as a rolling four quarter EBITDA calculation divided by San Mateo’s consolidated interest expense, of 2.50 or more. The San Mateo Credit Facility also restricts the ability of San Mateo to distribute cash to its members if San Mateo’s liquidity is less than 10% of the lender commitments under the San Mateo Credit Facility. Subject to certain exceptions, the San Mateo Credit Facility contains various covenants that limit San Mateo’s and its restricted subsidiaries’ ability to take certain actions, including, but not limited to, the following: • incur indebtedness or grant liens on any of San Mateo’s assets; • enter into hedging agreements; • declare or pay dividends, distributions or redemptions; • merge or consolidate; • make any loans or investments; • engage in transactions with affiliates; • engage in certain asset dispositions, including a sale of all or substantially all of San Mateo’s assets; and • issue equity interests in San Mateo or its subsidiaries. If an event of default exists under the San Mateo Credit Facility, the lenders will be able to accelerate the maturity of the borrowings and exercise other rights and remedies. Events of default include, but are not limited to, the following events: • failure to pay any principal or interest on the outstanding borrowings or any reimbursement obligation under any letter of credit when due or any fees or other amounts within certain grace periods; • failure to perform or otherwise comply with the covenants and obligations in the San Mateo Credit Facility or other loan documents, subject, in certain instances, to certain grace periods; • bankruptcy or insolvency events involving San Mateo or its subsidiaries; and • a change of control, as defined in the San Mateo Credit Facility. The Company believes that San Mateo was in compliance with the terms of the San Mateo Credit Facility at December 31, 2021. Senior Unsecured Notes At December 31, 2021, the Company had $1.05 billion of outstanding 5.875% senior notes due 2026 that were registered under the Securities Act and mature September 15, 2026 (the “Notes”). Interest is payable on the Notes semi-annually in arrears on each March 15 and September 15. The Notes are guaranteed on a senior unsecured basis by certain subsidiaries of the Company (the “Guarantors”). San Mateo and its subsidiaries are not Restricted Subsidiaries (as defined in the Indenture) or Guarantors of the Notes. The Company may redeem all or a part of the Notes at any time or from time to time at the following redemption prices (expressed as percentages of principal amount) plus accrued and unpaid interest, if any, to the applicable redemption date, if redeemed during the twelve-month period beginning on September 15 of the years indicated below: Year Redemption Price 2021 104.406% 2022 102.938% 2023 101.469% 2024 and thereafter 100.000% Subject to certain exceptions, the Indenture contains various covenants that limit the Company’s ability to take certain actions, including, but not limited to, the following: • incur additional indebtedness; • sell assets; • pay dividends or make certain investments; • create liens that secure indebtedness; • enter into transactions with affiliates; and • merge or consolidate with another company. In the case of an event of default arising from certain events of bankruptcy or insolvency with respect to Matador, any Restricted Subsidiary (as defined in the Indenture) that is a Significant Subsidiary (as defined in the Indenture) or any group of Restricted Subsidiaries that, taken together, would constitute a Significant Subsidiary, all outstanding Notes will become due and payable immediately without further action or notice. If any other event of default occurs and is continuing, the trustee or the holders of at least 25% in principal amount of the then outstanding Notes may declare all the Notes to be due and payable immediately. Events of default include, but are not limited to, the following events: • default for 30 days in the payment when due of interest on the Notes; • default in the payment when due of the principal of, or premium, if any, on the Notes; • failure by the Company to comply with its obligations to offer to purchase or purchase Notes pursuant to the change of control or asset sale covenants of the Indenture or to comply with the covenant relating to mergers; • failure by the Company for 180 days after notice to comply with its reporting obligations under the Indenture; • failure by the Company for 60 days after notice to comply with any of the other agreements in the Indenture; • payment defaults and accelerations with respect to other indebtedness of the Company and its Restricted Subsidiaries in the aggregate principal amount of $50.0 million or more; • failure by the Company or any Restricted Subsidiary to pay certain final judgments aggregating in excess of $50.0 million within 60 days; • any subsidiary guarantee by a Guarantor ceases to be in full force and effect, is declared null and void in a judicial proceeding or is denied or disaffirmed by its maker; and • certain events of bankruptcy or insolvency with respect to the Company or any Restricted Subsidiary that is a Significant Subsidiary or any group of Restricted Subsidiaries that, taken together, would constitute a Significant Subsidiary. |
Income Taxes
Income Taxes | 12 Months Ended |
Dec. 31, 2021 | |
Income Tax Disclosure [Abstract] | |
INCOME TAXES | Deferred tax assets and liabilities are the result of temporary differences between the financial statement carrying values and the tax bases of assets and liabilities. The Company’s net deferred tax position as of December 31, 2021 and 2020 is as follows (in thousands). December 31, 2021 2020 Deferred tax assets Net operating loss carryforwards $ 129,651 $ 122,952 Unrealized loss on derivatives 3,729 8,997 Percentage depletion carryover 1,770 1,462 Compensation 9,838 10,405 Lease liabilities 4,866 9,380 Other 9,410 8,334 Total deferred tax assets 159,264 161,530 Valuation allowance on deferred tax assets (10,599) (110,681) Total deferred tax assets, net of valuation allowance 148,665 50,849 Deferred tax liabilities Property and equipment (179,153) (11,879) Less than wholly-owned subsidiaries (39,900) (26,564) Lease right of use assets (4,866) (9,380) Other (2,684) (2,684) Total deferred tax liabilities (226,603) (50,507) Net deferred tax (liabilities) assets $ (77,938) $ 342 At December 31, 2021, the Company had net operating loss carryforwards of $555.2 million for federal income tax purposes and $223.3 million for state income tax purposes available to offset future taxable income, as limited by the applicable provisions, and which expire at various dates beginning in 2027 for the federal net operating loss carryforwards. The state net operating loss carryforwards begin expiring at various dates beginning in 2024; however, the significant portion of the Company’s state net operating loss carryforwards expire beginning in 2027. At December 31, 2020, the Company’s deferred tax assets exceeded its deferred tax liabilities due to the deferred tax assets generated by impairment charges recorded in 2020. As a result, the Company established a valuation allowance against most of the deferred tax assets beginning in the third quarter of 2020. The remaining net deferred tax asset at December 31, 2020 relates to state taxes, for which the deferred taxes were determined to be more likely than not to be utilized. Due to a variety of factors, including the Company’s significant net income in 2021, the Company’s federal valuation allowance was reversed as of September 30, 2021 as the deferred tax assets were determined to be more likely than not to be utilized. As a portion of the Company’s state net operating loss carryforwards are not expected to be utilized before expiration, a valuation allowance will continue to be recognized until the state deferred tax assets are more likely than not to be utilized. The current income tax provision and the deferred income tax provision for the years ended December 31, 2021, 2020 and 2019 were comprised of the following (in thousands). Year Ended December 31, 2021 2020 2019 Deferred income tax provision (benefit) Federal income tax $ 44,883 $ (25,675) $ 29,171 State income tax 29,827 (19,924) 6,361 Net deferred income tax provision (benefit) $ 74,710 $ (45,599) $ 35,532 Reconciliations of the tax expense (benefit) computed at the statutory federal rate to the Company’s total income tax provision (benefit) for the years ended December 31, 2021, 2020 and 2019 is as follows (in thousands). Year Ended December 31, 2021 2020 2019 Federal tax expense (benefit) at statutory rate (1) $ 150,223 $ (125,823) $ 33,441 State income tax 26,646 (20,607) 6,141 Permanent differences (2,078) (3,114) (4,267) Change in federal valuation allowance (103,262) 103,262 — Change in state valuation allowance 3,181 683 217 Net deferred income tax provision (benefit) 74,710 (45,599) 35,532 Total income tax provision (benefit) $ 74,710 $ (45,599) $ 35,532 __________________ (1) The statutory federal tax rate was 21% for the years ended December 31, 2021, 2020 and 2019. The Company files a United States federal income tax return and several state tax returns, a number of which remain open for examination. The earliest tax year open for examination for the federal, the State of New Mexico and the State of Louisiana tax returns is 2018. The earliest tax year open for examination for the State of Texas tax return is 2017. |
Stock-Based Compensation
Stock-Based Compensation | 12 Months Ended |
Dec. 31, 2021 | |
Share-based Payment Arrangement [Abstract] | |
STOCK-BASED COMPENSATION | STOCK-BASED COMPENSATION Stock Options, Restricted Stock, Restricted Stock Units, Stock and Performance Awards In 2012, the Company’s Board of Directors adopted and shareholders approved the 2012 Incentive Plan. The 2012 Incentive Plan provided for a maximum of 8,700,000 shares of common stock in the aggregate that could be issued pursuant to options, restricted stock, stock appreciation rights, restricted stock units or other performance award grants. In 2019, the Company’s Board of Directors adopted and shareholders approved the 2019 Incentive Plan. As of December 31, 2021, the 2019 Incentive Plan provided for a maximum of 1,571,972 shares of common stock in the aggregate that may be issued pursuant to grants of options, restricted stock, stock appreciation rights, restricted stock units or other performance award grants. The persons eligible to receive awards under the 2019 Incentive Plan include employees, directors, contractors or advisors of the Company. The primary purpose of the 2019 Incentive Plan is to attract and retain key employees, directors, contractors or advisors of the Company. With the adoption of the 2019 Incentive Plan, the Company does not expect to make any future awards under the 2012 Incentive Plan, but the 2012 Incentive Plan will remain in place until all awards outstanding under that plan have been settled. The 2012 Incentive Plan and the 2019 Incentive Plan are administered by the independent members of the Board of Directors, who, upon recommendation of the Strategic Planning and Compensation Committee of the Board of Directors, determine the number of options, restricted shares or other awards to be granted, the effective dates, the terms of the grants and the vesting periods. The Company typically uses newly issued shares of common stock to satisfy option exercises or restricted share grants. During the years ended December 31, 2021, 2020 and 2019, the Company granted both equity-based and liability-based awards under the 2019 Incentive Plan. The fair value of equity-based awards is fixed at the grant date, while the fair value of liability-based awards is remeasured at each reporting period. Stock Options Under the 2012 Incentive Plan and the 2019 Incentive Plan, stock option awards have been granted and are outstanding to purchase the Company’s common stock at an exercise price equal to the fair market value on the date of grant, a typical vesting period of three five six The weighted average grant date fair value for stock option awards granted under the 2019 Incentive Plan was estimated using the following weighted average assumptions during the year ended December 31, 2019. The Company did not grant stock option awards during the years ended December 31, 2021 and 2020. 2019 Stock option pricing model Black Scholes Merton Expected option life 4.00 years Risk-free interest rate 1.46% Volatility 48.52% Dividend yield —% Estimated forfeiture rate 4.43% Weighted average fair value of stock option awards granted during the year $5.04 The Company estimated the future volatility of its common stock using the historical value of its stock for a period of time commensurate with the expected term of the stock option. The expected term was estimated using the simplified method outlined in Staff Accounting Bulletin Topic 14. The risk-free interest rate was the rate for constant yield U.S. Treasury securities with a term to maturity that was consistent with the expected term of the award. Summarized information about stock options outstanding at December 31, 2021 under the 2012 Incentive Plan and the 2019 Incentive Plan (collectively, the “LTIPs”) is as follows. Number of options (in thousands) Weighted Options outstanding at December 31, 2020 2,473 $ 23.08 Options granted — $ — Options exercised (1,368) $ 25.37 Options forfeited (37) $ 18.72 Options expired (465) $ 16.90 Options outstanding at December 31, 2021 603 $ 22.92 Options outstanding at Options exercisable at Range of exercise prices Shares outstanding (in thousands) Weighted Weighted Shares exercisable (in thousands) Weighted $14.48 - $15.40 240 3.66 $ 14.80 82 $ 14.80 $26.86 - $29.68 363 1.59 $ 28.28 363 $ 28.28 At December 31, 2021, the aggregate intrinsic value for both outstanding and exercisable options was $4.9 million, based on the closing price of Matador’s common stock on the appropriate date under the LTIPs. The remaining weighted average contractual term of exercisable options at December 31, 2021 was 1.97 years. The total intrinsic value of options exercised during the years ended December 31, 2021, 2020 and 2019 was $15.8 million, $0.3 million and $0.8 million, respectively. The tax related benefit realized from the exercise of stock options totaled $16.8 million, $1.4 million and $2.8 million for the years ended December 31, 2021, 2020 and 2019, respectively. At December 31, 2021, the total remaining unrecognized compensation expense related to unvested stock options was approximately $0.5 million and the weighted average remaining requisite service period (vesting period) of all unvested stock options was 0.66 years. The fair value of options vested during 2021, 2020 and 2019 was $3.0 million, $6.7 million and $9.7 million, respectively. Service-Based Restricted Stock, Restricted Stock Units and Common Stock The Company has granted stock, restricted stock and restricted stock unit awards to employees, consultants, outside directors and advisors of the Company under the LTIPs. The stock and restricted stock are issued upon grant, with the restrictions, if any, being removed upon vesting. The equity-based restricted stock units are issued upon vesting, unless the recipient makes an election to defer issuance for a set term after vesting. Liability-based restricted stock units are settled in cash upon vesting. Restricted stock and restricted stock units granted in 2021, 2020 and 2019 were service-based awards, which will settle in cash or equity, and vest over a one-year to three-year period. Performance-based restricted stock units granted in 2021 and 2020 vest in an amount between zero and 200% of the target units granted based on the Company’s relative total shareholder return over the three-year periods ending December 31, 2023 and 2022, respectively, as compared to a designated peer group, and will be settled in equity. Equity-Based A summary of the non-vested equity-based restricted stock and restricted stock units as of December 31, 2021 is presented below (in thousands, except fair value). Restricted Stock Restricted Stock Units Service Based Service Based Performance Based Non-vested restricted stock and Shares Weighted Shares Weighted Shares Weighted Non-vested at December 31, 2020 682 $ 20.01 75 $ 8.85 1,069 $ 9.05 Granted 283 $ 37.56 36 $ 30.97 366 $ 50.53 Vested (1) (334) $ 27.14 (78) $ 9.02 (397) $ 20.00 Forfeited (42) $ 17.35 — $ — (75) $ 9.33 Non-vested at December 31, 2021 589 $ 24.59 33 $ 33.39 963 $ 20.26 __________________ (1) On December 31, 2021, 396,827 of the performance-based awards that were granted in 2019 vested. The vested units earned 200% for each vested award representing 793,654 aggregate shares of common stock, which were issued on December 31, 2021. Liability-Based A summary of the non-vested liability-based restricted stock units as of December 31, 2021 is presented below (in thousands). Non-vested Shares Non-vested at December 31, 2020 1,319 Granted 357 Vested (487) Forfeited (87) Non-vested at December 31, 2021 1,102 The Company settled 487,252 liability-based awards for $12.4 million and 226,363 liability-based awards for $2.4 million in cash for the years ended December 31, 2021 and 2020, respectively. The Company did not settle any liability awards for the year ended December 31, 2019. At December 31, 2021, the aggregate intrinsic value for the restricted stock and restricted stock units outstanding was $99.2 million, of which $40.7 million is expected to be settled in cash as calculated based on the maximum number of shares of restricted stock units vesting, based on the closing price of Matador’s common stock on the appropriate date under the LTIPs. At December 31, 2021, the total remaining unrecognized compensation expense related to unvested restricted stock and restricted stock units was approximately $50.3 million, of which $24.0 million is expected to be settled in cash, based on the closing price of Matador’s common stock on the appropriate date under the LTIPs. The weighted average remaining requisite service period (vesting period) of all non-vested restricted stock and restricted stock units was 2.0 years. The fair value of restricted stock and restricted stock units vested during 2021, 2020 and 2019 was $51.9 million, $8.4 million and $13.6 million, respectively. Summary During the years ended December 31, 2021, 2020 and 2019, the total expense attributable to stock options was $1.0 million, $3.4 million and $6.4 million, respectively. During the years ended December 31, 2021, 2020 and 2019, the total expense attributable to restricted stock and restricted stock units was $36.3 million, $17.7 million and $20.2 million, respectively. During the years ended December 31, 2021, 2020 and 2019, the Company capitalized $7.2 million, $3.6 million and $5.0 million, respectively, related to stock-based compensation and expensed the remaining $30.0 million, $17.6 million and $21.6 million, respectively. The total tax benefit recognized for all stock-based compensation was $7.9 million, $4.5 million and $5.6 million for the years ended December 31, 2021, 2020 and 2019, respectively. |
Employee Benefit Plans
Employee Benefit Plans | 12 Months Ended |
Dec. 31, 2021 | |
Retirement Benefits [Abstract] | |
EMPLOYEE BENEFIT PLANS | EMPLOYEE BENEFIT PLANS 401(k) Plan All full-time Company employees are eligible to join the Company’s defined contribution retirement plan the first day of the calendar month immediately following their date of employment. Each employee may contribute up to the maximum allowable under the Internal Revenue Code. Each year, the Company makes a contribution to the plan that equals 3% of the employee’s annual compensation, up to the maximum allowable under the Internal Revenue Code, referred to as the Employer’s Safe Harbor Non-Elective Contribution, which totaled $1.6 million, $1.4 million and $1.4 million in 2021, 2020 and 2019, respectively. In addition, each year, the Company may make a discretionary matching contribution, as well as additional contributions. The Company’s discretionary matching contributions totaled $2.1 million, $1.8 million and $1.7 million in 2021, 2020 and 2019, respectively. The Company made no additional contributions in any reporting period presented. |
Equity
Equity | 12 Months Ended |
Dec. 31, 2021 | |
Stockholders' Equity Note [Abstract] | |
EQUITY | EQUITY Common Stock Dividend The Company’s Board of Directors (the “Board”) declared a quarterly cash dividend of $0.025 per share of common stock in each of the first three quarters of 2021 and, in October 2021, the Board amended the Company’s dividend policy to increase the quarterly dividend and declared a quarterly cash dividend of $0.05 per share of common stock. Total cash dividends declared and paid totaled $14.6 million during the year ended December 31, 2021. There were no cash dividends declared or paid prior to 2021. Treasury Stock On October 21, 2021, October 22, 2020 and October 24, 2019, Matador’s Board of Directors canceled all of the shares of treasury stock outstanding as of September 30, 2021, 2020 and 2019, respectively. These shares were restored to the status of authorized but unissued shares of common stock of the Company. The shares of treasury stock outstanding at December 31, 2021, 2020 and 2019 represent forfeitures of non-vested restricted stock awards and forfeitures of fully vested restricted stock awards due to net share settlements with employees. Preferred Stock The Company’s Amended and Restated Certificate of Formation authorizes 2,000,000 shares of preferred stock. Before any such shares are issued, the Board of Directors shall fix and determine the designations, preferences, limitations and relative rights, including voting rights of the shares of each such series. |
Derivative Financial Instrument
Derivative Financial Instruments | 12 Months Ended |
Dec. 31, 2021 | |
Derivative Instruments and Hedging Activities Disclosure [Abstract] | |
DERIVATIVE FINANCIAL INSTRUMENTS | DERIVATIVE FINANCIAL INSTRUMENTSFrom time to time, the Company uses derivative financial instruments to mitigate its exposure to commodity price risk associated with oil, natural gas and NGL prices. The Company records derivative financial instruments on its consolidated balance sheets as either assets or liabilities measured at fair value. The Company has elected not to apply hedge accounting for its existing derivative financial instruments. As a result, the Company recognizes the change in derivative fair value between reporting periods currently in its consolidated statements of operations as an unrealized gain or loss. The fair value of the Company’s derivative financial instruments is determined using industry-standard models that consider various inputs including: (i) quoted forward prices for commodities, (ii) time value of money and (iii) current market and contractual prices for the underlying instruments, as well as other relevant economic measures. The Company has evaluated and considered the credit standings of its counterparties in determining the fair value of its derivative financial instruments. At December 31, 2021, the Company had various costless collar and swap contracts open and in place to mitigate its exposure to oil and natural gas price volatility, each with a specific term (calculation period), notional quantity (volume hedged) and price floor and ceiling for the collars and fixed price for the swaps. At December 31, 2021, each contract was set to expire at varying times during 2022. The Company had no open contracts associated with NGL prices at December 31, 2021. The following is a summary of the Company’s open costless collar contracts for oil and natural gas at December 31, 2021. Notional Quantity (Bbl or MMBtu) Weighted Average Price Floor ($/Bbl or Weighted Average Price Ceiling ($/Bbl or Fair Value of Asset (Liability) (thousands) Commodity Calculation Period Oil 01/01/2022 - 12/31/2022 2,040,000 $ 50.00 $ 67.85 $ (16,652) Natural Gas 01/01/2022 - 03/31/2022 8,250,000 $ 2.70 $ 6.33 (151) Total open costless collar contracts $ (16,803) The following is a summary of the Company’s open basis swaps contracts for oil at December 31, 2021. Commodity Calculation Period Notional Quantity (Bbl) Fixed Price Fair Value of Asset (Liability) (thousands) Oil Basis 01/01/2022 - 12/31/2022 5,520,000 $ 0.95 1,925 Total open basis swap contracts $ 1,925 At December 31, 2021, the Company had an aggregate net liability value for open derivative financial instruments of $14.9 million. The Company’s derivative financial instruments are subject to master netting arrangements, and the Company’s counterparties allow for cross-commodity master netting provided the settlement dates for the commodities are the same. The Company does not present different types of commodities with the same counterparty on a net basis in its consolidated balance sheets. The following table presents the gross asset and liability fair values of the Company’s commodity price derivative financial instruments and the location of these balances in the consolidated balance sheets as of December 31, 2021 and December 31, 2020 (in thousands). Derivative Instruments Gross amounts recognized Gross amounts netted in the consolidated balance sheets Net amounts presented in the consolidated balance sheets December 31, 2021 Current assets $ 215,145 $ (213,174) $ 1,971 Current liabilities (230,023) 213,174 (16,849) Total $ (14,878) $ — $ (14,878) December 31, 2020 Current assets $ 382,328 $ (375,601) $ 6,727 Other assets 150,194 (147,624) 2,570 Current liabilities (420,787) 375,601 (45,186) Long-term liabilities (147,624) 147,624 — Total $ (35,889) $ — $ (35,889) The following table summarizes the location and aggregate gain (loss) of all derivative financial instruments recorded in the consolidated statements of operations for the periods presented (in thousands). Year Ended December 31, Type of Instrument Location in Statements of Operations 2021 2020 2019 Derivative Instrument Oil Revenues: Realized (loss) gain on derivatives $ (194,058) $ 38,937 $ 9,026 Natural Gas Revenues: Realized (loss) gain on derivatives (26,047) — 456 Realized (loss) gain on derivatives (220,105) 38,937 9,482 Oil Revenues: Unrealized gain (loss) on derivatives 26,857 (37,703) (53,443) Natural Gas Revenues: Unrealized (loss) gain on derivatives (5,846) 5,695 (284) Unrealized gain (loss) on derivatives 21,011 (32,008) (53,727) Total $ (199,094) $ 6,929 $ (44,245) |
Fair Value Measurements
Fair Value Measurements | 12 Months Ended |
Dec. 31, 2021 | |
Fair Value Disclosures [Abstract] | |
FAIR VALUE MEASUREMENTS | The Company measures and reports certain financial and non-financial assets and liabilities on a fair value basis. Fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date (exit price). Fair value measurements are classified and disclosed in one of the following categories. Level 1 Unadjusted quoted prices for identical, unrestricted assets or liabilities in active markets. Level 2 Quoted prices in markets that are not active, or inputs that are observable, either directly or indirectly, for substantially the full term of the asset or liability. This category includes those derivative instruments that are valued with industry standard models that consider various inputs, including: (i) quoted forward prices for commodities, (ii) time value of money and (iii) current market and contractual prices for the underlying instruments, as well as other relevant economic measures. Substantially all of these inputs are observable in the marketplace throughout the full term of the derivative instrument and can be derived from observable data or supported by observable levels at which transactions are executed in the marketplace. Level 3 Unobservable inputs that are not corroborated by market data that reflect a company’s own market assumptions. Financial and non-financial assets and liabilities are classified based on the lowest level of input that is significant to the fair value measurement. The assessment of the significance of a particular input to the fair value measurement requires judgment, which may affect the valuation of the fair value of assets and liabilities and their placement within the fair value hierarchy levels. The following tables summarize the valuation of the Company’s financial assets and liabilities that were accounted for at fair value on a recurring basis in accordance with the classifications provided above as of December 31, 2021 and 2020 (in thousands). Fair Value Measurements at Description Level 1 Level 2 Level 3 Total Assets (Liabilities) Oil derivatives and basis swaps $ — $ (14,727) $ — $ (14,727) Natural gas derivatives — (151) — (151) Contingent consideration related to business combination — — (8,203) (8,203) Total $ — $ (14,878) $ (8,203) $ (23,081) Fair Value Measurements at Description Level 1 Level 2 Level 3 Total Assets (Liabilities) Oil derivatives and basis swaps $ — $ (41,584) $ — $ (41,584) Natural gas derivatives — 5,695 — 5,695 Total $ — $ (35,889) $ — $ (35,889) Additional disclosures related to derivative financial instruments are provided in Note 12. Other Fair Value Measurements At December 31, 2021 and 2020, the carrying values reported on the consolidated balance sheets for accounts receivable, prepaid expenses and other current assets, accounts payable, accrued liabilities, royalties payable, amounts due to affiliates, advances from joint interest owners and other current liabilities approximated their fair values due to their short-term maturities. At December 31, 2021 and 2020, the carrying value of borrowings under the Credit Agreement and the San Mateo Credit Facility approximated their fair value as both are subject to short-term floating interest rates that reflect market rates available to the Company at the time and are classified at Level 2 in the fair value hierarchy. At December 31, 2021 and 2020, the fair value of the Notes was $1.08 billion and $1.03 billion, respectively, based on quoted market prices, which represent Level 1 inputs in the fair value hierarchy. |
Commitments and Contingencies
Commitments and Contingencies | 12 Months Ended |
Dec. 31, 2021 | |
Commitments and Contingencies Disclosure [Abstract] | |
COMMITMENTS AND CONTINGENCIES | Processing, Transportation and Produced Water Disposal Commitments Firm Commitments From time to time, the Company enters into agreements with third parties whereby the Company commits to deliver anticipated natural gas and oil production and produced water from certain portions of its acreage for gathering, transportation, processing, fractionation, sales and disposal. The Company paid approximately $48.7 million and $46.0 million for deliveries under these agreements during the years ended December 31, 2021 and 2020, respectively. Certain of these agreements contain minimum volume commitments. If the Company does not meet the minimum volume commitments under these agreements, it will be required to pay certain deficiency fees. If the Company ceased operations in the areas subject to these agreements at December 31, 2021, the total deficiencies required to be paid by the Company under these agreements would be approximately $597.3 million. San Mateo Commitments The Company dedicated to San Mateo its current and certain future leasehold interests in the Rustler Breaks and Wolf asset areas and acreage in the Greater Stebbins Area and the Stateline asset area pursuant to 15-year, fixed-fee oil transportation, oil, natural gas and produced water gathering and produced water disposal agreements. In addition, the Company dedicated to San Mateo its current and certain future leasehold interests in the Rustler Breaks asset area and acreage in the Greater Stebbins Area and Stateline asset area pursuant to 15-year, fixed-fee natural gas processing agreements (collectively with the transportation, gathering and produced water disposal agreements, the “Operational Agreements”). San Mateo provides the Company with firm service under each of the Operational Agreements in exchange for certain minimum volume commitments. The remaining minimum contractual obligation under the Operational Agreements at December 31, 2021 was approximately $390.3 million. Other Commitments The Company does not own or operate its own drilling rigs, but instead enters into contracts with third parties for such drilling rigs. These contracts establish daily rates for the drilling rigs and the term of the Company’s commitment for the drilling services to be provided. The Company would incur a termination obligation if the Company elected to terminate a contract and if the drilling contractor were unable to secure replacement work for the contracted drilling rigs at the same daily rates being charged to the Company prior to the end of their respective contract terms. The Company’s undiscounted minimum outstanding aggregate termination obligations under its drilling rig contracts were approximately $10.8 million at December 31, 2021. At December 31, 2021, the Company had outstanding commitments to drill and complete and to participate in the drilling and completion of various operated and non-operated wells. If all of these wells are drilled and completed as proposed, the Company’s undiscounted minimum outstanding aggregate commitments for its participation in these operated and non-operated wells were approximately $65.4 million at December 31, 2021. The Company expects these costs to be incurred within the next three Legal Proceedings The Company is a party to several legal proceedings encountered in the ordinary course of its business. While the ultimate outcome and impact to the Company cannot be predicted with certainty, in the opinion of management, it is remote that these legal proceedings will have a material adverse impact on the Company’s financial condition, results of operations or cash flows. |
Supplemental Disclosures
Supplemental Disclosures | 12 Months Ended |
Dec. 31, 2021 | |
Supplemental Disclosures [Abstract] | |
SUPPLEMENTAL DISCLOSURES | Accrued Liabilities The following table summarizes the Company’s current accrued liabilities at December 31, 2021 and 2020 (in thousands). December 31, 2021 2020 Accrued evaluated and unproved and unevaluated property costs $ 128,598 $ 44,012 Accrued midstream properties costs 7,799 12,776 Accrued lease operating expenses 32,182 24,276 Accrued interest on debt 18,232 18,315 Accrued asset retirement obligations 270 623 Accrued partners’ share of joint interest charges 17,460 7,407 Accrued payable related to purchased natural gas 11,284 418 Other 37,458 11,331 Total accrued liabilities $ 253,283 $ 119,158 Supplemental Cash Flow Information The following table provides supplemental disclosures of cash flow information for the years ended December 31, 2021, 2020 and 2019 (in thousands). Year Ended December 31, 2021 2020 2019 Cash paid for interest expense, net of amounts capitalized $ 74,843 $ 76,880 $ 75,525 Increase (decrease) in asset retirement obligations related to mineral properties $ 1,091 $ (208) $ 2,912 Increase in asset retirement obligations related to midstream properties $ 257 $ 690 $ 1,204 Increase (decrease) in liabilities for drilling, completion and equipping capital expenditures $ 80,255 $ (26,126) $ (13,310) Increase (decrease) increase in liabilities for acquisition of oil and natural gas properties $ 2,981 $ (2,346) $ (2,567) (Decrease) increase in liabilities for midstream capital expenditures $ (4,478) $ (33,609) $ 30,374 Stock-based compensation expense recognized as liability $ 24,494 $ 3,702 $ 3,170 Transfer of inventory (to) from oil and natural gas properties $ (398) $ 608 $ 1,515 The following table provides a reconciliation of cash and restricted cash recorded in the consolidated balance sheets to cash and restricted cash as presented on the consolidated statements of cash flows (in thousands). Year Ended December 31, 2021 2020 2019 Cash $ 48,135 $ 57,916 $ 40,024 Restricted cash 38,785 33,467 25,104 Total cash and restricted cash $ 86,920 $ 91,383 $ 65,128 |
Segment Reporting
Segment Reporting | 12 Months Ended |
Dec. 31, 2020 | |
Segment Reporting [Abstract] | |
Segment Reporting | The Company operates in two business segments: (i) exploration and production and (ii) midstream. The exploration and production segment is engaged in the exploration, development, production and acquisition of oil and natural gas resources in the United States and is currently focused primarily on the oil and liquids-rich portion of the Wolfcamp and Bone Spring plays in the Delaware Basin in Southeast New Mexico and West Texas. The Company also operates in the Eagle Ford shale play in South Texas and the Haynesville shale and Cotton Valley plays in Northwest Louisiana. The midstream segment conducts midstream operations in support of the Company’s exploration, development and production operations and provides natural gas processing, oil transportation services, oil, natural gas and produced water gathering services and produced water disposal services to third parties. Substantially all of the Company’s midstream operations in the Rustler Breaks, Wolf and Stateline asset areas and the Greater Stebbins Area in the Delaware Basin, which comprise most of the Company’s midstream operations, are conducted through San Mateo (see Note 6). San Mateo and its subsidiaries are not guarantors of the Notes or the Credit Agreement. The following tables present selected financial information for the periods presented regarding the Company’s business segments on a stand-alone basis, corporate expenses that are not allocated to a segment and the consolidation and elimination entries necessary to arrive at the financial information for the Company on a consolidated basis (in thousands). On a consolidated basis, midstream services revenues consist primarily of those revenues from midstream operations related to third parties, including working interest owners in the Company’s operated wells. All midstream services revenues associated with Company-owned production are eliminated in consolidation. In evaluating the operating results of the exploration and production and midstream segments, the Company does not allocate certain expenses to the individual segments, including general and administrative expenses. Such expenses are reflected in the column labeled “Corporate.” Exploration and Production Consolidations and Eliminations Consolidated Company Midstream Corporate Year Ended December 31, 2021 Oil and natural gas revenues $ 1,695,032 $ 5,510 $ — $ — $ 1,700,542 Midstream services revenues — 228,817 — (153,318) 75,499 Sales of purchased natural gas 47,398 38,636 — — 86,034 Realized loss on derivatives (220,105) — — — (220,105) Unrealized gain on derivatives 21,011 — — — 21,011 Expenses (1) 794,880 142,444 85,899 (153,318) 869,905 Operating income (2) $ 748,456 $ 130,519 $ (85,899) $ — $ 793,076 Total assets (3) $ 3,324,681 $ 879,672 $ 57,800 $ — $ 4,262,153 Capital expenditures (4) $ 778,191 $ 59,361 $ 376 $ — $ 837,928 _____________________ (1) Includes depletion, depreciation and amortization expenses of $310.9 million and $31.5 million for the exploration and production and midstream segments, respectively. Also includes corporate depletion, depreciation and amortization expenses of $2.6 million. (2) Includes $55.7 million in net income attributable to non-controlling interest in subsidiaries related to the midstream segment. (3) Excludes intercompany receivables and investments in subsidiaries. (4) Includes $263.5 million attributable to land and seismic acquisition expenditures related to the exploration and production segment and $28.5 million in capital expenditures attributable to non-controlling interest in subsidiaries related to the midstream segment. Exploration and Production Consolidations and Eliminations Consolidated Company Midstream Corporate Year Ended December 31, 2020 Oil and natural gas revenues $ 741,092 $ 3,369 $ — $ — $ 744,461 Midstream services revenues — 166,194 — (101,262) 64,932 Sales of purchased natural gas 20,736 21,006 — — 41,742 Lease bonus - mineral acreage 4,062 — — — 4,062 Realized gain on derivatives 38,937 — — — 38,937 Unrealized loss on derivatives (32,008) — — — (32,008) Expenses (1) 1,334,378 97,599 52,910 (101,262) 1,383,625 Operating (loss) income (2) $ (561,559) $ 92,970 $ (52,910) $ — $ (521,499) Total assets (3) $ 2,782,819 $ 836,509 $ 67,952 $ — $ 3,687,280 Capital expenditures (4) $ 518,198 $ 201,440 $ 2,200 $ — $ 721,838 _____________________ (1) Includes depletion, depreciation and amortization expenses of $335.8 million and $23.3 million for the exploration and production and midstream segments, respectively. Includes full-cost ceiling impairment of $684.7 million for the exploration and production segment. Also includes corporate depletion, depreciation and amortization expenses of $2.7 million. (2) Includes $39.6 million in net income attributable to non-controlling interest in subsidiaries related to the midstream segment. (3) Excludes intercompany receivables and investments in subsidiaries. (4) Includes $70.5 million attributable to land and seismic acquisition expenditures related to the exploration and production segment and $112.1 million in capital expenditures attributable to non-controlling interest in subsidiaries related to the midstream segment. Exploration and Production Consolidations and Eliminations Consolidated Company Midstream Corporate Year Ended December 31, 2019 Oil and natural gas revenues $ 886,127 $ 6,198 $ — $ — $ 892,325 Midstream services revenues — 135,953 — (76,843) 59,110 Sales of purchased natural gas 4,802 69,967 — — 74,769 Lease bonus - mineral acreage 1,711 — — — 1,711 Realized gain on derivatives 9,482 — — — 9,482 Unrealized loss on derivatives (53,727) — — — (53,727) Expenses (1) 621,687 130,612 72,734 (76,843) 748,190 Operating income (loss) (2) $ 226,708 $ 81,506 $ (72,734) $ — $ 235,480 Total assets (3) $ 3,360,725 $ 647,937 $ 61,014 $ — $ 4,069,676 Capital expenditures (4) $ 718,712 $ 223,612 $ 3,701 $ — $ 946,025 _____________________ (1) Includes depletion, depreciation and amortization expenses of $331.7 million and $16.1 million for the exploration and production and midstream segments, respectively. Also includes corporate depletion, depreciation and amortization expenses of $2.7 million. (2) Includes $35.2 million in net income attributable to non-controlling interest in subsidiaries related to the midstream segment. (3) Excludes intercompany receivables and investments in subsidiaries. (4) Includes $48.3 million attributable to land and seismic acquisition expenditures related to the exploration and production segment and $145.4 million in capital expenditures attributable to non-controlling interest in subsidiaries related to the midstream segment. |
Summary of Significant Accoun_2
Summary of Significant Accounting Policies (Policies) | 12 Months Ended | |
Dec. 31, 2021 | Dec. 31, 2020 | |
Accounting Policies [Abstract] | ||
Basis of Presentation | Basis of Presentation The consolidated financial statements include the accounts of Matador and its wholly-owned and majority-owned subsidiaries. These consolidated financial statements have been prepared in accordance with generally accepted accounting principles in the United States of America (“U.S. GAAP”). Accordingly, the Company consolidates certain subsidiaries and joint ventures that are less-than-wholly-owned and are not involved in oil and natural gas exploration, including San Mateo, and the net income and equity attributable to the non-controlling interest in these subsidiaries have been reported separately as required by Accounting Standards Codification (“ASC”), Consolidation (Topic 810) . The Company proportionately consolidates certain joint ventures that are less-than-wholly-owned and are involved in oil and natural gas exploration. All intercompany balances and transactions have been eliminated in consolidation. | |
Use of Estimates | Use of Estimates The preparation of financial statements in conformity with U.S. GAAP requires management to make estimates and assumptions that affect the amounts reported in the financial statements and accompanying notes. These estimates and assumptions may also affect 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. The Company’s consolidated financial statements are based on a number of significant estimates, including oil and natural gas revenues, accrued assets and liabilities, stock-based compensation, valuation of derivative instruments, deferred tax assets and liabilities, purchase price allocations and oil and natural gas reserves. The estimates of oil and natural gas reserves quantities and future net cash flows are the basis for the calculations of depletion and impairment of oil and natural gas properties, as well as estimates of asset retirement obligations and certain tax accruals. The Company’s oil and natural gas reserves estimates, which are inherently imprecise and based upon many factors that are beyond the Company’s control, including oil and natural gas prices, are prepared by the Company’s engineering staff in accordance with guidelines established by the Securities and Exchange Commission (“SEC”) and then audited for their reasonableness and conformance with SEC guidelines by Netherland, Sewell & Associates, Inc., independent reservoir engineers. While the Company believes its estimates are reasonable, changes in facts and assumptions or the discovery of new information may result in revised estimates. Actual results could differ from these estimates. | |
Restricted Cash | Restricted Cash Restricted cash represents a portion of the cash associated with the Company’s less-than-wholly-owned subsidiaries, primarily San Mateo. By contractual agreement, the cash in the accounts held by the Company’s less-than-wholly-owned subsidiaries is not to be commingled with other Company cash and is to be used only to fund the capital expenditures and operations of these less-than-wholly-owned subsidiaries. | |
Accounts Receivable | Accounts Receivable The Company sells its operated oil, natural gas and natural gas liquid (“NGL”) production to various purchasers (see “—Revenues” below). In addition, the Company may participate with industry partners in the drilling, completion and operation of oil and natural gas wells. Substantially all of the Company’s accounts receivable are due from purchasers of oil, natural gas and NGLs, participants in oil and natural gas wells for which the Company serves as the operator, San Mateo’s customers or the Company’s derivative counterparties. Accounts receivable are typically due within 30 to 60 days of the production date and 30 days of the billing date and are stated at amounts due from purchasers and industry partners. Amounts are considered past due if they have been outstanding for 60 days or more. No interest is typically charged on past due amounts. | |
Lease and Well Equipment Inventory | Lease and Well Equipment Inventory Lease and well equipment inventory is stated at the lower of cost or market and consists entirely of materials or equipment scheduled for use in future well or midstream operations. | |
Property and Equipment | Oil and Natural Gas Properties The Company uses the full-cost method of accounting for its investments in oil and natural gas properties. Under this method, all costs associated with the acquisition, exploration and development of oil and natural gas properties and reserves, including unproved and unevaluated property costs, are capitalized as incurred and accumulated in a single cost center representing the Company’s activities, which are undertaken exclusively in the United States. Such costs include lease acquisition costs, geological and geophysical expenditures, lease rentals on undeveloped properties, costs of drilling both productive and non-productive wells, capitalized interest on qualifying projects and general and administrative expenses directly related to acquisition, exploration and development activities, but do not include any costs related to production, selling or general corporate administrative activities. The Company capitalized $38.4 million, $30.0 million and $31.1 million of its general and administrative costs into oil and natural gas properties in 2021, 2020 and 2019, respectively. The Company capitalized $4.8 million, $5.0 million and $7.6 million of its interest expense into oil and natural gas properties for the years ended December 31, 2021, 2020 and 2019, respectively. Capitalized costs of oil and natural gas properties are amortized using the unit-of-production method based upon production and estimates of proved reserves quantities. For the years ended December 31, 2021, 2020 and 2019, the Company recorded depletion expense of $310.1 million, $334.8 million and $330.7 million, respectively. Unproved and unevaluated property costs are excluded from the amortization base used to determine depletion. Unproved and unevaluated properties are assessed for possible impairment on a periodic basis based upon changes in operating or economic conditions. This assessment includes consideration of the following factors, among others: the assignment of proved reserves, geological and geophysical evaluations, intent to drill, remaining lease term and drilling activity and results. Upon impairment, the costs of the unproved and unevaluated properties are immediately included in the amortization base. Exploratory dry holes are included in the amortization base immediately upon determination that the well is not productive. Sales of oil and natural gas properties are accounted for as adjustments to net capitalized costs with no gain or loss recognized, unless such adjustments would significantly alter the relationship between net capitalized costs and proved reserves of oil and natural gas. All costs related to production activities and maintenance and repairs are expensed as incurred. Significant workovers that increase the properties’ reserves are capitalized. Ceiling Test The net capitalized costs of oil and natural gas properties are limited to the lower of unamortized costs less related deferred income taxes or the cost center “ceiling.” The cost center ceiling is defined as the sum of: (a) the present value, discounted at 10%, of future net revenues of proved oil and natural gas reserves, reduced by the estimated costs of developing these reserves, plus (b) unproved and unevaluated property costs not being amortized, plus (c) the lower of cost or estimated fair value of unproved and unevaluated properties included in the costs being amortized, if any, less (d) any income tax effects related to the properties involved. Any excess of the Company’s net capitalized costs above the cost center ceiling as described above is charged to operations as a full-cost ceiling impairment. The Company’s derivative instruments are not considered in the ceiling test computations as the Company does not designate these instruments as hedge instruments for accounting purposes. The estimated present value of after-tax future net cash flows from proved oil and natural gas reserves is highly dependent upon the quantities of proved reserves, the estimation of which requires substantial judgment. The associated commodity prices and the applicable discount rate used in these estimates are in accordance with guidelines established by the SEC. Under these guidelines, oil and natural gas reserves are estimated using then-current operating and economic conditions, with no provision for price and cost changes in future periods except by contractual arrangements. Future net revenues are calculated using prices that represent the arithmetic averages of the first-day-of-the-month oil and natural gas prices for the previous 12-month period, and a 10% discount factor is used to determine the present value of future net revenues. For the period from January through December 2021, these average oil and natural gas prices were $63.04 per Bbl and $3.60 per MMBtu, respectively. For the period from January through December 2020, these average oil and natural gas prices were $36.04 per Bbl and $1.99 per MMBtu, respectively. For the period from January through December 2019, these average oil and natural gas prices were $52.19 per Bbl and $2.58 per MMBtu, respectively. In estimating the present value of after-tax future net cash flows from proved oil and natural gas reserves, the average oil prices were further adjusted by property for quality, transportation and marketing fees and regional price differentials, and the average natural gas prices were further adjusted by property for energy content, transportation and marketing fees and regional price differentials. During the years ended December 31, 2021 and 2019, the Company’s full-cost ceiling exceeded the net capitalized costs less related deferred income taxes. As a result, the Company recorded no impairment to its net capitalized costs during the years ended December 31, 2021 and 2019. For the year ended December 31, 2020, the Company’s net capitalized costs less related deferred income taxes exceeded the full-cost ceiling. As a result, the Company recorded an impairment charge of $684.7 million, exclusive of tax effect, to its consolidated statement of operations for the year ended December 31, 2020 with the related deferred income tax benefit recorded net of a valuation allowance (see Note 8). As a non-cash item, the full-cost ceiling impairment impacts the accumulated depletion and the net carrying value of the Company’s assets on its consolidated balance sheets, as well as the corresponding shareholders’ equity, but it has no impact on the Company’s net cash flows as reported. Changes in oil and natural gas production rates, oil and natural gas prices, reserves estimates, future development costs and other factors will determine the Company’s actual ceiling test computation and impairment analyses in future periods. Midstream Properties and Other Property and Equipment Midstream properties and other property and equipment are recorded at historical cost and include midstream equipment and facilities, including the Company’s pipelines, processing facilities and produced water disposal systems, and corporate assets, including furniture, fixtures, equipment, land and leasehold improvements. Midstream equipment and facilities are depreciated over a 30-year useful life using the straight-line, mid-month convention method. Leasehold improvements are depreciated over the lesser of their useful lives or the term of the lease. Software, furniture, fixtures and other equipment are depreciated over their useful life ( five The Company evaluates midstream properties and other property and equipment for potential impairment whenever events or changes in circumstances indicate that their carrying value may not be recoverable. The carrying amount of a long-lived asset is not recoverable when it exceeds the undiscounted sum of the future cash flows expected to result from the use and eventual disposition of the asset. Expected future cash flows represent management’s estimates based on reasonable and supportable assumptions. | |
Asset Retirement Obligations | Asset Retirement ObligationsThe Company recognizes the fair value of an asset retirement obligation in the period in which it is incurred if a reasonable estimate of fair value can be made. The asset retirement obligation is recorded as a liability at its estimated present value, with an offsetting increase recognized in oil and natural gas properties, midstream properties or other property and equipment on the consolidated balance sheets. Periodic accretion of the discounted value of the estimated liability is recorded as an expense in the consolidated statements of operations. | |
Derivative Financial Instruments | Derivative Financial InstrumentsFrom time to time, the Company uses derivative financial instruments to mitigate its exposure to commodity price risk associated with oil, natural gas and NGL prices. The Company’s derivative financial instruments are recorded on the consolidated balance sheets as either an asset or a liability measured at fair value. The Company has elected not to apply hedge accounting for its existing derivative financial instruments, and as a result, the Company recognizes the change in derivative fair value between reporting periods currently in its consolidated statements of operations. The fair value of the Company’s derivative financial instruments is determined using industry-standard models that consider various inputs including: (i) quoted forward prices for commodities, (ii) time value of money and (iii) current market and contractual prices for the underlying instruments, as well as other relevant economic measures. Realized gains and losses from the settlement of derivative financial instruments and unrealized gains and unrealized losses from valuation changes in the remaining unsettled derivative financial instruments are reported as a component of revenues in the consolidated statements of operations. See Note 12 for additional information about the Company’s derivative instruments. | |
Revenues | Revenues The Company enters into contracts with customers to sell its oil and natural gas production. Revenue from these contracts is recognized when the Company’s performance obligations under these contracts are satisfied, which generally occurs with the transfer of control of the oil and natural gas to the purchaser. Control is generally considered transferred when the following criteria are met: (i) transfer of physical custody, (ii) transfer of title, (iii) transfer of risk of loss and (iv) relinquishment of any repurchase rights or other similar rights. Given the nature of the products sold, revenue is recognized at a point in time based on the amount of consideration the Company expects to receive in accordance with the price specified in the contract. Consideration under oil and natural gas marketing contracts is typically received from the purchaser one The majority of the Company’s oil marketing contracts transfer physical custody and title at or near the wellhead or a central delivery point, which is generally when control of the oil has been transferred to the purchaser. The majority of the oil produced is sold under contracts using market-based pricing, which price is then adjusted for differentials based upon delivery location and oil quality. To the extent the differentials are incurred at or after the transfer of control of the oil, the differentials are included in oil revenues on the statements of operations, as they represent part of the transaction price of the contract. If the differentials, or other related costs, are incurred prior to the transfer of control of the oil, those costs are included in production taxes, transportation and processing expenses on the Company’s consolidated statements of operations, as they represent payment for services performed outside of the contract with the customer. The Company’s natural gas is sold at the lease location, at the inlet or outlet of a natural gas processing plant or at an interconnect near a marketing hub following transportation from a processing plant. The majority of the Company’s natural gas is sold under fee-based contracts. When the natural gas is sold at the lease, the purchaser gathers the natural gas via pipeline to natural gas processing plants where, if necessary, NGLs are extracted. The NGLs and remaining residue gas are then sold by the purchaser, or if the Company elects to take in-kind the natural gas or the NGLs, the Company sells the natural gas or the NGLs to a third party. Under the fee-based contracts, the Company receives NGL and residue gas value, less the fee component, or is invoiced the fee component. To the extent control of the natural gas transfers upstream of the gathering and processing activities, revenue is recognized as the net amount received from the purchaser. To the extent that control transfers downstream of those services, revenue is recognized on a gross basis, and the related costs are included in production taxes, transportation and processing expenses on the Company’s consolidated statements of operations. The Company recognizes midstream services revenues at the time services have been rendered and the price is fixed and determinable. Third-party midstream services revenues are those revenues from midstream operations related to third parties, including working interest owners in the Company’s operated wells. All midstream services revenues related to the Company’s working interest are eliminated in consolidation. Since the Company has a right to payment from its customers in amounts that correspond directly to the value that the customer receives from the performance completed on each contract, the Company applies the practical expedient in Accounting Standards Update 2014-09, Revenue from Contracts with Customers (Topic 606) (“ASC 606”) that allows recognition of revenue in the amount for which there is a right to invoice the customer without estimating a transaction price for each contract and allocating that transaction price to the performance obligations within each contract. The Company periodically enters into natural gas purchase transactions with third parties whereby the Company (i) purchases the third party’s natural gas and subsequently sells the natural gas to other purchasers or (ii) processes the third party’s natural gas at San Mateo’s Black River cryogenic natural gas processing plant in Eddy County, New Mexico (the “Black River Processing Plant”) and then purchases, and subsequently sells, the residue gas and NGLs to other purchasers. Revenues and expenses from these transactions are presented on a gross basis on the Company’s consolidated statements of operations as the Company acts as a principal in the transactions by assuming the risk and rewards of ownership, including credit risk, of the natural gas purchased and by assuming the responsibility to deliver and process the natural gas volumes to be sold. From time to time, the Company, as an owner of mineral interests, may enter into or extend a lease to a third-party lessee to develop the oil and natural gas attributable to certain of its mineral interests in return for a specified payment or lease bonus. In those instances, revenue is recognized in the period when the lease is signed and the Company has no further obligation to the lessee. The Company records these payments as “Lease bonus - mineral acreage” revenues on its consolidated statements of operations. The following table summarizes the Company’s total revenues and revenues from contracts with customers on a disaggregated basis for the years ended December 31, 2021, 2020 and 2019 (in thousands). Year Ended December 31, 2021 2020 2019 Revenues from contracts with customers $ 1,862,075 $ 851,135 $ 1,026,204 Lease bonus - mineral acreage — 4,062 1,711 Realized (loss) gain on derivatives (220,105) 38,937 9,482 Unrealized gain (loss) on derivatives 21,011 (32,008) (53,727) Total revenues $ 1,662,981 $ 862,126 $ 983,670 Year Ended December 31, 2021 2020 2019 Oil revenues $ 1,205,608 $ 595,507 $ 759,811 Natural gas revenues 494,934 148,954 132,514 Third-party midstream services revenues 75,499 64,932 59,110 Sales of purchased natural gas 86,034 41,742 74,769 Total revenues from contracts with customers $ 1,862,075 $ 851,135 $ 1,026,204 The Company does not disclose the value of unsatisfied performance obligations under its contracts with customers as it applies the practical expedient in accordance with ASC 606. The expedient, as described in ASC 606-10-50-14(a), applies to variable consideration that is recognized as control of the product is transferred to the customer. Since each unit of product represents a separate performance obligation, future volumes are wholly unsatisfied and disclosure of the transaction price allocated to remaining performance obligations is not required. | |
Stock-Based Compensation | Stock-Based Compensation The Company may grant equity-based and liability-based common stock, stock options, restricted stock, restricted stock units, performance stock units and other awards permitted under any long-term incentive plan of the Company then in effect to members of its Board of Directors and certain employees, contractors and advisors. All equity-based awards are measured at | |
Income Taxes | Income Taxes The Company accounts for income taxes using the asset and liability approach for financial accounting and reporting. The Company evaluates the probability of realizing the future benefits of its deferred tax assets and records a valuation allowance for the portion of any deferred tax assets when it is more likely than not that the benefit from the deferred tax asset will not be realized. The Company recognizes the tax benefit of an uncertain tax position only if it is more likely than not that the tax position will be sustained upon examination by the taxing authorities based on the technical merits of the position. For tax positions meeting the more likely than not threshold, the amount recognized in the financial statements is the benefit that has a greater than 50% likelihood of being realized upon ultimate settlement with the relevant tax authority. At December 31, 2021, 2020 and 2019, the Company had not established any reserves for, nor recorded any unrecognized tax benefits related to, uncertain tax positions. When necessary, the Company would include interest assessed by taxing authorities in “Interest expense” and penalties related to income taxes in “Other expense” on its consolidated statements of operations. The Company did not record any interest or penalties related to income taxes for the years ended December 31, 2021, 2020 and 2019. | |
Earnings Per Common Share | Earnings Per Common Share The Company reports basic earnings attributable to Matador Resources Company shareholders per common share, which excludes the effect of potentially dilutive securities, and diluted earnings attributable to Matador Resources Company shareholders per common share, which includes the effect of all potentially dilutive securities, unless their impact is anti-dilutive. The following are reconciliations of the numerators and denominators used to compute the Company’s basic and diluted earnings per common share as reported for the years ended December 31, 2021, 2020 and 2019 (in thousands, except per share data). Year Ended December 31, 2021 2020 2019 Net income (loss) attributable to Matador Resources Company shareholders — numerator $ 584,968 $ (593,205) $ 87,777 Weighted average common shares outstanding — denominator Basic 116,999 116,068 116,555 Dilutive effect of options and restricted stock units 2,164 — 508 Diluted weighted average common shares outstanding 119,163 116,068 117,063 Earnings (loss) per common share attributable to Matador Resources Company shareholders Basic $ 5.00 $ (5.11) $ 0.75 Diluted $ 4.91 $ (5.11) $ 0.75 A total of 2.5 million and 2.6 million options to purchase shares of Matador’s common stock were excluded from the diluted weighted average common shares outstanding for the years ended December 31, 2020 and 2019, respectively, because their effects were anti-dilutive. Additionally, 0.7 million restricted shares, which are participating securities, were excluded from the calculations above for the year ended December 31, 2020 as the security holders do not have the obligation to share in the losses of the Company. | |
Credit Risk | Credit Risk The Company’s cash is held in financial institutions and at times these amounts exceed the insurance limits of the Federal Deposit Insurance Corporation. Management believes, however, that the Company’s counterparty risks are minimal based on the reputation and history of the institutions selected. The Company uses derivative financial instruments to mitigate its exposure to oil, natural gas and NGL price volatility. These transactions expose the Company to potential credit risk from its counterparties. The Company manages counterparty credit risk through established internal derivatives policies that are reviewed on an ongoing basis. Additionally, the Company’s commodity derivative contracts at December 31, 2021 were with The Bank of Nova Scotia, BMO Harris Financing, Inc. (Bank of Montreal), PNC Bank and Royal Bank of Canada (or affiliates thereof), and all but BMO Harris Financing, Inc. (Bank of Montreal) were parties that are lenders (or affiliates thereof) under the Company’s reserves-based revolving credit agreement. Accounts receivable constitute the principal component of additional credit risk to which the Company may be exposed. The Company attempts to minimize credit risk exposure to counterparties by monitoring the financial condition and payment history of its purchasers and joint interest partners. |
Summary of Significant Accoun_3
Summary of Significant Accounting Policies (Tables) | 12 Months Ended |
Dec. 31, 2021 | |
Accounting Policies [Abstract] | |
Disaggregation of Revenue | Year Ended December 31, 2021 2020 2019 Revenues from contracts with customers $ 1,862,075 $ 851,135 $ 1,026,204 Lease bonus - mineral acreage — 4,062 1,711 Realized (loss) gain on derivatives (220,105) 38,937 9,482 Unrealized gain (loss) on derivatives 21,011 (32,008) (53,727) Total revenues $ 1,662,981 $ 862,126 $ 983,670 Year Ended December 31, 2021 2020 2019 Oil revenues $ 1,205,608 $ 595,507 $ 759,811 Natural gas revenues 494,934 148,954 132,514 Third-party midstream services revenues 75,499 64,932 59,110 Sales of purchased natural gas 86,034 41,742 74,769 Total revenues from contracts with customers $ 1,862,075 $ 851,135 $ 1,026,204 |
Reconciliations of basic and diluted distributed and undistributed earnings (loss) per common share | The following are reconciliations of the numerators and denominators used to compute the Company’s basic and diluted earnings per common share as reported for the years ended December 31, 2021, 2020 and 2019 (in thousands, except per share data). Year Ended December 31, 2021 2020 2019 Net income (loss) attributable to Matador Resources Company shareholders — numerator $ 584,968 $ (593,205) $ 87,777 Weighted average common shares outstanding — denominator Basic 116,999 116,068 116,555 Dilutive effect of options and restricted stock units 2,164 — 508 Diluted weighted average common shares outstanding 119,163 116,068 117,063 Earnings (loss) per common share attributable to Matador Resources Company shareholders Basic $ 5.00 $ (5.11) $ 0.75 Diluted $ 4.91 $ (5.11) $ 0.75 |
Property and Equipment (Tables)
Property and Equipment (Tables) | 12 Months Ended |
Dec. 31, 2021 | |
Property, Plant and Equipment [Abstract] | |
Summary of the Company's property and equipment | The following table presents a summary of the Company’s property and equipment balances as of December 31, 2021 and 2020 (in thousands). December 31, 2021 2020 Oil and natural gas properties Evaluated (subject to amortization) $ 6,007,325 $ 5,295,931 Unproved and unevaluated (not subject to amortization) 964,714 902,133 Total oil and natural gas properties 6,972,039 6,198,064 Accumulated depletion (3,933,355) (3,623,265) Net oil and natural gas properties 3,038,684 2,574,799 Midstream properties Midstream equipment and facilities 900,979 841,695 Accumulated depreciation (92,574) (61,113) Net midstream properties 808,405 780,582 Other property and equipment Furniture, fixtures and other equipment 10,923 10,591 Software 8,225 8,116 Leasehold improvements 10,975 10,854 Total other property and equipment 30,123 29,561 Accumulated depreciation (20,527) (17,173) Net other property and equipment 9,596 12,388 Net property and equipment $ 3,856,685 $ 3,367,769 |
Breakdown of the Company's unproved and unevaluated property costs not subject to amortization | The following table provides a breakdown of the Company’s unproved and unevaluated property costs not subject to amortization as of December 31, 2021 and the year in which these costs were incurred (in thousands). Description 2021 2020 2019 2018 2017 and prior Total Costs incurred for Property acquisition $ 111,120 $ 40,355 $ 40,140 $ 417,114 $ 287,666 $ 896,395 Exploration wells 14,738 411 1,199 123 274 16,745 Development wells 46,232 2,027 3,245 60 10 51,574 Total $ 172,090 $ 42,793 $ 44,584 $ 417,297 $ 287,950 $ 964,714 |
Leases (Tables)
Leases (Tables) | 12 Months Ended |
Dec. 31, 2021 | |
Leases [Abstract] | |
Lease, Cost | The following table presents supplemental consolidated statement of operations information related to lease expenses, on a gross basis, for the years ended December 31, 2021 and 2020, respectively (in thousands). Lease payments represent gross payments to vendors, which, for certain of the Company’s operating assets, are partially offset by amounts received from other working interest owners in the Company’s operated wells. Year Ended December 31, 2021 2020 Operating leases Lease operating $ 11,393 $ 12,994 Plant and other midstream services 36 28 General and administrative 3,645 3,698 Total operating leases (1) 15,074 16,720 Short-term leases Lease operating 11,234 12,890 Plant and other midstream services 4,037 5,689 General and administrative 37 47 Total short-term leases (2)(3) 15,308 18,626 Financing leases Depreciation of assets 566 747 Interest on lease liabilities 138 123 Total financing leases 704 870 Total lease expense $ 31,086 $ 36,216 _____________________ (1) Does not include gross payments related to drilling rig leases of $31.9 million and $33.6 million for the years ended December 31, 2021 and 2020, respectively, that were capitalized and recorded in “Oil and natural gas properties, full-cost method” in the consolidated balance sheets at December 31, 2021 and 2020, respectively. (2) These costs are related to leases that are not recorded as right of use assets or lease liabilities in the consolidated balance sheets as they are short-term leases. (3) Does not include gross payments related to short-term drilling rig leases and other equipment rentals of $61.7 million and $65.3 million for the years ended December 31, 2021 and 2020, respectively, that were capitalized and recorded in “Oil and natural gas properties, full-cost method” in the consolidated balance sheets at December 31, 2021 and 2020, respectively. The following table presents supplemental consolidated cash flow information related to lease payments for the year ended December 31, 2021 and 2020, respectively (in thousands). Year Ended December 31, 2021 2020 Cash paid related to lease liabilities Operating cash payments for operating leases $ 14,430 $ 15,664 Investing cash payments for operating leases $ 31,967 $ 33,556 Financing cash payments for financing leases $ 629 $ 790 Right of use assets obtained in exchange for lease obligations entered into during the period Operating leases $ 18,454 $ 12,474 Financing leases $ 2,241 $ 996 |
Assets And Liabilities, Lessee | The following table presents supplemental consolidated balance sheet information related to leases as of December 31, 2021 and 2020, respectively (in thousands). December 31, 2021 2020 Operating leases Other long-term assets $ 29,519 $ 51,528 Other current liabilities $ (19,649) $ (35,716) Other long-term liabilities (15,340) (21,598) Total operating lease liabilities $ (34,989) $ (57,314) Financing leases Other property and equipment, at cost $ 5,914 $ 3,673 Accumulated depreciation (3,485) (2,134) Net property and equipment $ 2,429 $ 1,539 Other current liabilities $ (378) $ (621) Other long-term liabilities (45) (256) Total financing lease liabilities $ (423) $ (877) |
Lessee, Lease Terms | The following table presents the maturities of lease liabilities at December 31, 2021 (in years). Weighted-Average Remaining Lease Term December 31, 2021 Operating leases 2.5 Financing leases 1.7 |
Finance Lease, Liability, Maturity | The following table presents a schedule of future minimum lease payments required under all lease agreements as of December 31, 2021 (in thousands). December 31, 2021 Operating Leases Financing Leases 2022 $ 19,649 $ 378 2023 6,830 180 2024 4,217 37 2025 4,287 — 2026 1,553 — Thereafter — — Total lease payments 36,536 595 Less imputed interest (1,547) (172) Total lease obligations 34,989 423 Less current obligations (19,649) (378) Long-term lease obligations $ 15,340 $ 45 |
Lessee, Operating Lease, Liability, Maturity | The following table presents a schedule of future minimum lease payments required under all lease agreements as of December 31, 2021 (in thousands). December 31, 2021 Operating Leases Financing Leases 2022 $ 19,649 $ 378 2023 6,830 180 2024 4,217 37 2025 4,287 — 2026 1,553 — Thereafter — — Total lease payments 36,536 595 Less imputed interest (1,547) (172) Total lease obligations 34,989 423 Less current obligations (19,649) (378) Long-term lease obligations $ 15,340 $ 45 |
Asset Retirement Obligations (T
Asset Retirement Obligations (Tables) | 12 Months Ended |
Dec. 31, 2021 | |
Asset Retirement Obligation Disclosure [Abstract] | |
Schedule of changes in Company's asset retirement obligations | The following table summarizes the changes in the Company’s asset retirement obligations for the years ended December 31, 2021 and 2020 (in thousands). Year Ended December 31, 2021 2020 Beginning asset retirement obligations $ 38,542 $ 36,211 Liabilities incurred during period 2,294 2,548 Liabilities settled during period (151) (290) Revisions in estimated cash flows 86 (1,875) Divestitures during the period (880) — Accretion expense 2,068 1,948 Ending asset retirement obligations 41,959 38,542 Less: current asset retirement obligations (1) (270) (623) Long-term asset retirement obligations $ 41,689 $ 37,919 __________________ (1) Included in “Accrued liabilities” in the Company’s consolidated balance sheets at December 31, 2021 and 2020. |
Business Combinations and Asset
Business Combinations and Asset Acquisitions (Tables) | 12 Months Ended |
Dec. 31, 2021 | |
Business Combination and Asset Acquisition [Abstract] | |
Schedule of Recognized Identified Assets Acquired and Liabilities Assumed | The preliminary allocation of the consideration given related to this business combination was as follows (in thousands). The Company anticipates that the allocation of the consideration given should be finalized during 2022 upon determination of the final customary purchase price adjustments. Consideration given Allocation Cash $161,680 Working capital adjustments to be paid in 2022 6,500 Fair value of contingent consideration at December 14, 2021 6,718 Total consideration given $174,898 Allocation of purchase price Oil and natural gas properties Evaluated $139,312 Unproved and unevaluated 43,204 Accrued liabilities (360) Advances from joint interest owners (6,865) Asset retirement obligations (393) Net assets acquired $174,898 |
Debt (Tables)
Debt (Tables) | 12 Months Ended |
Dec. 31, 2021 | |
Debt Disclosure [Abstract] | |
Debt Instrument Redemption | The Company may redeem all or a part of the Notes at any time or from time to time at the following redemption prices (expressed as percentages of principal amount) plus accrued and unpaid interest, if any, to the applicable redemption date, if redeemed during the twelve-month period beginning on September 15 of the years indicated below: Year Redemption Price 2021 104.406% 2022 102.938% 2023 101.469% 2024 and thereafter 100.000% |
Income Taxes (Tables)
Income Taxes (Tables) | 12 Months Ended |
Dec. 31, 2021 | |
Income Tax Disclosure [Abstract] | |
Summary of net deferred tax position | The Company’s net deferred tax position as of December 31, 2021 and 2020 is as follows (in thousands). December 31, 2021 2020 Deferred tax assets Net operating loss carryforwards $ 129,651 $ 122,952 Unrealized loss on derivatives 3,729 8,997 Percentage depletion carryover 1,770 1,462 Compensation 9,838 10,405 Lease liabilities 4,866 9,380 Other 9,410 8,334 Total deferred tax assets 159,264 161,530 Valuation allowance on deferred tax assets (10,599) (110,681) Total deferred tax assets, net of valuation allowance 148,665 50,849 Deferred tax liabilities Property and equipment (179,153) (11,879) Less than wholly-owned subsidiaries (39,900) (26,564) Lease right of use assets (4,866) (9,380) Other (2,684) (2,684) Total deferred tax liabilities (226,603) (50,507) Net deferred tax (liabilities) assets $ (77,938) $ 342 |
Income tax expense reconciled to the tax computed at the statutory federal rate | The current income tax provision and the deferred income tax provision for the years ended December 31, 2021, 2020 and 2019 were comprised of the following (in thousands). Year Ended December 31, 2021 2020 2019 Deferred income tax provision (benefit) Federal income tax $ 44,883 $ (25,675) $ 29,171 State income tax 29,827 (19,924) 6,361 Net deferred income tax provision (benefit) $ 74,710 $ (45,599) $ 35,532 Reconciliations of the tax expense (benefit) computed at the statutory federal rate to the Company’s total income tax provision (benefit) for the years ended December 31, 2021, 2020 and 2019 is as follows (in thousands). Year Ended December 31, 2021 2020 2019 Federal tax expense (benefit) at statutory rate (1) $ 150,223 $ (125,823) $ 33,441 State income tax 26,646 (20,607) 6,141 Permanent differences (2,078) (3,114) (4,267) Change in federal valuation allowance (103,262) 103,262 — Change in state valuation allowance 3,181 683 217 Net deferred income tax provision (benefit) 74,710 (45,599) 35,532 Total income tax provision (benefit) $ 74,710 $ (45,599) $ 35,532 __________________ (1) The statutory federal tax rate was 21% for the years ended December 31, 2021, 2020 and 2019. |
Stock-Based Compensation (Table
Stock-Based Compensation (Tables) | 12 Months Ended |
Dec. 31, 2021 | |
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |
Summarized information about stock options outstanding | Summarized information about stock options outstanding at December 31, 2021 under the 2012 Incentive Plan and the 2019 Incentive Plan (collectively, the “LTIPs”) is as follows. Number of options (in thousands) Weighted Options outstanding at December 31, 2020 2,473 $ 23.08 Options granted — $ — Options exercised (1,368) $ 25.37 Options forfeited (37) $ 18.72 Options expired (465) $ 16.90 Options outstanding at December 31, 2021 603 $ 22.92 |
Summarized information about outstanding and exercisable stock option | Options outstanding at Options exercisable at Range of exercise prices Shares outstanding (in thousands) Weighted Weighted Shares exercisable (in thousands) Weighted $14.48 - $15.40 240 3.66 $ 14.80 82 $ 14.80 $26.86 - $29.68 363 1.59 $ 28.28 363 $ 28.28 |
Summary of the non-vested restricted stock and restricted stock units | A summary of the non-vested equity-based restricted stock and restricted stock units as of December 31, 2021 is presented below (in thousands, except fair value). Restricted Stock Restricted Stock Units Service Based Service Based Performance Based Non-vested restricted stock and Shares Weighted Shares Weighted Shares Weighted Non-vested at December 31, 2020 682 $ 20.01 75 $ 8.85 1,069 $ 9.05 Granted 283 $ 37.56 36 $ 30.97 366 $ 50.53 Vested (1) (334) $ 27.14 (78) $ 9.02 (397) $ 20.00 Forfeited (42) $ 17.35 — $ — (75) $ 9.33 Non-vested at December 31, 2021 589 $ 24.59 33 $ 33.39 963 $ 20.26 __________________ (1) On December 31, 2021, 396,827 of the performance-based awards that were granted in 2019 vested. The vested units earned 200% for each vested award representing 793,654 aggregate shares of common stock, which were issued on December 31, 2021. |
2012 Incentive Plan | |
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |
Weighted average assumptions used to estimate fair value of stock options granted under the Stock and Incentive Plan | The weighted average grant date fair value for stock option awards granted under the 2019 Incentive Plan was estimated using the following weighted average assumptions during the year ended December 31, 2019. The Company did not grant stock option awards during the years ended December 31, 2021 and 2020. 2019 Stock option pricing model Black Scholes Merton Expected option life 4.00 years Risk-free interest rate 1.46% Volatility 48.52% Dividend yield —% Estimated forfeiture rate 4.43% Weighted average fair value of stock option awards granted during the year $5.04 |
Derivative Financial Instrume_2
Derivative Financial Instruments (Tables) | 12 Months Ended |
Dec. 31, 2021 | |
Derivative Instruments and Hedging Activities Disclosure [Abstract] | |
Summary of contracts for oil and natural gas | The following is a summary of the Company’s open costless collar contracts for oil and natural gas at December 31, 2021. Notional Quantity (Bbl or MMBtu) Weighted Average Price Floor ($/Bbl or Weighted Average Price Ceiling ($/Bbl or Fair Value of Asset (Liability) (thousands) Commodity Calculation Period Oil 01/01/2022 - 12/31/2022 2,040,000 $ 50.00 $ 67.85 $ (16,652) Natural Gas 01/01/2022 - 03/31/2022 8,250,000 $ 2.70 $ 6.33 (151) Total open costless collar contracts $ (16,803) The following is a summary of the Company’s open basis swaps contracts for oil at December 31, 2021. Commodity Calculation Period Notional Quantity (Bbl) Fixed Price Fair Value of Asset (Liability) (thousands) Oil Basis 01/01/2022 - 12/31/2022 5,520,000 $ 0.95 1,925 Total open basis swap contracts $ 1,925 |
Summary of offsetting assets | The following table presents the gross asset and liability fair values of the Company’s commodity price derivative financial instruments and the location of these balances in the consolidated balance sheets as of December 31, 2021 and December 31, 2020 (in thousands). Derivative Instruments Gross amounts recognized Gross amounts netted in the consolidated balance sheets Net amounts presented in the consolidated balance sheets December 31, 2021 Current assets $ 215,145 $ (213,174) $ 1,971 Current liabilities (230,023) 213,174 (16,849) Total $ (14,878) $ — $ (14,878) December 31, 2020 Current assets $ 382,328 $ (375,601) $ 6,727 Other assets 150,194 (147,624) 2,570 Current liabilities (420,787) 375,601 (45,186) Long-term liabilities (147,624) 147,624 — Total $ (35,889) $ — $ (35,889) |
Summary of offsetting liabilities | The following table presents the gross asset and liability fair values of the Company’s commodity price derivative financial instruments and the location of these balances in the consolidated balance sheets as of December 31, 2021 and December 31, 2020 (in thousands). Derivative Instruments Gross amounts recognized Gross amounts netted in the consolidated balance sheets Net amounts presented in the consolidated balance sheets December 31, 2021 Current assets $ 215,145 $ (213,174) $ 1,971 Current liabilities (230,023) 213,174 (16,849) Total $ (14,878) $ — $ (14,878) December 31, 2020 Current assets $ 382,328 $ (375,601) $ 6,727 Other assets 150,194 (147,624) 2,570 Current liabilities (420,787) 375,601 (45,186) Long-term liabilities (147,624) 147,624 — Total $ (35,889) $ — $ (35,889) |
Summary of location and aggregate fair value of all derivative financial instruments recorded in the consolidated statements of operations | The following table summarizes the location and aggregate gain (loss) of all derivative financial instruments recorded in the consolidated statements of operations for the periods presented (in thousands). Year Ended December 31, Type of Instrument Location in Statements of Operations 2021 2020 2019 Derivative Instrument Oil Revenues: Realized (loss) gain on derivatives $ (194,058) $ 38,937 $ 9,026 Natural Gas Revenues: Realized (loss) gain on derivatives (26,047) — 456 Realized (loss) gain on derivatives (220,105) 38,937 9,482 Oil Revenues: Unrealized gain (loss) on derivatives 26,857 (37,703) (53,443) Natural Gas Revenues: Unrealized (loss) gain on derivatives (5,846) 5,695 (284) Unrealized gain (loss) on derivatives 21,011 (32,008) (53,727) Total $ (199,094) $ 6,929 $ (44,245) |
Fair Value Measurements (Tables
Fair Value Measurements (Tables) | 12 Months Ended |
Dec. 31, 2021 | |
Fair Value Disclosures [Abstract] | |
Summary of the valuation of the Company's financial assets and liabilities that were accounted for at fair value on a recurring basis | The following tables summarize the valuation of the Company’s financial assets and liabilities that were accounted for at fair value on a recurring basis in accordance with the classifications provided above as of December 31, 2021 and 2020 (in thousands). Fair Value Measurements at Description Level 1 Level 2 Level 3 Total Assets (Liabilities) Oil derivatives and basis swaps $ — $ (14,727) $ — $ (14,727) Natural gas derivatives — (151) — (151) Contingent consideration related to business combination — — (8,203) (8,203) Total $ — $ (14,878) $ (8,203) $ (23,081) Fair Value Measurements at Description Level 1 Level 2 Level 3 Total Assets (Liabilities) Oil derivatives and basis swaps $ — $ (41,584) $ — $ (41,584) Natural gas derivatives — 5,695 — 5,695 Total $ — $ (35,889) $ — $ (35,889) |
Supplemental Disclosures (Table
Supplemental Disclosures (Tables) | 12 Months Ended |
Dec. 31, 2021 | |
Supplemental Disclosures [Abstract] | |
Summary of current accrued liabilities | The following table summarizes the Company’s current accrued liabilities at December 31, 2021 and 2020 (in thousands). December 31, 2021 2020 Accrued evaluated and unproved and unevaluated property costs $ 128,598 $ 44,012 Accrued midstream properties costs 7,799 12,776 Accrued lease operating expenses 32,182 24,276 Accrued interest on debt 18,232 18,315 Accrued asset retirement obligations 270 623 Accrued partners’ share of joint interest charges 17,460 7,407 Accrued payable related to purchased natural gas 11,284 418 Other 37,458 11,331 Total accrued liabilities $ 253,283 $ 119,158 |
Supplemental disclosures of cash flow information | The following table provides supplemental disclosures of cash flow information for the years ended December 31, 2021, 2020 and 2019 (in thousands). Year Ended December 31, 2021 2020 2019 Cash paid for interest expense, net of amounts capitalized $ 74,843 $ 76,880 $ 75,525 Increase (decrease) in asset retirement obligations related to mineral properties $ 1,091 $ (208) $ 2,912 Increase in asset retirement obligations related to midstream properties $ 257 $ 690 $ 1,204 Increase (decrease) in liabilities for drilling, completion and equipping capital expenditures $ 80,255 $ (26,126) $ (13,310) Increase (decrease) increase in liabilities for acquisition of oil and natural gas properties $ 2,981 $ (2,346) $ (2,567) (Decrease) increase in liabilities for midstream capital expenditures $ (4,478) $ (33,609) $ 30,374 Stock-based compensation expense recognized as liability $ 24,494 $ 3,702 $ 3,170 Transfer of inventory (to) from oil and natural gas properties $ (398) $ 608 $ 1,515 The following table provides a reconciliation of cash and restricted cash recorded in the consolidated balance sheets to cash and restricted cash as presented on the consolidated statements of cash flows (in thousands). Year Ended December 31, 2021 2020 2019 Cash $ 48,135 $ 57,916 $ 40,024 Restricted cash 38,785 33,467 25,104 Total cash and restricted cash $ 86,920 $ 91,383 $ 65,128 |
Segment Reporting (Tables)
Segment Reporting (Tables) | 12 Months Ended |
Dec. 31, 2020 | |
Segment Reporting [Abstract] | |
Schedule of Segment Reporting Information, by Segment | The following tables present selected financial information for the periods presented regarding the Company’s business segments on a stand-alone basis, corporate expenses that are not allocated to a segment and the consolidation and elimination entries necessary to arrive at the financial information for the Company on a consolidated basis (in thousands). On a consolidated basis, midstream services revenues consist primarily of those revenues from midstream operations related to third parties, including working interest owners in the Company’s operated wells. All midstream services revenues associated with Company-owned production are eliminated in consolidation. In evaluating the operating results of the exploration and production and midstream segments, the Company does not allocate certain expenses to the individual segments, including general and administrative expenses. Such expenses are reflected in the column labeled “Corporate.” Exploration and Production Consolidations and Eliminations Consolidated Company Midstream Corporate Year Ended December 31, 2021 Oil and natural gas revenues $ 1,695,032 $ 5,510 $ — $ — $ 1,700,542 Midstream services revenues — 228,817 — (153,318) 75,499 Sales of purchased natural gas 47,398 38,636 — — 86,034 Realized loss on derivatives (220,105) — — — (220,105) Unrealized gain on derivatives 21,011 — — — 21,011 Expenses (1) 794,880 142,444 85,899 (153,318) 869,905 Operating income (2) $ 748,456 $ 130,519 $ (85,899) $ — $ 793,076 Total assets (3) $ 3,324,681 $ 879,672 $ 57,800 $ — $ 4,262,153 Capital expenditures (4) $ 778,191 $ 59,361 $ 376 $ — $ 837,928 _____________________ (1) Includes depletion, depreciation and amortization expenses of $310.9 million and $31.5 million for the exploration and production and midstream segments, respectively. Also includes corporate depletion, depreciation and amortization expenses of $2.6 million. (2) Includes $55.7 million in net income attributable to non-controlling interest in subsidiaries related to the midstream segment. (3) Excludes intercompany receivables and investments in subsidiaries. (4) Includes $263.5 million attributable to land and seismic acquisition expenditures related to the exploration and production segment and $28.5 million in capital expenditures attributable to non-controlling interest in subsidiaries related to the midstream segment. Exploration and Production Consolidations and Eliminations Consolidated Company Midstream Corporate Year Ended December 31, 2020 Oil and natural gas revenues $ 741,092 $ 3,369 $ — $ — $ 744,461 Midstream services revenues — 166,194 — (101,262) 64,932 Sales of purchased natural gas 20,736 21,006 — — 41,742 Lease bonus - mineral acreage 4,062 — — — 4,062 Realized gain on derivatives 38,937 — — — 38,937 Unrealized loss on derivatives (32,008) — — — (32,008) Expenses (1) 1,334,378 97,599 52,910 (101,262) 1,383,625 Operating (loss) income (2) $ (561,559) $ 92,970 $ (52,910) $ — $ (521,499) Total assets (3) $ 2,782,819 $ 836,509 $ 67,952 $ — $ 3,687,280 Capital expenditures (4) $ 518,198 $ 201,440 $ 2,200 $ — $ 721,838 _____________________ (1) Includes depletion, depreciation and amortization expenses of $335.8 million and $23.3 million for the exploration and production and midstream segments, respectively. Includes full-cost ceiling impairment of $684.7 million for the exploration and production segment. Also includes corporate depletion, depreciation and amortization expenses of $2.7 million. (2) Includes $39.6 million in net income attributable to non-controlling interest in subsidiaries related to the midstream segment. (3) Excludes intercompany receivables and investments in subsidiaries. (4) Includes $70.5 million attributable to land and seismic acquisition expenditures related to the exploration and production segment and $112.1 million in capital expenditures attributable to non-controlling interest in subsidiaries related to the midstream segment. Exploration and Production Consolidations and Eliminations Consolidated Company Midstream Corporate Year Ended December 31, 2019 Oil and natural gas revenues $ 886,127 $ 6,198 $ — $ — $ 892,325 Midstream services revenues — 135,953 — (76,843) 59,110 Sales of purchased natural gas 4,802 69,967 — — 74,769 Lease bonus - mineral acreage 1,711 — — — 1,711 Realized gain on derivatives 9,482 — — — 9,482 Unrealized loss on derivatives (53,727) — — — (53,727) Expenses (1) 621,687 130,612 72,734 (76,843) 748,190 Operating income (loss) (2) $ 226,708 $ 81,506 $ (72,734) $ — $ 235,480 Total assets (3) $ 3,360,725 $ 647,937 $ 61,014 $ — $ 4,069,676 Capital expenditures (4) $ 718,712 $ 223,612 $ 3,701 $ — $ 946,025 _____________________ (1) Includes depletion, depreciation and amortization expenses of $331.7 million and $16.1 million for the exploration and production and midstream segments, respectively. Also includes corporate depletion, depreciation and amortization expenses of $2.7 million. (2) Includes $35.2 million in net income attributable to non-controlling interest in subsidiaries related to the midstream segment. (3) Excludes intercompany receivables and investments in subsidiaries. (4) Includes $48.3 million attributable to land and seismic acquisition expenditures related to the exploration and production segment and $145.4 million in capital expenditures attributable to non-controlling interest in subsidiaries related to the midstream segment. |
Summary of Significant Accoun_4
Summary of Significant Accounting Policies Summary of Significant Accounting Policies (Details Textual) | 12 Months Ended | |||||||||||||||||
Dec. 31, 2021USD ($) | Dec. 31, 2021USD ($) | Dec. 31, 2021USD ($)purchaser | Dec. 31, 2021USD ($) | Dec. 31, 2021USD ($)$ / bbl | Dec. 31, 2021USD ($)$ / MMBTU | Dec. 31, 2020USD ($) | Dec. 31, 2020USD ($)purchaser | Dec. 31, 2020USD ($) | Dec. 31, 2020USD ($)$ / bbl | Dec. 31, 2020USD ($)$ / MMBTU | Dec. 31, 2020USD ($)shares | Dec. 31, 2019USD ($) | Dec. 31, 2019purchaser | Dec. 31, 2019 | Dec. 31, 2019$ / bbl | Dec. 31, 2019$ / MMBTU | Dec. 31, 2019shares | |
Revenue, Initial Application Period Cumulative Effect Transition [Line Items] | ||||||||||||||||||
Billing date | 30 days | |||||||||||||||||
Outstanding days of account receivable | 60 days | |||||||||||||||||
Allowance for doubtful accounts | $ 0 | $ 0 | $ 0 | $ 0 | $ 0 | $ 0 | $ 0 | $ 0 | $ 0 | $ 0 | $ 0 | $ 0 | ||||||
Number of purchasers | purchaser | 3 | 2 | 2 | |||||||||||||||
Capitalized general and administrative costs | 38,400,000 | 30,000,000 | $ 31,100,000 | |||||||||||||||
Capitalized interest expense | 4,800,000 | 5,000,000 | 7,600,000 | |||||||||||||||
Depletion | (310,100,000) | (334,800,000) | (330,700,000) | |||||||||||||||
Previous period used for price calculation | 12 months | |||||||||||||||||
Present value discounted percent of future net revenues of proved oil and natural gas reserves | 10.00% | |||||||||||||||||
Average oil and natural gas prices | 63.04 | 3.60 | 36.04 | 1.99 | 52.19 | 2.58 | ||||||||||||
Impairment charge of net capitalized costs | 0 | 684,743,000 | 0 | |||||||||||||||
Stock-based compensation (non-cash) expense | 9,039,000 | 13,625,000 | 18,505,000 | |||||||||||||||
Common stock and restricted stock unit expense | 900,000 | 1,000,000 | 1,400,000 | |||||||||||||||
Compensation expense, liability-based awards | 20,400,000 | 4,000,000 | 3,200,000 | |||||||||||||||
Minimum | ||||||||||||||||||
Revenue, Initial Application Period Cumulative Effect Transition [Line Items] | ||||||||||||||||||
Accounts receivable due period | 30 days | |||||||||||||||||
Contract term after production | 1 month | |||||||||||||||||
Maximum | ||||||||||||||||||
Revenue, Initial Application Period Cumulative Effect Transition [Line Items] | ||||||||||||||||||
Accounts receivable due period | 60 days | |||||||||||||||||
Contract term after production | 2 months | |||||||||||||||||
Plains Marketing, L.P. | Customer Concentration Risk | Sales Revenue, Goods, Net | ||||||||||||||||||
Revenue, Initial Application Period Cumulative Effect Transition [Line Items] | ||||||||||||||||||
Concentration risk, percentage | 29.00% | 57.00% | 53.00% | |||||||||||||||
Plains Marketing, L.P. | Customer Concentration Risk | Accounts Receivable | ||||||||||||||||||
Revenue, Initial Application Period Cumulative Effect Transition [Line Items] | ||||||||||||||||||
Concentration risk, percentage | 39.00% | |||||||||||||||||
BP America Production Company | Customer Concentration Risk | Sales Revenue, Goods, Net | ||||||||||||||||||
Revenue, Initial Application Period Cumulative Effect Transition [Line Items] | ||||||||||||||||||
Concentration risk, percentage | 10.00% | 14.00% | ||||||||||||||||
BP America Production Company | Customer Concentration Risk | Accounts Receivable | ||||||||||||||||||
Revenue, Initial Application Period Cumulative Effect Transition [Line Items] | ||||||||||||||||||
Concentration risk, percentage | 31.00% | |||||||||||||||||
Exxon Mobil Corporate | Customer Concentration Risk | Sales Revenue, Goods, Net | ||||||||||||||||||
Revenue, Initial Application Period Cumulative Effect Transition [Line Items] | ||||||||||||||||||
Concentration risk, percentage | 33.00% | 8.00% | ||||||||||||||||
Exxon Mobil Corporate | Customer Concentration Risk | Accounts Receivable | ||||||||||||||||||
Revenue, Initial Application Period Cumulative Effect Transition [Line Items] | ||||||||||||||||||
Concentration risk, percentage | 35.00% | |||||||||||||||||
Two Significant Customers | Customer Concentration Risk | Sales Revenue, Goods, Net | ||||||||||||||||||
Revenue, Initial Application Period Cumulative Effect Transition [Line Items] | ||||||||||||||||||
Concentration risk, percentage | 65.00% | 67.00% | ||||||||||||||||
Three Significant Customers | Customer Concentration Risk | Sales Revenue, Goods, Net | ||||||||||||||||||
Revenue, Initial Application Period Cumulative Effect Transition [Line Items] | ||||||||||||||||||
Concentration risk, percentage | 72.00% | |||||||||||||||||
Machinery and Equipment | ||||||||||||||||||
Revenue, Initial Application Period Cumulative Effect Transition [Line Items] | ||||||||||||||||||
Capitalized general and administrative costs | $ 1,300,000 | 1,800,000 | 1,800,000 | |||||||||||||||
Capitalized interest expense | $ 500,000 | $ 900,000 | ||||||||||||||||
Useful life using the straight-line | 30 years | |||||||||||||||||
Machinery and Equipment | Minimum | ||||||||||||||||||
Revenue, Initial Application Period Cumulative Effect Transition [Line Items] | ||||||||||||||||||
Useful life | 5 years | |||||||||||||||||
Machinery and Equipment | Maximum | ||||||||||||||||||
Revenue, Initial Application Period Cumulative Effect Transition [Line Items] | ||||||||||||||||||
Useful life | 30 years | |||||||||||||||||
Employee Stock Options | ||||||||||||||||||
Revenue, Initial Application Period Cumulative Effect Transition [Line Items] | ||||||||||||||||||
Antidilutive options excluded from calculation (in shares) | shares | 2,500,000 | 2,600,000 | ||||||||||||||||
Restricted Stock | ||||||||||||||||||
Revenue, Initial Application Period Cumulative Effect Transition [Line Items] | ||||||||||||||||||
Antidilutive options excluded from calculation (in shares) | shares | 700,000 |
Summary of Significant Accoun_5
Summary of Significant Accounting Policies - Earnings Per Share (Details) - USD ($) $ / shares in Units, shares in Thousands, $ in Thousands | 12 Months Ended | ||
Dec. 31, 2021 | Dec. 31, 2020 | Dec. 31, 2019 | |
Accounting Policies [Abstract] | |||
Net income (loss) attributable to Matador Resources Company shareholders — numerator | $ 584,968 | $ (593,205) | $ 87,777 |
Weighted average common shares outstanding — denominator | |||
Basic (in shares) | 116,999 | 116,068 | 116,555 |
Dilutive effect of options and restricted stock units (in shares) | 2,164 | 0 | 508 |
Diluted weighted average common shares outstanding (in shares) | 119,163 | 116,068 | 117,063 |
Earnings (loss) per common share attributable to Matador Resources Company shareholders | |||
Basic (usd per share) | $ 5 | $ (5.11) | $ 0.75 |
Diluted (usd per share) | $ 4.91 | $ (5.11) | $ 0.75 |
Summary of Significant Accoun_6
Summary of Significant Accounting Policies Summary of Significant Accounting Policies - Disaggregated Revenue (Details) - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2021 | Dec. 31, 2020 | Dec. 31, 2019 | |
Disaggregation of Revenue [Line Items] | |||
Revenue from contract with customer | $ 1,862,075 | $ 851,135 | $ 1,026,204 |
Lease bonus - mineral acreage | 0 | 4,062 | 1,711 |
Realized gain on derivatives | (220,105) | 38,937 | 9,482 |
Unrealized gain on derivatives | 21,011 | (32,008) | (53,727) |
Total revenues | 1,662,981 | 862,126 | 983,670 |
Oil | |||
Disaggregation of Revenue [Line Items] | |||
Revenue from contract with customer | 1,205,608 | 595,507 | 759,811 |
Natural gas revenues | |||
Disaggregation of Revenue [Line Items] | |||
Revenue from contract with customer | 494,934 | 148,954 | 132,514 |
Third-party midstream services revenues | |||
Disaggregation of Revenue [Line Items] | |||
Revenue from contract with customer | 75,499 | 64,932 | 59,110 |
Sales of purchased natural gas | |||
Disaggregation of Revenue [Line Items] | |||
Revenue from contract with customer | $ 86,034 | $ 41,742 | $ 74,769 |
Property and Equipment (Details
Property and Equipment (Details) - USD ($) $ in Thousands | Dec. 31, 2021 | Dec. 31, 2020 |
Oil and natural gas properties | ||
Evaluated (subject to amortization) | $ 6,007,325 | $ 5,295,931 |
Total unproved and unevaluated | 964,714 | 902,133 |
Total oil and natural gas properties | 6,972,039 | 6,198,064 |
Accumulated depletion | (3,933,355) | (3,623,265) |
Net oil and natural gas properties | 3,038,684 | 2,574,799 |
Midstream Properties [Abstract] | ||
Midstream properties | 900,979 | 841,695 |
Accumulated depreciation | 4,046,456 | 3,701,551 |
Other property and equipment | ||
Other property and equipment | 30,123 | 29,561 |
Accumulated depreciation | (20,527) | (17,173) |
Net other property and equipment | 9,596 | 12,388 |
Net property and equipment | 3,856,685 | 3,367,769 |
Midstream equipment and facilities | ||
Midstream Properties [Abstract] | ||
Midstream properties | 900,979 | 841,695 |
Accumulated depreciation | 92,574 | 61,113 |
Net midstream properties | 808,405 | 780,582 |
Furniture, fixtures and other equipment | ||
Other property and equipment | ||
Other property and equipment | 10,923 | 10,591 |
Software | ||
Other property and equipment | ||
Other property and equipment | 8,225 | 8,116 |
Leasehold improvements | ||
Other property and equipment | ||
Other property and equipment | $ 10,975 | $ 10,854 |
Property and Equipment (Detai_2
Property and Equipment (Details 1) - USD ($) $ in Thousands | Dec. 31, 2021 | Dec. 31, 2020 | Dec. 31, 2019 | Dec. 31, 2018 |
Costs incurred for | ||||
Total unproved and unevaluated | $ 964,714 | $ 902,133 | ||
2021 | ||||
Costs incurred for | ||||
Property acquisition | 111,120 | |||
Exploration wells | 14,738 | |||
Development wells | 46,232 | |||
Total unproved and unevaluated | 172,090 | |||
2020 | ||||
Costs incurred for | ||||
Property acquisition | 40,355 | |||
Exploration wells | 411 | |||
Development wells | 2,027 | |||
Total unproved and unevaluated | $ 42,793 | |||
2019 | ||||
Costs incurred for | ||||
Property acquisition | $ 40,140 | |||
Exploration wells | 1,199 | |||
Development wells | 3,245 | |||
Total unproved and unevaluated | 44,584 | |||
2018 | ||||
Costs incurred for | ||||
Property acquisition | 417,114 | |||
Exploration wells | 123 | |||
Development wells | 60 | |||
Total unproved and unevaluated | $ 417,297 | |||
2017 and prior | ||||
Costs incurred for | ||||
Property acquisition | $ 287,666 | |||
Exploration wells | 274 | |||
Development wells | 10 | |||
Total unproved and unevaluated | $ 287,950 | |||
Total | ||||
Costs incurred for | ||||
Property acquisition | 896,395 | |||
Exploration wells | 16,745 | |||
Development wells | 51,574 | |||
Total unproved and unevaluated | $ 964,714 |
Property and Equipment (Detai_3
Property and Equipment (Details Textual) $ in Thousands | Dec. 31, 2021USD ($) |
Property, Plant and Equipment [Line Items] | |
Anticipated amount for wells | $ 68,300 |
Projects Inception to Date | |
Property, Plant and Equipment [Line Items] | |
Exploration costs | 16,745 |
Development wells | $ 51,574 |
Leases - Narrative (Details)
Leases - Narrative (Details) | Dec. 31, 2021 |
Leases [Abstract] | |
Incremental borrowing rate, operating leases | 2.73% |
Incremental borrowing rate, finance leases | 1.99% |
Leases - Components of Lease Ex
Leases - Components of Lease Expense (Details) - USD ($) $ in Thousands | 12 Months Ended | |
Dec. 31, 2021 | Dec. 31, 2020 | |
Lessee, Lease, Description [Line Items] | ||
Operating leases | $ 15,074 | $ 16,720 |
Short-term leases | 15,308 | 18,626 |
Financing leases | ||
Depreciation of assets | 566 | 747 |
Interest on lease liabilities | 138 | 123 |
Total financing leases | 704 | 870 |
Total lease expense | 31,086 | 36,216 |
Lease operating | ||
Lessee, Lease, Description [Line Items] | ||
Operating leases | 11,393 | 12,994 |
Short-term leases | 11,234 | 12,890 |
Plant and other midstream services | ||
Lessee, Lease, Description [Line Items] | ||
Operating leases | 36 | 28 |
Short-term leases | 4,037 | 5,689 |
General and administrative | ||
Lessee, Lease, Description [Line Items] | ||
Operating leases | 3,645 | 3,698 |
Short-term leases | 37 | 47 |
Drilling Rig Leases | ||
Financing leases | ||
Gross payments | 31,900 | 33,600 |
Drilling Rig Leases And Other Equipment Rentals | ||
Financing leases | ||
Gross payments | $ 61,700 | $ 65,300 |
Leases - Balance Sheet Informat
Leases - Balance Sheet Information (Details) - USD ($) $ in Thousands | Dec. 31, 2021 | Dec. 31, 2020 |
Operating leases | ||
Right-of-use asset | $ 29,519 | $ 51,528 |
Other current liabilities | $ (19,649) | $ (35,716) |
Operating Lease, Liability, Current, Statement of Financial Position [Extensible List] | Other Liabilities, Current | Other Liabilities, Current |
Other long-term liabilities | $ (15,340) | $ (21,598) |
Operating Lease, Liability, Noncurrent, Statement of Financial Position [Extensible List] | Other Liabilities, Noncurrent | Other Liabilities, Noncurrent |
Total operating lease liabilities | $ (34,989) | $ (57,314) |
Financing leases | ||
Other property and equipment, at cost | 5,914 | 3,673 |
Accumulated depreciation | $ (3,485) | $ (2,134) |
Finance Lease, Right-of-Use Asset, Statement of Financial Position [Extensible Enumeration] | Property, Plant and Equipment, Net | Property, Plant and Equipment, Net |
Net property and equipment | $ 2,429 | $ 1,539 |
Finance Lease, Liability, Current, Statement of Financial Position [Extensible List] | Other Liabilities, Current | Other Liabilities, Current |
Other current liabilities | $ (378) | $ (621) |
Finance Lease, Liability, Noncurrent, Statement of Financial Position [Extensible List] | Other Liabilities, Noncurrent | Other Liabilities, Noncurrent |
Other long-term liabilities | $ (45) | $ (256) |
Total financing lease liabilities | $ (423) | $ (877) |
Operating Lease, Right-of-Use Asset, Statement of Financial Position [Extensible List] | Other Assets, Noncurrent | Other Assets, Noncurrent |
Leases - Cash Flow Information
Leases - Cash Flow Information (Details) - USD ($) $ in Thousands | 12 Months Ended | |
Dec. 31, 2021 | Dec. 31, 2020 | |
Cash paid related to lease liabilities | ||
Operating cash payments for operating leases | $ 14,430 | $ 15,664 |
Investing cash payments for operating leases | 31,967 | 33,556 |
Financing cash payments for financing leases | 629 | 790 |
Right of use assets obtained in exchange for lease obligations entered into during the period | ||
Operating leases | 18,454 | 12,474 |
Financing leases | $ 2,241 | $ 996 |
Leases - Lease Terms (Details)
Leases - Lease Terms (Details) | Dec. 31, 2021 |
Weighted-Average Remaining Lease Term | |
Operating leases | 2 years 6 months |
Financing leases | 1 year 8 months 12 days |
Leases - Lease Payment Maturity
Leases - Lease Payment Maturity Schedule (Details) - USD ($) $ in Thousands | Dec. 31, 2021 | Dec. 31, 2020 |
Operating Leases | ||
2021 | $ 19,649 | |
2022 | 6,830 | |
2024 | 4,287 | |
2025 | 1,553 | |
Thereafter | 0 | |
Total lease payments | 36,536 | |
Less imputed interest | (1,547) | |
Lease liability | 34,989 | $ 57,314 |
Less current obligations | (19,649) | (35,716) |
Long-term lease obligations | 15,340 | 21,598 |
Financing Leases | ||
2021 | 378 | |
2022 | 180 | |
2023 | 37 | |
2024 | 0 | |
2025 | 0 | |
Thereafter | 0 | |
Total lease payments | 595 | |
Less imputed interest | (172) | |
Total lease obligations | 423 | 877 |
Less current obligations | (378) | (621) |
Long-term lease obligations | 45 | $ 256 |
2022 | $ 4,217 |
Leases Leases - Maturities of O
Leases Leases - Maturities of Office Leases (Details) $ in Thousands | Dec. 31, 2021USD ($) |
Leases [Abstract] | |
2021 | $ 19,649 |
2022 | 6,830 |
2022 | 4,217 |
2024 | 4,287 |
2025 | 1,553 |
Thereafter | 0 |
Total lease payments | $ 36,536 |
Asset Retirement Obligations (D
Asset Retirement Obligations (Details) - USD ($) $ in Thousands | 12 Months Ended | |
Dec. 31, 2021 | Dec. 31, 2020 | |
Changes in the Company's asset retirement obligations | ||
Beginning asset retirement obligations | $ 38,542 | $ 36,211 |
Liabilities incurred during period | 2,294 | 2,548 |
Liabilities settled during period | (151) | (290) |
Revisions in estimated cash flows | 86 | (1,875) |
Divestitures during the period | (880) | 0 |
Accretion expense | 2,068 | 1,948 |
Ending asset retirement obligations | 41,959 | 38,542 |
Less: current asset retirement obligations | (270) | (623) |
Long-term asset retirement obligations | $ 41,689 | $ 37,919 |
Business Combinations and Div_2
Business Combinations and Divestitures (Details) $ in Thousands | Dec. 15, 2021USD ($) | Dec. 14, 2021USD ($)Boe$ / bbl | Feb. 23, 2021USD ($) | Feb. 25, 2019USD ($) | Feb. 17, 2017USD ($)well | Dec. 31, 2021USD ($) | Mar. 31, 2019USD ($) | Dec. 31, 2021USD ($) | Dec. 31, 2021USD ($)$ / bbl | Dec. 31, 2021USD ($)$ / MMBTU | Dec. 31, 2020USD ($) | Dec. 31, 2020USD ($)$ / bbl | Dec. 31, 2020USD ($)$ / MMBTU | Dec. 31, 2019USD ($) | Dec. 31, 2019USD ($)$ / bbl | Dec. 31, 2019USD ($)$ / MMBTU | Feb. 23, 2021USD ($) |
Business Acquisition [Line Items] | |||||||||||||||||
Oil and Gas, average sale price | 63.04 | 3.60 | 36.04 | 1.99 | 52.19 | 2.58 | |||||||||||
Distributions to noncontrolling interest holders | $ 61,985 | $ 45,570 | $ 39,200 | ||||||||||||||
Additional paid-in capital | $ 2,077,592 | 2,077,592 | $ 2,077,592 | $ 2,077,592 | 2,027,069 | $ 2,027,069 | $ 2,027,069 | ||||||||||
Proceeds from divestiture of businesses | 4,200 | 4,800 | |||||||||||||||
Proceeds from sale of assets | 4,215 | 4,789 | 21,921 | ||||||||||||||
Noncontrolling Interest | |||||||||||||||||
Business Acquisition [Line Items] | |||||||||||||||||
Distributions to noncontrolling interest holders | 61,985 | 45,570 | 39,200 | ||||||||||||||
Properties in Lea and Eddy, NM | |||||||||||||||||
Business Acquisition [Line Items] | |||||||||||||||||
Consideration transferred | $ 161,700 | ||||||||||||||||
Business combination, working capital adjustment | 6,500 | ||||||||||||||||
Purchase price increase (decrease) due to average oil price | 5,000 | ||||||||||||||||
Fair value of contingent consideration at December 14, 2021 | $ 6,718 | 1,500 | 1,500 | $ 1,500 | $ 1,500 | ||||||||||||
Barrels of oil per day | Boe | 3,500 | ||||||||||||||||
Properties in Lea and Eddy, NM | Minimum | |||||||||||||||||
Business Acquisition [Line Items] | |||||||||||||||||
Oil and Gas, average sale price | $ / bbl | 75 | ||||||||||||||||
Properties in Lea and Eddy, NM | Pro Forma | |||||||||||||||||
Business Acquisition [Line Items] | |||||||||||||||||
Asset acquisition, pro forma revenue | $ 4,000 | $ 3,200 | |||||||||||||||
San Mateo Midstream | |||||||||||||||||
Business Acquisition [Line Items] | |||||||||||||||||
Proceeds from joint venture | 64,500 | 47,400 | |||||||||||||||
Corporate Joint Venture | San Mateo Midstream | |||||||||||||||||
Business Acquisition [Line Items] | |||||||||||||||||
Subsidiary ownership percentage | 51.00% | ||||||||||||||||
Number of wells contributed to joint venture | well | 14 | ||||||||||||||||
Deferred performance incentives | $ 150,000 | $ 73,500 | |||||||||||||||
Deferred performance incentives, term | 5 years | ||||||||||||||||
Amount earned from potential earnout | $ 58,800 | ||||||||||||||||
Remaining performance incentives available to be earned, up to | $ 14,700 | ||||||||||||||||
Five Point | |||||||||||||||||
Business Acquisition [Line Items] | |||||||||||||||||
Proceeds from joint venture | $ 33,900 | ||||||||||||||||
Five Point | Corporate Joint Venture | San Mateo Midstream | |||||||||||||||||
Business Acquisition [Line Items] | |||||||||||||||||
Subsidiary ownership percentage | 49.00% | 49.00% | 49.00% | 49.00% | |||||||||||||
Payments for deferred performance incentives | $ 14,700 | ||||||||||||||||
Rustler Breaks and Wolf Asset Area | Corporate Joint Venture | San Mateo Midstream | |||||||||||||||||
Business Acquisition [Line Items] | |||||||||||||||||
Contractual obligation, term | 15 years | ||||||||||||||||
Rustler Breaks Asset Area | Corporate Joint Venture | San Mateo Midstream | |||||||||||||||||
Business Acquisition [Line Items] | |||||||||||||||||
Contractual obligation, term | 15 years | ||||||||||||||||
San Mateo Midstream | Five Point | Corporate Joint Venture | |||||||||||||||||
Business Acquisition [Line Items] | |||||||||||||||||
Contributions to joint venture | 119,700 | 77,300 | |||||||||||||||
Additional paid-in capital | 23,100 | $ 23,100 | $ 23,100 | 28,400 | $ 28,400 | $ 28,400 | |||||||||||
Tax impact of equity contribution | 4,800 | 5,900 | |||||||||||||||
San Mateo Midstream | Matador Resources Company | Corporate Joint Venture | |||||||||||||||||
Business Acquisition [Line Items] | |||||||||||||||||
Contributions to joint venture | $ 75,000 | $ 24,200 | |||||||||||||||
San Mateo Midstream | Property Contribution [Member] | Matador Resources Company | Corporate Joint Venture | |||||||||||||||||
Business Acquisition [Line Items] | |||||||||||||||||
Contributions to joint venture | $ 1,000 |
Business Combinations and Div_3
Business Combinations and Divestitures - Allocation Schedule (Details) - USD ($) $ in Thousands | Dec. 31, 2021 | Dec. 14, 2021 | Dec. 31, 2020 |
Business Acquisition [Line Items] | |||
Evaluated (subject to amortization) | $ 6,007,325 | $ 5,295,931 | |
Total unproved and unevaluated | 964,714 | 902,133 | |
Advances from joint interest owners | (18,074) | $ (4,191) | |
Properties in Lea and Eddy, NM | |||
Business Acquisition [Line Items] | |||
Cash | $ 161,680 | ||
Fair value of contingent consideration at December 14, 2021 | $ 1,500 | 6,718 | |
Total consideration given | 174,898 | ||
Evaluated (subject to amortization) | 139,312 | ||
Total unproved and unevaluated | 43,204 | ||
Contingent consideration related to business combination | (360) | ||
Advances from joint interest owners | (6,865) | ||
Asset retirement obligations | $ (393) |
Debt Credit Agreements (Details
Debt Credit Agreements (Details Textual) (Details) - USD ($) | Dec. 19, 2018 | Feb. 23, 2021 | Dec. 31, 2021 | Dec. 31, 2020 | Dec. 31, 2019 | Nov. 30, 2021 | Nov. 18, 2021 | Nov. 01, 2021 | Jun. 30, 2021 | Oct. 30, 2020 | Oct. 31, 2019 |
Debt Instrument [Line Items] | |||||||||||
Borrowings under credit agreement | $ 100,000,000 | $ 440,000,000 | |||||||||
Secured debt, percentage of mortgages used as security | 85.00% | ||||||||||
Repay deficit in agreement, period | 6 months | ||||||||||
Deferred loan costs | $ 3,900,000 | ||||||||||
Repayment of borrowings | $ 600,000,000 | $ 35,000,000 | $ 35,000,000 | ||||||||
Repayments of borrowings | $ 25,000,000 | ||||||||||
Debt instrument, interest rate, increase (decrease) | 0.50% | ||||||||||
Third Amended Credit Agreement | |||||||||||
Debt Instrument [Line Items] | |||||||||||
Effective interest rate | 1.85% | ||||||||||
EBITDA ratio, debt outstanding, cash and cash equivalents limit | $ 75,000,000 | ||||||||||
Debt to EBITDA ratio covenant | 3.50 | ||||||||||
Third Amended Credit Agreement | Minimum | |||||||||||
Debt Instrument [Line Items] | |||||||||||
Commitment fee percentage | 0.375% | ||||||||||
Third Amended Credit Agreement | Maximum | |||||||||||
Debt Instrument [Line Items] | |||||||||||
Commitment fee percentage | 0.50% | ||||||||||
San Mateo Credit Facility | |||||||||||
Debt Instrument [Line Items] | |||||||||||
Effective interest rate | 2.11% | ||||||||||
Eurodollar | Third Amended Credit Agreement | Minimum | |||||||||||
Debt Instrument [Line Items] | |||||||||||
Additional interest rate | 1.75% | ||||||||||
Eurodollar | Third Amended Credit Agreement | Maximum | |||||||||||
Debt Instrument [Line Items] | |||||||||||
Additional interest rate | 2.75% | ||||||||||
Federal Funds Effective Rate | Third Amended Credit Agreement | |||||||||||
Debt Instrument [Line Items] | |||||||||||
Basis spread on variable rate | 0.50% | ||||||||||
Base Rate Loan | Third Amended Credit Agreement | Maximum | |||||||||||
Debt Instrument [Line Items] | |||||||||||
Additional interest rate | 1.75% | ||||||||||
Unsecured Debt | SBA Loan, CARES Act [Member] | |||||||||||
Debt Instrument [Line Items] | |||||||||||
Long-term debt | $ 7,500,000 | ||||||||||
Revolving Credit Facility | |||||||||||
Debt Instrument [Line Items] | |||||||||||
Senior secured revolving credit maximum facility | $ 700,000,000 | ||||||||||
Revolving Credit Facility | Third Amended Credit Agreement | |||||||||||
Debt Instrument [Line Items] | |||||||||||
Increase in borrowing capacity | $ 1,350,000,000 | $ 900,000,000 | |||||||||
Maximum borrowing capacity, amended | $ 1,500,000,000 | ||||||||||
Line of Credit | Fourth Amended Credit Agreement | |||||||||||
Debt Instrument [Line Items] | |||||||||||
Long-term line of credit | $ 25,000,000 | ||||||||||
Line of Credit | San Mateo Credit Facility | |||||||||||
Debt Instrument [Line Items] | |||||||||||
Outstanding letters of credit | 9,000,000 | ||||||||||
Long-term line of credit | 385,000,000 | ||||||||||
Senior secured revolving credit maximum facility | $ 250,000,000 | $ 375,000,000 | |||||||||
Repayment of borrowings | $ 30,000,000 | ||||||||||
Accordian feature, increase limit | $ 700,000,000 | $ 450,000,000 | |||||||||
Deferred loan costs | 1,900,000 | ||||||||||
Line of Credit | San Mateo Credit Facility | Minimum | |||||||||||
Debt Instrument [Line Items] | |||||||||||
Commitment fee percentage | 0.30% | ||||||||||
Line of Credit | San Mateo Credit Facility | Maximum | |||||||||||
Debt Instrument [Line Items] | |||||||||||
Commitment fee percentage | 0.50% | ||||||||||
Letter of Credit | Credit Agreement | |||||||||||
Debt Instrument [Line Items] | |||||||||||
Outstanding letters of credit | $ 45,800,000 | ||||||||||
Libor Rate | Third Amended Credit Agreement | |||||||||||
Debt Instrument [Line Items] | |||||||||||
Basis spread on variable rate | 1.00% | ||||||||||
Base Rate Loan | Minimum | |||||||||||
Debt Instrument [Line Items] | |||||||||||
Additional interest rate | 0.75% | ||||||||||
Federal Funds Effective Rate | Line of Credit | San Mateo Credit Facility | |||||||||||
Debt Instrument [Line Items] | |||||||||||
Basis spread on variable rate | 0.50% | ||||||||||
Adjusted LIBO Rate | Line of Credit | San Mateo Credit Facility | |||||||||||
Debt Instrument [Line Items] | |||||||||||
Basis spread on variable rate | 1.00% | ||||||||||
Adjusted LIBO Rate | Line of Credit | San Mateo Credit Facility | Minimum | |||||||||||
Debt Instrument [Line Items] | |||||||||||
Additional interest rate | 1.00% | ||||||||||
Adjusted LIBO Rate | Line of Credit | San Mateo Credit Facility | Maximum | |||||||||||
Debt Instrument [Line Items] | |||||||||||
Additional interest rate | 2.00% | ||||||||||
Statutory Reserve Rate | Line of Credit | San Mateo Credit Facility | Minimum | |||||||||||
Debt Instrument [Line Items] | |||||||||||
Additional interest rate | 2.00% | ||||||||||
Statutory Reserve Rate | Line of Credit | San Mateo Credit Facility | Maximum | |||||||||||
Debt Instrument [Line Items] | |||||||||||
Additional interest rate | 3.00% | ||||||||||
The Bank Of Nova Scotia | San Mateo Credit Facility | |||||||||||
Debt Instrument [Line Items] | |||||||||||
Debt to EBITDA ratio covenant | 5 | ||||||||||
Interest coverage ratio | 2.50 |
Debt Senior Unsecured Notes (De
Debt Senior Unsecured Notes (Details Textual) (Details) - USD ($) | Oct. 04, 2018 | Dec. 31, 2021 | Dec. 31, 2020 |
Debt Instrument [Line Items] | |||
Borrowings under Credit Agreement | $ 100,000,000 | $ 440,000,000 | |
Unsecured Debt | Senior Notes | |||
Debt Instrument [Line Items] | |||
Long-term debt | $ 1,050,000,000 | ||
Unsecured Debt | 2026 Notes Offering | |||
Debt Instrument [Line Items] | |||
Stated interest rate | 5.875% | ||
Unsecured Debt | Additional 2026 Notes | Debt Instrument, Redemption, Period One | |||
Debt Instrument [Line Items] | |||
Threshold percentage of principle | 25.00% | ||
Default period | 30 days | ||
Period after notice to comply | 180 days | ||
Period after notice to comply with other agreements | 60 days | ||
Maximum aggregate payment defaults and accelerations | $ 50,000,000 | ||
Maximum outstanding judgments | $ 50,000,000 | ||
Maximum outstanding judgements, payment period | 60 days | ||
Unsecured Debt | Senior Notes Due 2026 | |||
Debt Instrument [Line Items] | |||
Long-term debt | $ 1,050,000,000 | ||
Unsecured Debt | Senior Notes Due 2026 | Debt Instrument, Redemption, Period Two | |||
Debt Instrument [Line Items] | |||
Debt redemption price, percentage | 104.406% |
Debt Debt Redemption (Details)
Debt Debt Redemption (Details) - Unsecured Debt - Senior Notes Due 2026 | Oct. 04, 2018 |
2021 | |
Debt Instrument [Line Items] | |
Redemption Price | 104.406% |
2022 | |
Debt Instrument [Line Items] | |
Redemption Price | 102.938% |
2023 | |
Debt Instrument [Line Items] | |
Redemption Price | 101.469% |
2024 and thereafter | |
Debt Instrument [Line Items] | |
Redemption Price | 100.00% |
Income Taxes (Details)
Income Taxes (Details) - USD ($) $ in Thousands | Dec. 31, 2021 | Dec. 31, 2020 |
Deferred tax assets | ||
Net operating loss carryforwards | $ 129,651 | $ 122,952 |
Unrealized loss on derivatives | 3,729 | 8,997 |
Percentage depletion carryover | 1,770 | 1,462 |
Compensation | 9,838 | 10,405 |
Lease liabilities | 4,866 | 9,380 |
Other | 9,410 | 8,334 |
Deferred Tax Assets, Gross | 159,264 | 161,530 |
Valuation allowance on deferred tax assets | (10,599) | (110,681) |
Total deferred tax assets, net of valuation allowance | 148,665 | 50,849 |
Deferred tax liabilities | ||
Property and equipment | (179,153) | (11,879) |
Less than wholly-owned subsidiaries | (39,900) | (26,564) |
Lease right of use assets | (4,866) | (9,380) |
Other | (2,684) | (2,684) |
Total deferred tax liabilities | (226,603) | (50,507) |
Net deferred tax (liabilities) assets | $ (77,938) | $ 342 |
Income Taxes (Details Textual)
Income Taxes (Details Textual) - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2021 | Dec. 31, 2020 | Dec. 31, 2019 | |
Operating Loss Carryforwards [Line Items] | |||
Full-cost ceiling impairment | $ 0 | $ 684,743 | $ 0 |
Internal Revenue Service (IRS) | |||
Operating Loss Carryforwards [Line Items] | |||
Operating loss carryforwards | 555,200 | ||
State and Local Jurisdiction | |||
Operating Loss Carryforwards [Line Items] | |||
Operating loss carryforwards | $ 223,300 |
Income Taxes (Details 1)
Income Taxes (Details 1) - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2021 | Dec. 31, 2020 | Dec. 31, 2019 | |
Deferred income tax provision (benefit) | |||
Federal income tax | $ 44,883 | $ (25,675) | $ 29,171 |
State income tax | 29,827 | (19,924) | 6,361 |
Net deferred income tax provision (benefit) | 74,710 | (45,599) | 35,532 |
Deferred income tax provision (benefit) | |||
Federal tax (benefit) expense at statutory rate | 150,223 | (125,823) | 33,441 |
State income tax | 26,646 | (20,607) | 6,141 |
Permanent differences | (2,078) | (3,114) | (4,267) |
Change in federal valuation allowance | (103,262) | 103,262 | 0 |
Change in state valuation allowance | 3,181 | 683 | 217 |
Net deferred income tax provision (benefit) | 74,710 | (45,599) | 35,532 |
Total income tax provision (benefit) | $ 74,710 | $ (45,599) | $ 35,532 |
Stock-Based Compensation (Detai
Stock-Based Compensation (Details) - USD ($) $ / shares in Units, $ in Millions | 12 Months Ended | ||
Dec. 31, 2021 | Dec. 31, 2020 | Dec. 31, 2019 | |
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||
Capitalized stock-based compensation | $ 7.2 | $ 3.6 | $ 5 |
Weighted average assumptions used to estimate fair value of stock options granted under the Stock and Incentive Plan | |||
Weighted average fair value of stock option awards granted during the year (in usd per share) | $ 5.04 | ||
2012 Incentive Plan | |||
Weighted average assumptions used to estimate fair value of stock options granted under the Stock and Incentive Plan | |||
Stock option pricing model | Black Scholes Merton | ||
Expected option life | 4 years | ||
Risk-free interest rate | 1.46% | ||
Volatility | 48.52% | ||
Dividend yield | 0.00% | ||
Estimated forfeiture rate | 4.43% |
Stock-Based Compensation (Det_2
Stock-Based Compensation (Details 1) shares in Thousands | 12 Months Ended |
Dec. 31, 2021$ / sharesshares | |
Number of options (in thousands) | |
Options outstanding at beginning of period (in shares) | shares | 2,473 |
Options granted (in shares) | shares | 0 |
Options exercised (in shares) | shares | (1,368) |
Options forfeited (in shares) | shares | (37) |
Options expired (in shares) | shares | (465) |
Options outstanding at end of period (in shares) | shares | 603 |
Weighted average exercise price | |
Weighted average exercise price, Options outstanding Beginning Balance (usd per share) | $ / shares | $ 23.08 |
Weighted average exercise price, Options granted (usd per share) | $ / shares | 0 |
Weighted average exercise price, Options exercised (usd per share) | $ / shares | 25.37 |
Weighted average exercise price, Options forfeited (usd per share) | $ / shares | 18.72 |
Weighted average exercise price, Options expired (usd per share) | $ / shares | 16.90 |
Weighted average exercise price, Options outstanding Ending Balance (usd per share) | $ / shares | $ 22.92 |
Stock-Based Compensation (Det_3
Stock-Based Compensation (Details 2) shares in Thousands | 12 Months Ended |
Dec. 31, 2021$ / sharesshares | |
$14.48 - $15.40 | |
Summarized information about outstanding and exercisable stock option | |
Range of exercise prices, lower limit (in usd per share) | $ 14.48 |
Range of exercise prices, upper limit (in usd per share) | $ 15.40 |
Shares outstanding (in shares) | shares | 240 |
Weighted average remaining contractual price | 3 years 7 months 28 days |
Weighted average exercise price (usd per share) | $ 14.80 |
Shares exercisable | shares | 82 |
Weighted average exercise price (usd per share) | $ 14.80 |
$26.86 - $29.68 | |
Summarized information about outstanding and exercisable stock option | |
Range of exercise prices, lower limit (in usd per share) | 26.86 |
Range of exercise prices, upper limit (in usd per share) | $ 29.68 |
Shares outstanding (in shares) | shares | 363 |
Weighted average remaining contractual price | 1 year 7 months 2 days |
Weighted average exercise price (usd per share) | $ 28.28 |
Shares exercisable | shares | 363 |
Weighted average exercise price (usd per share) | $ 28.28 |
Stock-Based Compensation (Det_4
Stock-Based Compensation (Details 3) - USD ($) $ / shares in Units, $ 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] | |||
Stock-based compensation expense | $ 9,039 | $ 13,625 | $ 18,505 |
Employee Stock Options | |||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||
Stock-based compensation expense | $ 1,000 | $ 3,400 | $ 6,400 |
Restricted Stock Service Based | |||
Summary of non-vested stock options | |||
Non-vested Shares, Beginning Balance (in shares) | 682,000 | ||
Shares Granted (in shares) | 283,000 | ||
Shares Vested (in shares) | (334,000) | ||
Shares Forfeited (in shares) | (42,000) | ||
Non-vested Shares, Ending Balance (in shares) | 589,000 | 682,000 | |
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Weighted Average Grant Date Fair Value [Abstract] | |||
Weighted average fair value, Beginning Balance (usd per share) | $ 20.01 | ||
Weighted average fair value, Granted (usd per share) | 37.56 | ||
Weighted average fair value, Vested (usd per share) | 27.14 | ||
Weighted average fair value, Forfeited (usd per share) | 17.35 | ||
Weighted average fair value, Ending Balance (usd per share) | $ 24.59 | $ 20.01 | |
Restricted Stock Units Service Based | |||
Summary of non-vested stock options | |||
Non-vested Shares, Beginning Balance (in shares) | 75,000 | ||
Shares Granted (in shares) | 36,000 | ||
Shares Vested (in shares) | (78,000) | ||
Shares Forfeited (in shares) | 0 | ||
Non-vested Shares, Ending Balance (in shares) | 33,000 | 75,000 | |
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Weighted Average Grant Date Fair Value [Abstract] | |||
Weighted average fair value, Beginning Balance (usd per share) | $ 8.85 | ||
Weighted average fair value, Granted (usd per share) | 30.97 | ||
Weighted average fair value, Vested (usd per share) | 9.02 | ||
Weighted average fair value, Forfeited (usd per share) | 0 | ||
Weighted average fair value, Ending Balance (usd per share) | $ 33.39 | $ 8.85 | |
Restricted Stock Units Performance Based | |||
Summary of non-vested stock options | |||
Non-vested Shares, Beginning Balance (in shares) | 1,069,000 | ||
Shares Granted (in shares) | 366,000 | ||
Shares Vested (in shares) | (397,000) | ||
Shares Forfeited (in shares) | (75,000) | ||
Non-vested Shares, Ending Balance (in shares) | 963,000 | 1,069,000 | |
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Weighted Average Grant Date Fair Value [Abstract] | |||
Weighted average fair value, Beginning Balance (usd per share) | $ 9.05 | ||
Weighted average fair value, Granted (usd per share) | 50.53 | ||
Weighted average fair value, Vested (usd per share) | 20 | ||
Weighted average fair value, Forfeited (usd per share) | 9.33 | ||
Weighted average fair value, Ending Balance (usd per share) | $ 20.26 | $ 9.05 | |
Restricted Stock Units Performance Based | 2019 Incentive Plan | |||
Summary of non-vested stock options | |||
Non-vested Shares, Ending Balance (in shares) | 396,827 | ||
Restricted Stock Units Performance Based | 2019 Incentive Plan | Maximum | |||
Summary of non-vested stock options | |||
Non-vested Shares, Ending Balance (in shares) | 793,654 |
Stock Based Compensation (Detai
Stock Based Compensation (Details 4) - Restricted Stock Liability Based - shares | 12 Months Ended | |
Dec. 31, 2021 | Dec. 31, 2020 | |
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ||
Non-vested Shares, Beginning Balance (in shares) | 1,319,000 | |
Shares Granted (in shares) | 357,000 | |
Shares Vested (in shares) | (487,252) | (226,363) |
Shares Forfeited (in shares) | (87,000) | |
Non-vested Shares, Ending Balance (in shares) | 1,102,000 | 1,319,000 |
Stock Based Compensation (Det_2
Stock Based Compensation (Details Textual) - USD ($) | 12 Months Ended | ||
Dec. 31, 2021 | Dec. 31, 2020 | Dec. 31, 2019 | |
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||
Maximum vesting period 1 | 5 years | ||
Maximum vesting period 2 | 6 years | ||
Maximum vesting period 3 | 10 years | ||
Fair value of stock option awards outstanding (in shares) | 603,000 | 2,473,000 | |
Aggregate intrinsic value | $ 4,900,000 | ||
Aggregate intrinsic value exercisable | $ 4,900,000 | ||
Weighted average contractual term | 1 year 11 months 19 days | ||
Total intrinsic value of options exercised | $ 15,800,000 | $ 300,000 | $ 800,000 |
Tax related benefits realized from the exercise of stock options | 16,800,000 | 1,400,000 | 2,800,000 |
Unrecognized compensation expense related to unvested stock options | $ 500,000 | ||
Weighted average remaining requisite service period of unvested stock awards | 7 months 28 days | ||
Fair value of option shares vested | $ 3,000,000 | 6,700,000 | 9,700,000 |
Stock-based compensation expense | $ 9,039,000 | 13,625,000 | 18,505,000 |
Options granted (in shares) | 0 | ||
Aggregate intrinsic value for the restricted stock and restricted stock units outstanding | $ 99,200,000 | ||
Aggregate intrinsic value expected to be settled in cash | 40,700,000 | ||
Tax benefits recognized for stock based compensation | 7,900,000 | 4,500,000 | 5,600,000 |
Capitalized stock-based compensation | 7,200,000 | 3,600,000 | 5,000,000 |
Expensed stock-based compensation | 30,000,000 | 17,600,000 | 21,600,000 |
Cash used to settle liability-based awards | $ 12,400,000 | 2,400,000 | |
Minimum | |||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||
Vesting period of shares | 3 years | ||
Maximum | |||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||
Vesting period of shares | 4 years | ||
Restricted Stock | |||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||
Weighted average remaining requisite service period of unvested stock awards | 2 years | ||
Unrecognized compensation expense related to unvested restricted stock and restricted stock units | $ 50,300,000 | ||
Unrecognized compensation expense related to unvested restricted stock expected to be settled in cash | 24,000,000 | ||
Fair value of restricted stock and restricted stock units vested | 51,900,000 | 8,400,000 | 13,600,000 |
Restricted stock or unit expenses | $ 36,300,000 | 17,700,000 | 20,200,000 |
Performance-Based Stock Units | |||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||
Vesting period of shares | 3 years | ||
Performance-Based Stock Units | Minimum | |||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||
Vesting percentage | 0.00% | ||
Performance-Based Stock Units | Maximum | |||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||
Vesting percentage | 200.00% | ||
Stock options | |||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||
Stock-based compensation expense | $ 1,000,000 | $ 3,400,000 | $ 6,400,000 |
Restricted Stock Service Based [Member] | |||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||
Restricted stock grants (in shares) | 283,000 | ||
Restricted stock vested (in shares) | 334,000 | ||
Restricted Stock Liability Based | |||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||
Restricted stock grants (in shares) | 357,000 | ||
Restricted stock vested (in shares) | 487,252 | 226,363 | |
2012 Incentive Plan | |||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||
Maximum shares of common stock provided (in shares) | 8,700,000 | ||
2019 Incentive Plan | |||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||
Maximum shares of common stock provided (in shares) | 1,571,972 |
Employee Benefit Plans (Details
Employee Benefit Plans (Details) - USD ($) | 12 Months Ended | ||
Dec. 31, 2021 | Dec. 31, 2020 | Dec. 31, 2019 | |
Employee Benefit Plan (Textual) [Abstract] | |||
Employees annual compensation | 3.00% | ||
Safe Harbor match | $ 1,600,000 | $ 1,400,000 | $ 1,400,000 |
Discretionary matching contributions | 2,100,000 | $ 1,800,000 | $ 1,700,000 |
No additional discretionary contributions | $ 0 |
Equity (Details)
Equity (Details) - USD ($) $ / shares in Units, $ in Thousands | 1 Months Ended | 3 Months Ended | 12 Months Ended |
Oct. 31, 2021 | Dec. 31, 2021 | Dec. 31, 2021 | |
Stockholders' Equity Note [Abstract] | |||
Common stock, dividends (in usd per share) | $ 0.05 | $ 0.025 | $ 0.125 |
Dividends paid | $ 14,581 | ||
Preferred shares authorized (in shares) | 2,000,000 | 2,000,000 |
Derivative Financial Instrume_3
Derivative Financial Instruments (Details) | Dec. 31, 2021USD ($)bbl$ / bbl |
Derivative [Line Items] | |
Derivative Asset (Liability), Net | $ (14,878,000) |
Open costless collar contracts | |
Summary of contracts for oil and natural gas | |
Fair Value of Asset (Liability) | $ (16,803,000) |
Open costless collar contracts | Oil | |
Summary of contracts for oil and natural gas | |
Notional Quantity (Bbl) | bbl | 2,040,000 |
Weighted Average Price Floor (usd per Bbl) | $ / bbl | 50 |
Weighted Average Price Ceiling (usd per Bbl) | $ / bbl | 67.85 |
Fair Value of Asset (Liability) | $ (16,652,000) |
Open costless collar contracts | Natural Gas | 01/01/2021 - 12/31/2021 | |
Summary of contracts for oil and natural gas | |
Notional Quantity (Bbl) | bbl | 8,250,000 |
Weighted Average Price Floor (usd per Bbl) | $ / bbl | 2.70 |
Weighted Average Price Ceiling (usd per Bbl) | $ / bbl | 6.33 |
Fair Value of Asset (Liability) | $ (151,000) |
Open Basis Swap Contracts | |
Summary of contracts for oil and natural gas | |
Fair Value of Asset (Liability) | $ 1,925,000 |
Open Basis Swap Contracts | Oil Basis Swaps | 01/01/2022 - 12/31/2022 | |
Summary of contracts for oil and natural gas | |
Notional Quantity (Bbl) | bbl | 5,520,000 |
Fixed price (usd per Bbl) | $ / bbl | 0.95 |
Fair Value of Asset (Liability) | $ 1,925,000 |
Derivative Financial Instrume_4
Derivative Financial Instruments (Details 2) - USD ($) $ in Thousands | Dec. 31, 2021 | Dec. 31, 2020 |
Offsetting Derivative Assets [Abstract] | ||
Derivative liability | $ (35,889) | |
Total | $ (14,878) | |
Derivative Asset (Liability) Subject to Master Netting Arrangement | 0 | |
Derivative Asset (Liability), Net | (14,878) | |
Offsetting Derivative Liabilities [Abstract] | ||
Derivative Asset | 0 | |
Current assets | ||
Offsetting Derivative Assets [Abstract] | ||
Gross amounts of recognized liabilities | 382,328 | |
Gross amounts netted in the consolidated balance sheet | 375,601 | |
Derivative liability | 6,727 | |
Offsetting Derivative Liabilities [Abstract] | ||
Gross amounts of recognized assets | 215,145 | |
Gross amounts netted in the consolidated balance sheets | (213,174) | |
Derivative Asset | 1,971 | |
Other Assets | ||
Offsetting Derivative Liabilities [Abstract] | ||
Gross amounts of recognized assets | 150,194 | |
Gross amounts netted in the consolidated balance sheets | (147,624) | |
Derivative Asset | 2,570 | |
Long-term liabilities | ||
Offsetting Derivative Assets [Abstract] | ||
Gross amounts of recognized liabilities | (147,624) | |
Gross amounts netted in the consolidated balance sheet | (147,624) | |
Derivative liability | 0 | |
Current liabilities | ||
Offsetting Derivative Assets [Abstract] | ||
Gross amounts of recognized liabilities | (230,023) | (420,787) |
Gross amounts netted in the consolidated balance sheet | (213,174) | (375,601) |
Derivative liability | $ (16,849) | $ (45,186) |
Derivative Financial Instrume_5
Derivative Financial Instruments (Details 3) - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2021 | Dec. 31, 2020 | Dec. 31, 2019 | |
Summary of location and aggregate fair value of all derivative financial instruments recorded in the consolidated statements of operations | |||
Realized (loss) gain on derivatives | $ (220,105) | $ 38,937 | $ 9,482 |
Unrealized gain (loss) on derivatives | 21,011 | (32,008) | (53,727) |
Revenues | |||
Summary of location and aggregate fair value of all derivative financial instruments recorded in the consolidated statements of operations | |||
Realized (loss) gain on derivatives | (220,105) | 38,937 | 9,482 |
Unrealized gain (loss) on derivatives | 21,011 | (32,008) | (53,727) |
Total | (199,094) | 6,929 | (44,245) |
Oil | Revenues | |||
Summary of location and aggregate fair value of all derivative financial instruments recorded in the consolidated statements of operations | |||
Realized (loss) gain on derivatives | (194,058) | 38,937 | 9,026 |
Unrealized gain (loss) on derivatives | 26,857 | (37,703) | (53,443) |
Natural Gas | Revenues | |||
Summary of location and aggregate fair value of all derivative financial instruments recorded in the consolidated statements of operations | |||
Realized (loss) gain on derivatives | (26,047) | 0 | 456 |
Unrealized gain (loss) on derivatives | $ (5,846) | $ 5,695 | $ (284) |
Fair Value Measurements (Detail
Fair Value Measurements (Details) - USD ($) $ in Thousands | Dec. 31, 2021 | Dec. 31, 2020 |
Assets (Liabilities) | ||
Oil derivatives and basis swaps | $ (35,889) | |
Natural gas derivatives | 0 | |
Total | $ (14,878) | |
Fair value on a recurring basis | ||
Assets (Liabilities) | ||
Oil derivatives and basis swaps | (14,727) | (41,584) |
Natural gas derivatives | (151) | (5,695) |
Contingent consideration related to business combination | (8,203) | |
Total | (23,081) | (35,889) |
Fair value on a recurring basis | Level 1 | ||
Assets (Liabilities) | ||
Oil derivatives and basis swaps | 0 | 0 |
Natural gas derivatives | 0 | 0 |
Contingent consideration related to business combination | 0 | |
Total | 0 | 0 |
Fair value on a recurring basis | Level 2 | ||
Assets (Liabilities) | ||
Oil derivatives and basis swaps | (14,727) | (41,584) |
Natural gas derivatives | (151) | (5,695) |
Contingent consideration related to business combination | 0 | |
Total | (14,878) | (35,889) |
Fair value on a recurring basis | Level 3 | ||
Assets (Liabilities) | ||
Oil derivatives and basis swaps | 0 | 0 |
Natural gas derivatives | 0 | 0 |
Contingent consideration related to business combination | (8,203) | |
Total | $ (8,203) | $ 0 |
Fair Value Measurements (Deta_2
Fair Value Measurements (Details Textual) - USD ($) | 12 Months Ended | |
Dec. 31, 2021 | Dec. 31, 2020 | |
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items] | ||
Fair value of notes payable | $ 1,080,000,000 | $ 1,030,000,000 |
Pipe and other equipment | ||
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items] | ||
Impairment charge for equipments held in inventory | $ 0 |
Commitments and Contingencies (
Commitments and Contingencies (Details Textual) - USD ($) $ in Thousands | Feb. 17, 2017 | Dec. 31, 2021 | Dec. 31, 2020 |
Delivery Of Natural Gas And Oil Production To Third Parties | |||
Long-term Purchase Commitment [Line Items] | |||
Payment for other commitment | $ 48,700 | $ 46,000 | |
Other commitment | 597,300 | ||
Drilling Rig Commitments | |||
Long-term Purchase Commitment [Line Items] | |||
Maximum termination outstanding obligations of contracts | 10,800 | ||
Minimum outstanding commitments | $ 65,400 | ||
Drilling Rig Commitments | Minimum | |||
Long-term Purchase Commitment [Line Items] | |||
Purchase commitment period | 3 years | ||
Corporate Joint Venture | San Mateo Midstream | |||
Long-term Purchase Commitment [Line Items] | |||
Contractual obligation | $ 390,300 | ||
2019 15-Year Fixed Fee Natural Gas Transportation Agreement | San Mateo Midstream | |||
Long-term Purchase Commitment [Line Items] | |||
Supply agreement, term | 15 years | ||
Rustler Breaks Asset Area | Corporate Joint Venture | San Mateo Midstream | |||
Long-term Purchase Commitment [Line Items] | |||
Contractual obligation, term | 15 years | ||
Rustler Breaks and Wolf Asset Area | Corporate Joint Venture | San Mateo Midstream | |||
Long-term Purchase Commitment [Line Items] | |||
Contractual obligation, term | 15 years |
Supplemental Disclosures (Detai
Supplemental Disclosures (Details) - USD ($) $ in Thousands | Dec. 31, 2021 | Dec. 31, 2020 |
Summary of current accrued liabilities | ||
Total accrued liabilities | $ 253,283 | $ 119,158 |
Other | 37,458 | 11,331 |
Accrued evaluated and unproved and unevaluated property costs | ||
Summary of current accrued liabilities | ||
Total accrued liabilities | 128,598 | 44,012 |
Accrued midstream properties costs | ||
Summary of current accrued liabilities | ||
Total accrued liabilities | 7,799 | 12,776 |
Accrued lease operating expenses | ||
Summary of current accrued liabilities | ||
Total accrued liabilities | 32,182 | 24,276 |
Accrued interest on debt | ||
Summary of current accrued liabilities | ||
Total accrued liabilities | 18,232 | 18,315 |
Accrued asset retirement obligations | ||
Summary of current accrued liabilities | ||
Total accrued liabilities | 270 | 623 |
Accrued partners’ share of joint interest charges | ||
Summary of current accrued liabilities | ||
Total accrued liabilities | 17,460 | 7,407 |
Accrued payable related to purchased natural gas | ||
Summary of current accrued liabilities | ||
Total accrued liabilities | $ 11,284 | $ 418 |
Supplemental Disclosures (Det_2
Supplemental Disclosures (Details 1) - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2021 | Dec. 31, 2020 | Dec. 31, 2019 | |
Supplemental disclosures of cash flow information | |||
Cash paid for interest expense, net of amounts capitalized | $ 74,843 | $ 76,880 | $ 75,525 |
Increase (decrease) in asset retirement obligations related to mineral properties | 1,091 | (208) | 2,912 |
Increase in asset retirement obligations related to midstream properties | 257 | 690 | 1,204 |
Increase (decrease) in liabilities for drilling, completion and equipping capital expenditures | 80,255 | (26,126) | (13,310) |
Increase (decrease) increase in liabilities for acquisition of oil and natural gas properties | 2,981 | (2,346) | (2,567) |
(Decrease) increase in liabilities for midstream capital expenditures | (4,478) | (33,609) | 30,374 |
Stock-based compensation expense recognized as liability | 24,494 | 3,702 | 3,170 |
Transfer of inventory (to) from oil and natural gas properties | $ (398) | $ 608 | $ 1,515 |
Supplemental Disclosures Supple
Supplemental Disclosures Supplemental Disclosures (Details 2) (Details) - USD ($) $ in Thousands | Dec. 31, 2021 | Dec. 31, 2020 | Dec. 31, 2019 | Dec. 31, 2018 |
Supplemental Disclosures [Abstract] | ||||
Cash | $ 48,135 | $ 57,916 | $ 40,024 | |
Restricted cash | 38,785 | 33,467 | 25,104 | |
Total cash and restricted cash | $ 86,920 | $ 91,383 | $ 65,128 | $ 83,984 |
Segment Reporting (Details)
Segment Reporting (Details) | 12 Months Ended | ||
Dec. 31, 2021USD ($)segment | Dec. 31, 2020USD ($) | Dec. 31, 2019USD ($) | |
Segment Reporting Information [Line Items] | |||
Number of business segments | segment | 2 | ||
Revenues | $ 1,862,075,000 | $ 851,135,000 | $ 1,026,204,000 |
Lease bonus - mineral acreage | 0 | 4,062,000 | 1,711,000 |
Realized gain on derivatives | (220,105,000) | 38,937,000 | 9,482,000 |
Unrealized gain on derivatives | 21,011,000 | (32,008,000) | (53,727,000) |
Expenses | 869,905,000 | 1,383,625,000 | 748,190,000 |
Operating income (loss) | 793,076,000 | (521,499,000) | 235,480,000 |
Assets | 4,262,153,000 | 3,687,280,000 | 4,069,676,000 |
Capital expenditures | 837,928,000 | 721,838,000 | 946,025,000 |
Depletion, depreciation and amortization | 344,905,000 | 361,831,000 | 350,540,000 |
Impairment charge of net capitalized costs | 0 | 684,743,000 | 0 |
Operating Segments | Exploration and Production | |||
Segment Reporting Information [Line Items] | |||
Lease bonus - mineral acreage | 4,062,000 | 1,711,000 | |
Realized gain on derivatives | (220,105,000) | 38,937,000 | 9,482,000 |
Unrealized gain on derivatives | 21,011,000 | (32,008,000) | (53,727,000) |
Expenses | 794,880,000 | 1,334,378,000 | 621,687,000 |
Operating income (loss) | 748,456,000 | (561,559,000) | 226,708,000 |
Assets | 3,324,681,000 | 2,782,819,000 | 3,360,725,000 |
Capital expenditures | 778,191,000 | 518,198,000 | 718,712,000 |
Depletion, depreciation and amortization | 310,900,000 | 335,800,000 | 331,700,000 |
Payments to acquire productive assets | 70,500,000 | 48,300,000 | |
Operating Segments | Midstream | |||
Segment Reporting Information [Line Items] | |||
Lease bonus - mineral acreage | 0 | 0 | |
Realized gain on derivatives | 0 | 0 | 0 |
Unrealized gain on derivatives | 0 | 0 | 0 |
Expenses | 142,444,000 | 97,599,000 | 130,612,000 |
Operating income (loss) | 130,519,000 | 92,970,000 | 81,506,000 |
Assets | 879,672,000 | 836,509,000 | 647,937,000 |
Capital expenditures | 59,361,000 | 201,440,000 | 223,612,000 |
Depletion, depreciation and amortization | 31,500,000 | 23,300,000 | 16,100,000 |
Income (loss) attributable to noncontrolling interest | 55,700,000 | 39,600,000 | 35,200,000 |
Land and seismic acquisition expenditures | 263,500,000 | ||
Payments to acquire productive assets | 28,500,000 | 112,100,000 | 145,400,000 |
Corporate | |||
Segment Reporting Information [Line Items] | |||
Lease bonus - mineral acreage | 0 | 0 | |
Realized gain on derivatives | 0 | 0 | 0 |
Unrealized gain on derivatives | 0 | 0 | 0 |
Expenses | 85,899,000 | 52,910,000 | 72,734,000 |
Operating income (loss) | (85,899,000) | (52,910,000) | (72,734,000) |
Assets | 57,800,000 | 67,952,000 | 61,014,000 |
Capital expenditures | 376,000 | 2,200,000 | 3,701,000 |
Depletion, depreciation and amortization | 2,600,000 | 2,700,000 | 2,700,000 |
Consolidations and Eliminations | |||
Segment Reporting Information [Line Items] | |||
Lease bonus - mineral acreage | 0 | 0 | |
Realized gain on derivatives | 0 | 0 | 0 |
Unrealized gain on derivatives | 0 | 0 | 0 |
Expenses | (153,318,000) | (101,262,000) | (76,843,000) |
Operating income (loss) | 0 | 0 | 0 |
Assets | 0 | 0 | 0 |
Capital expenditures | 0 | 0 | 0 |
Oil and natural gas revenues | |||
Segment Reporting Information [Line Items] | |||
Revenues | 1,700,542,000 | 744,461,000 | 892,325,000 |
Oil and natural gas revenues | Operating Segments | Exploration and Production | |||
Segment Reporting Information [Line Items] | |||
Revenues | 1,695,032,000 | 741,092,000 | 886,127,000 |
Oil and natural gas revenues | Operating Segments | Midstream | |||
Segment Reporting Information [Line Items] | |||
Revenues | 5,510,000 | 3,369,000 | 6,198,000 |
Oil and natural gas revenues | Corporate | |||
Segment Reporting Information [Line Items] | |||
Revenues | 0 | 0 | 0 |
Oil and natural gas revenues | Consolidations and Eliminations | |||
Segment Reporting Information [Line Items] | |||
Revenues | 0 | 0 | 0 |
Third-party midstream services revenues | |||
Segment Reporting Information [Line Items] | |||
Revenues | 75,499,000 | 64,932,000 | 59,110,000 |
Third-party midstream services revenues | Operating Segments | Exploration and Production | |||
Segment Reporting Information [Line Items] | |||
Revenues | 0 | 0 | 0 |
Third-party midstream services revenues | Operating Segments | Midstream | |||
Segment Reporting Information [Line Items] | |||
Revenues | 228,817,000 | 166,194,000 | 135,953,000 |
Third-party midstream services revenues | Corporate | |||
Segment Reporting Information [Line Items] | |||
Revenues | 0 | 0 | 0 |
Third-party midstream services revenues | Consolidations and Eliminations | |||
Segment Reporting Information [Line Items] | |||
Revenues | (153,318,000) | (101,262,000) | (76,843,000) |
Sales of purchased natural gas | |||
Segment Reporting Information [Line Items] | |||
Revenues | 86,034,000 | 41,742,000 | 74,769,000 |
Sales of purchased natural gas | Operating Segments | Exploration and Production | |||
Segment Reporting Information [Line Items] | |||
Revenues | 47,398,000 | 20,736,000 | 4,802,000 |
Sales of purchased natural gas | Operating Segments | Midstream | |||
Segment Reporting Information [Line Items] | |||
Revenues | 38,636,000 | 21,006,000 | 69,967,000 |
Sales of purchased natural gas | Corporate | |||
Segment Reporting Information [Line Items] | |||
Revenues | 0 | 0 | 0 |
Sales of purchased natural gas | Consolidations and Eliminations | |||
Segment Reporting Information [Line Items] | |||
Revenues | $ 0 | $ 0 | $ 0 |