Document and Entity Information
Document and Entity Information - USD ($) | 12 Months Ended | ||
Dec. 31, 2019 | Mar. 04, 2020 | Jun. 30, 2019 | |
Cover [Abstract] | |||
Document Type | 10-K | ||
Amendment Flag | false | ||
Document Period End Date | Dec. 31, 2019 | ||
Document Fiscal Year Focus | 2019 | ||
Document Fiscal Period Focus | FY | ||
Trading Symbol | TALO | ||
Title of 12(b) Security | Common Stock | ||
Security Exchange Name | NYSE | ||
Entity Registrant Name | Talos Energy Inc. | ||
Document Annual Report | true | ||
Document Transition Report | false | ||
Entity Small Business | false | ||
Entity Emerging Growth Company | false | ||
Entity Current Reporting Status | Yes | ||
Entity Interactive Data Current | Yes | ||
Entity Shell Company | false | ||
Entity Incorporation, State or Country Code | DE | ||
Entity File Number | 01-38497 | ||
Entity Tax Identification Number | 82-3532642 | ||
Entity Address, Address Line One | 333 Clay Street | ||
Entity Address, Address Line Two | Suite 3300 | ||
Entity Address, City or Town | Houston | ||
Entity Address, State or Province | TX | ||
Entity Address, Postal Zip Code | 77002 | ||
City Area Code | 713 | ||
Local Phone Number | 328-3000 | ||
Entity Central Index Key | 0001724965 | ||
Current Fiscal Year End Date | --12-31 | ||
Entity Filer Category | Accelerated Filer | ||
Entity Common Stock, Shares Outstanding | 54,204,730 | ||
Entity Well-known Seasoned Issuer | Yes | ||
Entity Voluntary Filers | No | ||
Entity Public Float | $ 481,140,961 | ||
Documents Incorporated by Reference | Portions of the registrant’s definitive proxy statement relating to the 2020 Annual Meeting of Shareholders are incorporated by reference into Part III of this report. |
CONSOLIDATED BALANCE SHEETS
CONSOLIDATED BALANCE SHEETS - USD ($) $ in Thousands | Dec. 31, 2019 | Dec. 31, 2018 |
Current assets: | ||
Cash and cash equivalents | $ 87,022 | $ 139,914 |
Restricted cash | 1,248 | |
Accounts receivable | ||
Trade, net | 107,842 | 103,025 |
Joint interest, net | 16,552 | 20,244 |
Other | 6,346 | 19,686 |
Assets from price risk management activities | 8,393 | 75,473 |
Prepaid assets | 65,877 | 38,911 |
Income tax receivable | 116 | 10,701 |
Other current assets | 1,836 | 7,644 |
Total current assets | 293,984 | 416,846 |
Property and equipment: | ||
Proved properties | 4,066,260 | 3,629,430 |
Unproved properties, not subject to amortization | 194,532 | 108,209 |
Other property and equipment | 29,843 | 33,191 |
Total property and equipment | 4,290,635 | 3,770,830 |
Accumulated depreciation, depletion and amortization | (2,065,023) | (1,719,609) |
Total property and equipment, net | 2,225,612 | 2,051,221 |
Other long-term assets: | ||
Other well equipment inventory | 7,732 | 9,224 |
Operating lease assets | 7,779 | |
Other assets | 54,375 | 2,695 |
Total assets | 2,589,482 | 2,479,986 |
Current liabilities: | ||
Accounts payable | 71,357 | 51,019 |
Accrued liabilities | 154,816 | 188,650 |
Accrued royalties | 31,729 | 38,520 |
Current portion of long-term debt | 443 | |
Current portion of asset retirement obligations | 61,051 | 68,965 |
Liabilities from price risk management activities | 19,476 | 550 |
Accrued interest payable | 10,249 | 10,200 |
Current portion of operating lease liabilities | 1,594 | |
Other current liabilities | 20,180 | 22,071 |
Total current liabilities | 370,452 | 380,418 |
Long-term liabilities: | ||
Long-term debt, net of discount and deferred financing costs | 732,981 | 654,861 |
Asset retirement obligations | 308,427 | 313,852 |
Liabilities from price risk management activities | 511 | |
Operating lease liabilities | 17,239 | |
Other long-term liabilities | 81,595 | 123,359 |
Total liabilities | 1,511,205 | 1,472,490 |
Commitments and contingencies (Note 12) | ||
Stockholders' Equity: | ||
Preferred stock, $0.01 par value; 30,000,000 shares authorized and no shares issued or outstanding as of December 31, 2019 and December 31, 2018 | ||
Common stock $0.01 par value; 270,000,000 shares authorized; 54,197,004 and 54,155,768 shares issued and outstanding as of December 31, 2019 and December 31, 2018, respectively | 542 | 542 |
Additional paid-in capital | 1,346,142 | 1,334,090 |
Accumulated deficit | (268,407) | (327,136) |
Total stockholders' equity | 1,078,277 | 1,007,496 |
Total liabilities and stockholders' equity | $ 2,589,482 | $ 2,479,986 |
CONSOLIDATED BALANCE SHEETS (Pa
CONSOLIDATED BALANCE SHEETS (Parenthetical) - $ / shares | Dec. 31, 2019 | Dec. 31, 2018 |
Statement Of Financial Position [Abstract] | ||
Preferred stock, par value | $ 0.01 | $ 0.01 |
Preferred stock, shares authorized | 30,000,000 | 30,000,000 |
Preferred stock, shares issued | 0 | 0 |
Preferred stock, shares outstanding | 0 | 0 |
Common stock, par value | $ 0.01 | $ 0.01 |
Common stock, shares authorized | 270,000,000 | 270,000,000 |
Common stock, shares issued | 54,197,004 | 54,155,768 |
Common stock, shares outstanding | 54,197,004 | 54,155,768 |
CONSOLIDATED STATEMENTS OF OPER
CONSOLIDATED STATEMENTS OF OPERATIONS - USD ($) shares in Thousands, $ in Thousands | 12 Months Ended | ||
Dec. 31, 2019 | Dec. 31, 2018 | Dec. 31, 2017 | |
Revenues: | |||
Total revenue | $ 927,620 | $ 891,288 | $ 412,828 |
Operating expenses: | |||
Depreciation, depletion and amortization | 345,931 | 288,719 | 157,352 |
Write-down of oil and natural gas properties | 12,221 | ||
Accretion expense | 34,389 | 35,344 | 19,295 |
General and administrative expense | 77,209 | 85,816 | 36,673 |
Total operating expenses | 714,526 | 638,159 | 367,528 |
Operating income (loss) | 213,094 | 253,129 | 45,300 |
Interest expense | (97,847) | (90,114) | (80,934) |
Price risk management activities income (expense) | (95,337) | 60,435 | (27,563) |
Other income | 2,678 | 1,012 | 329 |
Net income (loss) before income taxes | 22,588 | 224,462 | (62,868) |
Income tax benefit (expense) | 36,141 | (2,922) | |
Net income (loss) | $ 58,729 | $ 221,540 | $ (62,868) |
Net income (loss) per common share: | |||
Basic | $ 1.08 | $ 4.81 | $ (2.01) |
Diluted | $ 1.08 | $ 4.81 | $ (2.01) |
Weighted average common shares outstanding: | |||
Basic | 54,185 | 46,058 | 31,244 |
Diluted | 54,413 | 46,061 | 31,244 |
Oil and Gas Properties | |||
Operating expenses: | |||
Lease operating expense | $ 243,427 | $ 226,291 | $ 152,748 |
Production taxes | 1,349 | 1,989 | 1,460 |
Oil Revenue | |||
Revenues: | |||
Revenue | 833,118 | 781,815 | 344,781 |
Natural Gas Revenue | |||
Revenues: | |||
Revenue | 55,278 | 73,610 | 48,886 |
NGL Revenue | |||
Revenues: | |||
Revenue | 19,668 | $ 35,863 | 16,658 |
Other | |||
Revenues: | |||
Revenue | $ 19,556 | $ 2,503 |
CONSOLIDATED STATEMENTS OF CHAN
CONSOLIDATED STATEMENTS OF CHANGES IN STOCKHOLDERS' EQUITY (DEFICIT) - USD ($) $ in Thousands | Total | Common Stock | Additional Paid-In Capital | Accumulated Deficit |
Balance at Dec. 31, 2016 | $ 6,986 | $ 312 | $ 492,157 | $ (485,483) |
Balance, shares at Dec. 31, 2016 | 31,244,085 | |||
Equity based compensation | 1,795 | 1,795 | ||
Net income (loss) | (62,868) | (62,868) | ||
Balance at Dec. 31, 2017 | (54,087) | $ 312 | 493,952 | (548,351) |
Balance, shares at Dec. 31, 2017 | 31,244,085 | |||
Cumulative effect adjustment | (325) | (325) | ||
Sponsor Debt Exchange | 102,000 | $ 29 | 101,971 | |
Sponsor Debt Exchange, Shares | 2,874,049 | |||
Stone Combination | 731,964 | $ 201 | 731,763 | |
Stone Combination, Shares | 20,037,634 | |||
Equity based compensation | 6,404 | 6,404 | ||
Net income (loss) | 221,540 | 221,540 | ||
Balance at Dec. 31, 2018 | $ 1,007,496 | $ 542 | 1,334,090 | (327,136) |
Balance, shares at Dec. 31, 2018 | 54,155,768 | 54,155,768 | ||
Equity based compensation | $ 12,385 | 12,385 | ||
Equity based compensation, Shares | 53,787 | |||
Shares withheld for taxes on equity transactions | (333) | (333) | ||
Shares withheld for taxes on equity transactions, Shares | (12,551) | |||
Net income (loss) | 58,729 | 58,729 | ||
Balance at Dec. 31, 2019 | $ 1,078,277 | $ 542 | $ 1,346,142 | $ (268,407) |
Balance, shares at Dec. 31, 2019 | 54,197,004 | 54,197,004 |
CONSOLIDATED STATEMENTS OF CASH
CONSOLIDATED STATEMENTS OF CASH FLOWS - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2019 | Dec. 31, 2018 | Dec. 31, 2017 | |
Cash flows from operating activities: | |||
Net income (loss) | $ 58,729 | $ 221,540 | $ (62,868) |
Adjustments to reconcile net income (loss) to net cash provided by operating activities | |||
Depreciation, depletion, amortization and accretion expense | 380,320 | 324,063 | 176,647 |
Write-down of oil and natural gas properties and other well inventory | 12,386 | 244 | 260 |
Amortization of deferred financing costs and original issue discount | 5,207 | 4,253 | 2,383 |
Equity based compensation, net of amounts capitalized | 6,964 | 2,893 | 875 |
Price risk management activities expense (income) | 95,337 | (60,435) | 27,563 |
Net cash received (paid) on settled derivative instruments | (8,820) | (111,147) | 23,834 |
Settlement of asset retirement obligations | (75,331) | (112,946) | (32,573) |
Changes in operating assets and liabilities: | |||
Accounts receivable | 5,788 | (786) | (9,132) |
Other current assets | (15,114) | (2,624) | (4,441) |
Accounts payable | 7,523 | (48,825) | 2,409 |
Other current liabilities | (35,459) | 32,044 | 46,364 |
Other non-current assets and liabilities, net | (43,797) | 15,171 | 4,732 |
Net cash provided by operating activities | 393,733 | 263,445 | 176,053 |
Cash flows from investing activities: | |||
Exploration, development and other capital expenditures | (463,409) | (240,914) | (155,177) |
Cash (paid for) received from acquisitions, net of cash acquired | (37,916) | 278,409 | (2,464) |
Proceeds from sale of other property and equipment | 5,369 | ||
Net cash provided by (used in) investing activities | (495,956) | 37,495 | (157,641) |
Cash flows from financing activities: | |||
Redemption of Senior Notes and other long-term debt | (10,567) | (25,257) | (1,000) |
Proceeds from Bank Credit Facility | 110,000 | 319,000 | 10,000 |
Repayment of Bank Credit Facility | (25,000) | (54,000) | (15,000) |
Deferred financing costs | (1,963) | (17,002) | |
Other deferred payments | (9,921) | ||
Payments of finance lease | (14,133) | (12,952) | (12,412) |
Employee stock transactions | (333) | ||
Net cash provided by (used in) financing activities | 48,083 | (193,211) | (18,412) |
Net increase (decrease) in cash, cash equivalents and restricted cash | (54,140) | 107,729 | |
Cash, cash equivalents and restricted cash: | |||
Balance, beginning of period | 141,162 | 33,433 | 33,433 |
Balance, end of period | 87,022 | 141,162 | 33,433 |
Supplemental Non-Cash Transactions: | |||
Capital expenditures included in accounts payable and accrued liabilities | 90,956 | 100,664 | 40,626 |
Supplemental Cash Flow Information: | |||
Interest paid, net of amounts capitalized | $ 62,571 | 53,476 | 47,994 |
LLC Bank Credit Facility | |||
Cash flows from financing activities: | |||
Repayment of Bank Credit Facility | $ (403,000) | $ (15,000) |
Formation and Basis of Presenta
Formation and Basis of Presentation | 12 Months Ended |
Dec. 31, 2019 | |
Organization Consolidation And Presentation Of Financial Statements [Abstract] | |
Formation and Basis of Presentation | Note 1 — Formation and Basis of Presentation Formation and Nature of Business Talos Energy Inc. (“Talos” or the “Company”) is a technically driven independent exploration and production company focused on safely and efficiently maximizing value through our operations, currently in the United States (“U.S.”) Gulf of Mexico and offshore Mexico. The Company leverages decades of geology, geophysics and offshore operations expertise towards the acquisition, exploration, exploitation and development of assets in key geological trends that are present in many offshore basins around the world. Talos Energy Inc. was formed in connection with the previously disclosed business combination between Talos Energy LLC and Stone Energy Corporation (“Stone”) that occurred on May 10, 2018, pursuant to which Talos Energy LLC and Stone became indirect wholly owned subsidiaries of Talos Energy Inc. Talos Energy LLC — Talos Energy LLC was formed in 2011 and commenced commercial operations on February 6, 2013. Prior to February 6, 2013, Talos Energy LLC had incurred certain general and administrative expenses associated with the start-up of its operations. On February 3, 2012, Talos Energy LLC completed a transaction with funds and other alternative investment vehicles managed by Apollo Management VII, L.P. and Apollo Commodities Management, L.P., with respect to Series I (“Apollo Funds”), and entities controlled by or affiliated with Riverstone Energy Partners V, L.P. (“Riverstone Funds”, and together with the Apollo Funds, the “Sponsors”) and members of management pursuant to which the Company received a private equity capital commitment. Stone Combination — On May 10, 2018 (the “Stone Closing Date”), the Company (f/k/a Sailfish Energy Holdings Corporation) consummated the transactions contemplated by that certain Transaction Agreement, dated as of November 21, 2017 (the “Transaction Agreement”), by and among Stone, the Company, Sailfish Merger Sub Corporation (“Merger Sub”), Talos Energy LLC and Talos Production LLC (which was converted into a Delaware Corporation and named Talos Production Inc. in 2019), pursuant to which, among other items, each of Stone, Talos Production LLC and Talos Energy LLC became wholly-owned subsidiaries of the Company (the “Stone Combination”). Prior to the Stone Closing Date, the Company did not conduct any material activities other than those incident to its formation and the matters contemplated by the Transaction Agreement. On the Stone Closing Date, the following transactions, among others, occurred: (i) Stone underwent a reorganization pursuant to which Merger Sub merged with and into Stone, with Stone continuing as the surviving corporation and a direct wholly-owned subsidiary of the Company (the “Merger”) and each share of Stone’s common stock outstanding immediately prior to the Merger (other than treasury shares held by Stone, which were cancelled for no consideration) was converted into the right to receive one share of the Company’s common stock, par value $0.01 (the “Common Stock”) and (ii) the Sponsors contributed all of the equity interests in Talos Production LLC (which at that time owned 100% of the equity interests in Talos Energy LLC) to the Company in exchange for an aggregate of 31,244,085 shares of Common Stock (the “Sponsor Equity Exchange”). Concurrently with the consummation of the Transaction Agreement, the Company consummated the transactions contemplated by that certain Exchange Agreement, dated as of November 21, 2017 (the “Exchange Agreement”), among the Company, Stone, the Talos Issuers (defined below), the various lenders and noteholders of the Talos Issuers listed therein, certain funds controlled by Franklin Advisers, Inc. (“Franklin”) (such controlled noteholders, the “Franklin Noteholders”), and certain clients of MacKay Shields LLC (“MacKay Shields”) (such noteholders, the “MacKay Noteholders”), pursuant to which (i) the Apollo Funds and Riverstone Funds contributed $102.0 million in aggregate principal amount of 9.75% Senior Notes due 2022 (“9.75% Senior Notes”) issued by Talos Production LLC and Talos Production Finance, Inc. (together, the “Talos Issuers”) to the Company in exchange for an aggregate of 2,874,049 shares of Common Stock (the “Sponsor Debt Exchange”); (ii) the holders of second lien bridge loans (“11.00% Bridge Loans”) issued by the Talos Issuers exchanged such 11.00% Bridge Loans for $172.0 million aggregate principal amount of 11.00% Second-Priority Senior Secured Notes due 2022 of the Talos Issuers (“11.00% Notes”) and (iii) Franklin Noteholders and MacKay Noteholders exchanged their 7.50% Senior Notes due 2022 issued by Stone (“7.50% Notes”) for $137.4 million aggregate principal amount of 11.00% Notes. Substantially concurrent therewith, the Company consummated an exchange offer and consent solicitation, pursuant to which the holders of the 7.50% Notes, excluding the 7.50% Notes held by the Franklin Noteholders and the MacKay Noteholders, exchanged their 7.50% Notes for 11.00% Notes and a cash payment, and a solicitation of consents to proposed amendments to the 7.50% Notes. Approximately $81.5 million in aggregate principal amount of the 7.50% Notes were validly tendered, and approximately $6.1 million in aggregate principal amount of 7.50% Notes remained outstanding as of the Stone Closing Date. As a result of the closing of the transactions contemplated by the Transaction Agreement and the Exchange Agreement (the “Transactions”) the former stakeholders of Talos Energy LLC held approximately 63% of the Company’s outstanding Common Stock and the former stockholders of Stone held approximately 37% of the Company’s outstanding Common Stock as of the Stone Closing Date. Basis of Presentation and Consolidation The consolidated financial statements have been prepared in accordance with accounting principles generally accepted in the United States of America (“GAAP”) and include each subsidiary from the date of inception. All intercompany transactions have been eliminated. All adjustments are of a normal, recurring nature and are necessary to fairly present the financial position, results of operations and cash flows for the periods are reflected herein. The Company has evaluated subsequent events through the date the consolidated financial statements were issued. Talos Energy LLC was considered the accounting acquirer in the Stone Combination under GAAP. Accordingly, the historical financial and operating data of Talos Energy Inc., which covers periods prior to the Stone Closing Date, reflects the assets, liabilities and results of operations of Talos Energy LLC and does not reflect the assets, liabilities and results of operations of Stone. For the periods prior to May 10, 2018, the Company retrospectively adjusted its Statement of Changes in Stockholders’ Equity and the weighted average shares used in determining earnings per share to reflect the number of shares Talos Energy LLC received in the Stone Combination. Beginning on May 10, 2018, common stock is presented to reflect the legal capital of Talos Energy Inc. The preparation of financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities as of the date of the financial statements, the reported amounts of revenues and expenses during the reporting periods and the reported amounts of proved oil and natural gas reserves. Actual results could differ from those estimates. For presentation purposes, as of December 31, 2019, operating expenses previously presented as “Direct lease operating expense,” “Insurance” and “Workover and maintenance expense” have been combined and presented as “Lease operating expense” on our Consolidated Statements of Operations. Such reclassification had no effect on our results of operations, financial position or cash flows. The Company has one reportable segment, which is the exploration and production of oil and natural gas. Substantially all the Company’s long-lived assets, proved reserves and production sales are related to the Company’s operations in the United States. Recently Adopted Accounting Standards Leases — In February 2016, the Financial Accounting Standards Board issued Accounting Standards Codification 2016-02, Leases (“Topic 842”) requiring an entity to recognize a right-of-use asset representing the right to use an underlying asset for the lease term and a lease liability representing the obligation associated with future lease payments for virtually all leases. The pattern of expense recognition in the income statement is dependent on lease classification as finance or operating. A lease is defined as a contract, or part of a contract, that conveys the right to control the use of identified property, plant or equipment (an identified asset) for a period of time in exchange for consideration. However, Topic 842 does not apply to leases of mineral rights. On January 1, 2019, the Company adopted Topic 842, using the modified retrospective approach, which does not require an adjustment to comparative-period financial statements. As such, results for reporting periods beginning January 1, 2019 are presented in accordance with Topic 842, while prior period amounts are reported in accordance with previous lease accounting treatment. The Company elected the package of practical expedients permitted under the transition guidance within the new standard, which, among other items, allowed Talos not to reassess whether expired or existing contracts, including land easements, contain a lease or reassess the classification and indirect costs associated with existing or expired leases. On the January 1, 2019 adoption date, the Company recorded a right-of-use asset of approximately $7.3 million and corresponding lease liability of $16.9 million representing the present value of its future operating lease payments. Upon the adoption of Topic 842, lease incentives are presented as a reduction to the right-of-use asset resulting in the difference between the right-of-use asset and lease liability. Adoption of this standard did not require an adjustment to retained earnings and did not impact the consolidated statements of operations, consolidated statements of cash flows or consolidated statements of changes in stockholders’ equity. See Note 5 – Leases Recently Issued Accounting Standards In June 2016, the FASB issued ASU 2016-13, Financial Instruments - Credit Losses (Topic 326): Measurement of Credit Losses on Financial Instruments |
Summary of Significant Accounti
Summary of Significant Accounting Policies | 12 Months Ended |
Dec. 31, 2019 | |
Organization Consolidation And Presentation Of Financial Statements [Abstract] | |
Summary of Significant Accounting Policies | Note 2 — Summary of Significant Accounting Policies Overview of Significant Accounting Policies Cash and Cash Equivalents — The Company presents cash as cash and cash equivalents on the Company’s consolidated balance sheets. The Company considers all cash, money market funds and highly liquid investments with an original maturity of three months or less as cash and cash equivalents. Cash and cash equivalents are carried at cost, which approximates fair value. Accounts Receivable and Allowance for Uncollectible Accounts — Accounts receivable are stated at the historical carrying amount net of an allowance for uncollectible accounts of $9.9 million at December 31, 2019 and $8.7 million at December 31, 2018. The Company establishes provisions for losses on accounts receivable with other parties if it believes that it will not collect all or part of the outstanding balance. On a quarterly basis, the Company reviews collectability and establishes or adjusts the Company’s allowance as necessary using the specific identification method. The Company presented $18.0 million of refund claims for value added taxes paid in Mexico in other assets on the consolidated balance sheets as of December 31, 2019. Prepaid Assets — Prepaid assets primarily represent deposits with the Office of Natural Resources Revenue (“ONRR”) and transaction escrow related to the ILX and Castex Acquisition as further defined in Note 3 — Acquisitions. The deposits with ONRR represent the Company’s estimated federal royalties payable within thirty days of the production date. On a monthly basis the Company adjusts the deposit based on actual royalty payments remitted to the ONRR. The transaction escrow was applied to the purchase price that closed in the first quarter of 2020. The escrow for the year ended December 31, 2019 was $31.8 million. Revenue Recognition — Revenues are recorded based from the sale of oil, natural gas and NGL quantities sold to purchasers. The Company records revenues from the sale of oil, natural gas and NGLs based on quantities of production sold to purchasers under short-term contracts (less than twelve months) at market prices when delivery to the customer has occurred, title has transferred, prices are fixed and determinable and collection is reasonably assured. This occurs when production has been delivered to a pipeline or when a barge lifting has occurred. The Company recognizes transportation costs as a component of lease operating expense when it is the shipper of the product. Each unit of product typically represents a separate performance obligation, therefore, future volumes are wholly unsatisfied and disclosure of the transaction price allocated to remaining performance obligations is not required. Gas Imbalances — Prior to the adoption of A ccounting Standards Codification (“ASC”) 606 in 2018 , the Company used the entitlement method to account for sales and production. Under the entitlement method, revenue was recorded based on the Company’s entitled share of production with any difference recorded as an imbalance on the consolidated balance sheet. Upon the adoption of ASC 606 in 2018 , revenues are recorded based on the actual sales volumes sold to purchasers. An imbalance receivable or payable is recorded only to the extent the imbalance is in excess of its share of remaining proved developed reserves in an underlying property. The change in accounting method from the entitlements method to the sales method resulted in an immaterial cumulative-effect adjustment to stockholders’ deficit on the date of adoption. Production Handling Fees — Prior to the adoption of ASC 606 in 2018, the Company presented certain reimbursements for costs from certain third parties as other revenue on the consolidated statements of operations. Upon the adoption of ASC 606 in 2018, the reimbursements are presented as a reduction of lease operating expense on the consolidated statements of operations. The impact of the reclassification for the year ended December 31, 2018 was immaterial . Other Revenue — Other revenues primarily represents a multi -year federal royalty refund claim from the ONRR. The company records revenue when a refund is filed and its collection is reasonably assured. The refunds for the year ended December 31, 2019 was $19.3 million. Accounting for Oil and Natural Gas Activities — The Company follows the full cost method of accounting for oil and natural gas exploration and development activities. Under the full cost method, substantially all costs incurred in connection with the acquisition, development and exploration of oil and natural gas reserves are capitalized. These capitalized amounts include the internal costs directly related to acquisition, development and exploration activities, asset retirement costs and capitalized interest. Under the full cost method, dry hole costs and geological and geophysical costs are capitalized into the full cost pool, which is subject to amortization and assessed for impairment on a quarterly basis through a ceiling test calculation as discussed below. Capitalized costs associated with proved reserves are amortized on a country by country basis over the life of the total proved reserves using the unit of production method, computed quarterly. Conversely, capitalized costs associated with unproved properties and related geological and geophysical costs, exploration wells currently drilling and capitalized interest are initially excluded from the amortizable base. The Company transfers unproved property costs into the amortizable base when properties are determined to have proved reserves or when the Company has completed an unproved properties evaluation resulting in an impairment. The Company evaluates each of these unproved properties individually for impairment at least quarterly. Additionally, the amortizable base includes future development costs, dismantlement, restoration and abandonment costs, net of estimated salvage values, and geological and geophysical costs incurred that cannot be associated with specific unproved properties or prospects in which the Company owns a direct interest. The Company capitalizes overhead costs that are directly related to exploration, acquisition and development activities. Capitalized overhead for the years ended December 31, 2019, 2018 and 2017 was $28.2 million, $21.9 million and $13.7 million, respectively. The Company’s capitalized costs are limited to a ceiling based on the present value of future net revenues from proved reserves, computed using a discount factor of 10 percent, plus the lower of cost or estimated fair value of unproved oil and natural gas properties not being amortized less the related tax effects. Any costs in excess of the ceiling are recognized as a non-cash impairment expense on the consolidated statements of operations and an increase to accumulated depreciation, depletion and amortization on the Company’s consolidated balance sheets. The expense may not be reversed in future periods, even though higher oil, natural gas and NGL prices may subsequently increase the ceiling. The Company performs this ceiling test calculation each quarter. In accordance with the SEC rules and regulations, the Company utilizes SEC Pricing when performing the ceiling test. The Company also holds prices and costs constant over the life of the reserves, even though actual prices and costs of oil and natural gas are often volatile and may change from period to period. Under the full cost method of accounting for oil and natural gas operations, assets whose costs are currently being depreciated, depleted or amortized are assets in use in the earnings activities of the enterprise and do not qualify for capitalization of interest cost. Investments in unproved properties for which exploration and development activities are in progress and other major development projects that are not being currently depreciated, depleted or amortized are assets qualifying for capitalization of interest costs. When the Company sells or conveys interests in oil and natural gas properties, the Company reduces its oil and natural gas reserves for the amount attributable to the sold or conveyed interest. The Company treats sales proceeds on non-significant sales as reductions to the cost of the Company’s oil and natural gas properties. The Company does not recognize a gain or loss on sales of oil and natural gas properties, unless those sales would significantly alter the relationship between capitalized costs and proved reserves. Other Property and Equipment — Other property and equipment is recorded at cost and consists primarily of leasehold improvements, office furniture and fixtures, computer hardware and software. Acquisitions, renewals and betterments are capitalized; maintenance and repairs are expensed as incurred. Depreciation is provided using the straight-line method over estimated useful lives of three to ten years Other Well Equipment Inventory — Other well equipment inventory primarily represents the cost of equipment to be used in the Company’s oil and natural gas drilling and development activities such as drilling pipe, tubulars and certain wellhead equipment. When this inventory is supplied to wells, the cost of this inventory is capitalized in oil and gas properties, and if such property is jointly owned, the proportionate costs will be reimbursed by third party participants. The Company’s inventory is stated at the lower of cost or net realizable value. The Company recorded $0.2 million, $0.2 million, and $0.3 million of impairment to adjust inventory to net realizable value, which was expensed and reflected in lease operating expense, during the years ended December 31, 2019, 2018 and 2017, respectively. Fair Value Measure of Financial Instruments — Financial instruments generally consist of cash and cash equivalents, restricted cash, accounts receivable, commodity derivatives, accounts payable and debt. The carrying amount of cash and cash equivalents, restricted cash, accounts receivable and accounts payable approximates fair value due to the highly liquid nature of these instruments. Current fair value accounting standards define fair value, establish a consistent framework for measuring fair value and stipulate the related disclosure requirements for each major asset and liability category measured at fair value on either a recurring or nonrecurring basis. These standards also clarify fair value is an exit price, presenting the amount that would be received to sell an asset or paid to transfer a liability, in an orderly transaction between market participants. The Company follows a three-level hierarchy, prioritizing and defining the types of inputs used to measure fair value depending on the degree to which they are observable as follows: Level 1 – Inputs to the valuation methodology are quoted prices (unadjusted) for identical assets or liabilities in active markets. Level 2 – Inputs to the valuation methodology include quoted prices for similar assets and liabilities in active markets, and inputs that are observable for the asset or liability, either directly or indirectly, for substantially the full term of the financial statement. Level 3 – Inputs to the valuation methodology are unobservable (little or no market data), which require the reporting entity to develop its own assumptions, and are significant to the fair value measurement. Assets and liabilities measured at fair value are based on one or more of three valuation techniques. The valuation techniques are as follows: Market Approach – Prices and other relevant information generated by market transactions involving identical or comparable assets or liabilities. Cost Approach – Amount that would be required to replace the service capacity of an asset (replacement cost). Income Approach – Techniques to convert expected future cash flows to a single present value amount based on market expectations (including present value techniques, option-pricing and excess earnings models). Authoritative guidance on financial instruments requires certain fair value disclosures to be presented. The estimated fair value amounts have been determined using available market information and valuation methodologies. Considerable judgment is required in interpreting market data to develop the estimates of fair value. The use of different assumptions or valuation methodologies may have a material effect on the estimated fair value amounts. Asset Retirement Obligations — The Company has obligations associated with the retirement of its oil and natural gas wells and related infrastructure. The Company has obligations to plug wells when production on those wells is exhausted, when the Company no longer plans to use them or when the Company abandons them. The Company accrues a liability with respect to these obligations based on its estimate of the timing and amount to replace, remove or retire the associated assets. In estimating the liability associated with its asset retirement obligations, the Company utilizes several assumptions, including a credit-adjusted risk-free interest rate, estimated costs of decommissioning services, estimated timing of when the work will be performed and a projected inflation rate. Changes in estimate represent changes to the expected amount and timing of payments to settle its asset retirement obligations. Typically, these changes result from obtaining new information about the timing of its obligations to plug and abandon oil and natural gas wells and the costs to do so. After initial recording, the liability is increased for the passage of time, with the increase being reflected as accretion expense in the Company’s consolidated statements of operations. If the Company incurs an amount different from the amount accrued for decommissioning obligations, the Company recognizes the difference as an adjustment to proved properties. Price Risk Management Activities — The Company uses commodity price derivatives to manage fluctuating oil and natural gas market risks. The Company periodically enters into commodity derivative contracts, which may require payments to (or receipts from) counterparties based on the differential between a fixed price and a variable price for a fixed quantity of oil or natural gas without the exchange of underlying volumes. Commodity derivatives are recorded on the consolidated balance sheets at fair value with settlements of such contracts and changes in the unrealized fair value recorded in earnings each period. Realized gains and losses on the settlement of commodity derivatives and changes in their unrealized gains and losses are reported in price risk management activities income (expense) in the consolidated statements of operations. The Company classifies cash flows related to derivative contracts based on the nature and purpose of the derivative. As the derivative cash flows are considered an integral part of the Company’s oil and natural gas operations, they are classified as cash flows from operating activities. The Company does not enter into derivative agreements for trading or other speculative purposes. The commodity derivative’s fair value reflects the Company’s best estimate with priority based upon exchange or over-the-counter quotations. Quoted valuations may not be available due to location differences or terms that extend beyond the period for which quotations are available. Where quotes are not available, the Company then utilizes other valuation techniques or models to estimate market values. These modeling techniques require the Company to make estimations of future prices, price correlation, market volatility and liquidity. The Company’s actual results may differ from its estimates, and these differences can be favorable or unfavorable. Leases — At inception, contracts are reviewed to determine whether the agreement contains a lease. To the extent an arrangement is determined to include a lease, it is classified as either an operating or a finance lease, which dictates the pattern of expense recognition in the income statement. Operating leases are reflected as operating lease assets, current portion of operating lease liabilities and operating lease liabilities on the consolidated balance sheet. Finance leases are included in property and equipment, other current liabilities, and other long-term liabilities in our consolidated balance sheets. A right-of-use (“ROU”) asset representing our right to use an underlying asset for the lease term and a lease liability representing our obligation to make lease payments arising from the lease are recognized on the consolidated balance sheet for all leases, regardless of classification. The ROU asset is initially measured as the present value of the lease liability adjusted for any payments made prior to commencement, including any initial direct costs incurred and incentives received. Lease liabilities are initially measured at the present value of future minimum lease payments, excluding variable lease payments, over the lease term. As most of our leases do not provide an implicit rate, we generally use our incremental borrowing rate based on the estimated rate of interest for collateralized borrowing over a similar term of the lease payments at commencement date. The Company has elected to account for lease and non-lease components in its contracts as a single lease component for all asset classes. Our lease terms may include options to extend or terminate the lease when it is reasonably certain that we will exercise that option. The Company has elected to not apply the recognition requirements of Topic 842 to leases with durations of twelve months or less (i.e. short-term). Income Taxes — Prior to the Stone Combination, Talos Energy LLC was a partnership for U.S. federal income tax purposes and was not subject to U.S. federal income tax or state income tax (in most states) at the entity level. As such, Talos Energy LLC did not recognize U.S. federal income tax expense or state income tax expense in most states. In connection with the Stone Combination, Talos Energy LLC was contributed to the Company, which is subject to U.S. federal and state income taxes. The Company records current income taxes based on estimates of current taxable income and provides for deferred income taxes to reflect estimated future income tax payments and receipts. Changes in tax laws are recorded in the period they are enacted. Deferred taxes represent the tax impacts of differences between the financial statement and tax bases of assets and liabilities and carryovers at each year end. The Company classifies all deferred tax assets and liabilities, along with any related valuation allowance, as long-term on the consolidated balance sheets. The realization of deferred tax assets depends on recognition of sufficient future taxable income during periods in which those temporary differences are deductible. The Company reduces deferred tax assets by a valuation allowance when, based on estimates, it is more likely than not that a portion of those assets will not be realized in a future period. The deferred tax asset estimates are subject to revision, either up or down, in future periods based on new facts or circumstances. In evaluating the Company’s valuation allowances, the Company considers cumulative book losses, the reversal of existing temporary differences, the existence of taxable income in carryback years, tax planning strategies and future taxable income for each of its taxable jurisdictions, the latter two of which involve the exercise of significant judgment. Changes to the Company’s valuation allowances could materially impact its results of operations. The Company’s policy is to classify interest and penalties associated with underpayment of income taxes as interest expense and general and administrative expense on the consolidated statements of operations, respectively. Income (Loss) Per Share — Basic net income per common share (“EPS”) is computed by dividing net income (loss) by the weighted average number of shares of common stock outstanding during the period. Except when the effect would be antidilutive, diluted EPS includes the impact of restricted stock units (“RSUs”), performance share units (“PSUs”) and outstanding warrants. See Note 10 — Income (Loss) Per Share for additional information. Share-Based Compensation — Certain of the Company’s employees participate in its equity based compensation. The Company measures all employee equity based compensation awards at fair value as calculated using an option pricing method for valuing such securities on the date awards are granted to its employees and recognize compensation cost on a straight-line basis in the Company’s financial statements over the vesting period of each grant according to ASC 718, Compensation—Stock Compensation. During 2019, the Company issued RSUs and PSUs to certain employees and non-employee directors. The fair value of the stock-based awards is determined at the date of grant and is not remeasured for awards classified as equity, but is remeasured at each reporting period for awards classified as a liability. The Company records share-based compensation, net of actual forfeitures, for the RSUs and PSUs in general and administrative expense on the consolidated statements of operations, net of amounts capitalized to oil and gas properties. See Note 8 — Employee Benefits Plans and Share-Based Compensation RSUs — Share-based compensation is based on the market price of the Company’s Common Stock on the grant date and recognized over the vesting period using the straight-line method as the requisite service period is fulfilled. PSUs — Share-based compensation is based on the grant date fair value determined using a Monte Carlo valuation model and recognized over the vesting period using the straight-line method. Estimates used in the Monte Carlo valuation model are considered highly-complex and subjective. The number of shares of Common Stock issuable upon vesting ranges from zero to 200% of the number of PSUs granted based on the Company’s total shareholder return (“TSR”) relative to the TSR achieved by a specified industry peer group. Share-based compensation related to PSUs is recognized as the requisite service period is fulfilled, even if the market condition is not achieved Concentration of Credit Risk Consisting principally of cash and cash equivalents, restricted cash, accounts receivable and commodity derivatives, the Company is subject to concentrated financial instruments credit risk. Cash and cash equivalents and restricted cash balances are maintained in financial institutions, which at times, exceed federally insured limits. The Company monitors the financial condition of these institutions and has not experienced losses on these accounts. Commodity derivatives are entered into with registered swap dealers, the majority of which participate in the Company’s senior reserve-based revolving credit facility (the “Bank Credit Facility”). The Company monitors the financial condition of these institutions and has not experienced losses due to counterparty default on these instruments. The Company markets substantially all of its oil and natural gas production, and all of its revenues are attributable to the U.S. The majority of the Company’s oil, natural gas and NGL production is sold to customers under short-term (less than 12 months) contracts at market-based prices. The Company’s customers consist primarily of major oil and natural gas companies, well-established oil and pipeline companies and independent oil and gas producers and suppliers. The Company performs ongoing credit evaluations of its customers and provide allowances for probable credit losses when necessary. The percent of consolidated revenue of major customers, those whose total represented 10% or more of the Company’s oil, natural gas and NGL revenues, was as follows: Year Ended December 31, 2019 2018 2017 Shell Trading (US) Company 58 % 65 % 80 % Phillips 66 28 % 18 % ** ** less than 10% The loss of a major customer could have material adverse effect on the Company in the short term. However, the Company believes it would be able to obtain other customers to market its oil, natural gas and NGL production. |
Acquisitions
Acquisitions | 12 Months Ended |
Dec. 31, 2019 | |
Business Combinations [Abstract] | |
Acquisitions | Note 3 — Acquisitions Asset Acquisitions Each of the acquisitions below qualified as an asset acquisition that requires, among other items, that the cost of the assets acquired and liabilities assumed to be recognized on the balance sheet by allocating the asset cost on a relative fair value basis. The fair value measurements of the oil and natural gas properties acquired and asset retirement obligations assumed were derived utilizing an income approach and based, in part, on significant inputs not observable in the market. These inputs represent Level 3 measurements in the fair value hierarchy and include, but are not limited to, estimates of reserves, future operating and development costs, future commodity prices, estimated future cash flows and appropriate discount rates. These inputs required significant judgments and estimates by the Company’s management at the time of the valuation. Transaction costs incurred on an asset acquisition are capitalized as a component of the assets acquired and any contingent consideration is recognized as the contingency is resolved. Acquisition of Gunflint Field — On January 11, 2019, the Company completed the acquisition of an approximate 9.6% non-operated working interest in the Gunflint Field located in the Mississippi Canyon area (the “Gunflint Acquisition”) from Samson Offshore Mapleleaf, LLC for $29.6 million ($27.9 million after customary purchase price adjustments). The following table presents the allocation of the purchase price to the assets acquired and liabilities assumed, based on their relative fair values, on January 11, 2019 (in thousands): Property and equipment $ 28,912 Asset retirement obligations (996 ) Allocated purchase price $ 27,916 Acquisition of Whistler Energy II, LLC — On August 31, 2018, the Company completed the acquisition of all the issued and outstanding membership interests of Whistler Energy II, LLC (“Whistler”) from Whistler Energy II Holdco, LLC, an affiliate of the Apollo Funds (the “Whistler Acquisition”), for $ 52.6 million ($ 14.8 million, net of $ 37.8 million of cash acquired). The $37.8 million of cash acquired consists of $ 30.8 million of cash collateral posted by Whistler and released by third party surety companies at closing and $ 7.0 million of cash on hand for working capital purposes. Through the acquisition, the Company acquired and assumed all of Whistler’s oil and natural gas assets and the associated asset retirement obligations for interests located in Green Canyon Block 18, Green Canyon Block 60 and Ewing Bank Blocks 944 and 988, including a fixed production platform on Green Canyon Block 18. The following table presents the allocation of the purchase price to the assets acquired and liabilities assumed, based on their relative fair values, on August 31, 2018 (in thousands): Current assets (1) $ 45,337 Property and equipment 35,344 Other long-term assets 66 Current liabilities (4,261 ) Asset retirement obligations (23,862 ) Allocated purchase price $ 52,624 (1) Business Combination Acquisitions qualifying as a business combination are accounted for under the acquisition method of accounting, which requires, among other items, that assets acquired and liabilities assumed be recognized on the consolidated balance sheet at their fair values as of the acquisition date. The fair value measurements of the oil and natural gas properties acquired and asset retirement obligations assumed were derived utilizing an income approach and based, in part, on significant inputs not observable in the market. These inputs represent Level 3 measurements in the fair value hierarchy and include, but are not limited to, estimates of reserves, future operating and development costs, future commodity prices, estimated future cash flows and appropriate discount rates. These inputs required significant judgments and estimates at the time of the valuation. ILX and Castex Acquisition — On December 10, 2019, the Company and Talos Production Inc., formerly known as Talos Production LLC, entered into separate Purchase and Sale Agreements (collectively, the “Purchase Agreements”) with each of the following parties: ILX Holdings, LLC (“ILX Holdings”), ILX Holdings II, LLC (“ILX Holdings II”), ILX Holdings III LLC (“ILX Holdings III”) and Castex Energy 2014, LLC (“Castex 2014”), each a related party and an affiliate of the Riverstone Funds (“Riverstone Sellers” and such Purchase Agreements the “Riverstone Purchase Agreements”), and Castex Energy 2016, LP (together with the Riverstone Sellers, the “Sellers”). Subsequent Event — On February 24, 2020, the Company, Talos Production Inc. and the Riverstone Sellers amended the Riverstone Purchase Agreements. Pursuant to the Purchase Agreements, as amended, among other things, the Company will acquire all of the issued and outstanding limited liability company interests in certain wholly owned subsidiaries of each of the respective Sellers (collectively, the “ILX and Castex Acquisition”) for an aggregate consideration of cash equal to $385.0 million and 110,000 shares of Series A Convertible Preferred Stock. Each share of Series A Convertible Preferred Stock will automatically convert into 100 shares (subject to adjustment) of Common Stock on the 20th day following the mailing of a definitive information statement relating to such conversion. On February 28, 2020, the Company completed the ILX and Castex Acquisition with an effective date of July 1, 2019. Due to the timing of the ILX and Castex Acquisition, the Company is unable to make a reasonable estimate of the purchase price allocation of such acquisition at this time. Combination Between Talos Energy LLC and Stone Energy Corporation — On May 10, 2018, the Company consummated the Transactions contemplated by the Transaction Agreement and Exchange Agreement, pursuant to which, among other things, Talos Energy LLC and Stone became wholly-owned subsidiaries of the Company. The combination was executed as an all-stock transaction whereby the former stakeholders of Talos Energy LLC held approximately 63% of the Company’s outstanding Common Stock and the former stockholders of Stone held approximately 37% of the Company’s outstanding Common Stock as of the Stone Closing Date. The purchase price of $732.0 million is based on the closing price of Stone common stock and common warrants immediately prior to closing. The following table summarizes the purchase price (in thousands, except per share data): Stone Energy common stock - issued and outstanding as of May 9, 2018 20,038 Stone Energy common stock price $ 35.49 Common stock value $ 711,149 Stone Energy common stock warrants - issued and outstanding as of May 9, 2018 3,528 Stone Energy common stock warrants price $ 5.90 Common stock warrants value $ 20,815 Total purchase price $ 731,964 During 2018, the Company incurred approximately $88.6 million of transaction related costs, of which, $32.5 million was expensed and reflected in general and administrative expense on the consolidated statements of operations. The remaining $56.1 million was the result of (i) $9.3 million in work fees paid to holders of the 11.00% Notes reflected as a debt discount reducing long-term debt on the consolidated balance sheet and (ii) $46.8 million in fees for seismic use agreements for change in control provisions and reflected in proved properties on the consolidated balance sheet. The following table presents the final allocation of the purchase price to the assets acquired and liabilities assumed, based on their fair values on May 10, 2018 (in thousands): Current assets (1) $ 372,963 Property and equipment 886,406 Other long-term assets 19,494 Current liabilities (132,846 ) Long-term debt (235,416 ) Other long-term liabilities (178,637 ) Allocated purchase price $ 731,964 (1) The follow table presents revenue and net income attributable to the assets acquired in the Stone Combination for the years ended December 31, 2019 and 2018: Year Ended December 31, 2019 2018 Revenue $ 414,056 332,944 Net income $ 187,428 148,473 Pro Forma Financial Information (Unaudited) — The following supplemental pro forma information (in thousands, except per common share amounts), presents the consolidated results of operations for the years ended December 31, 2018 and 2017 as if the Stone Combination had occurred on January 1, 2017. The unaudited pro forma information was derived from historical statements of operations of the Company and Stone and adjusted to include (i) depletion and accretion expense applied to the adjusted basis of the oil and natural gas properties acquired, (ii) interest expense to reflect the debt transactions contemplated by the Exchange Agreement and (iii) general and administrative expense adjusted for transaction related costs incurred. This information does not purport to be indicative of results of operations that would have occurred had the Stone Combination occurred on January 1, 2017, nor is such information indicative of any expected future results of operations. Year Ended December 31, 2018 2017 Revenue $ 1,013,184 $ 712,648 Net income (loss) $ 274,577 $ (100,980 ) Basic net income (loss) per common share $ 5.07 $ (1.86 ) Diluted net income (loss) per common share $ 5.07 $ (1.86 ) |
Property, Plant and Equipment
Property, Plant and Equipment | 12 Months Ended |
Dec. 31, 2019 | |
Oil And Gas Property [Abstract] | |
Property, Plant and Equipment | Note 4 — Property, Plant and Equipment Proved Properties The Company’s interests in oil and natural gas proved properties are located in the United States, primarily in the Gulf of Mexico deep and shallow waters. The Company follows the full cost method of accounting for its oil and natural gas exploration and development activities. Pursuant to SEC Regulation S-X, Rule 4-10, under the full cost method of accounting, the Company’s capitalized oil and natural gas costs are limited to a ceiling based on the present value of future net revenues from proved reserves, computed using a discount factor of 10%, plus the lower of cost or estimated fair value of unproved oil and natural gas properties not being amortized less the related tax effects. The Company performs this ceiling test calculation each quarter utilizing SEC pricing. During 2019, 2018 and 2017, the Company’s ceiling test computations did not result in a write-down of its U.S. oil and natural gas properties. At December 31, 2019, its ceiling test computation was based on SEC pricing of $61.01 per Bbl of oil, $2.59 per Mcf of natural gas and $26.17 per Bbl of NGLs. Unproved Properties Unproved capitalized costs of oil and natural gas properties excluded from amortization relate to unevaluated properties associated with acquisitions, leases awarded in the U.S. Gulf of Mexico federal lease sales, certain geological and geophysical costs, expenditures associated with certain exploratory wells in progress and capitalized interest. Unproved properties also include expenditures associated with exploration and appraisal activities in Block 7 and Block 31 located in the shallow waters off the coast of Mexico’s Veracruz and Tabasco states. The following table sets forth a summary of the Company’s oil and natural gas property costs not being amortized at December 31, 2019, by the year in which such costs were incurred (in thousands): Year Ended December 31, Total 2019 2018 2017 2016 and Prior Acquisition United States $ 42,501 $ 16,062 $ 26,439 $ — $ — Exploration United States 45,117 35,656 7,087 2,372 2 Exploration Mexico 106,914 61,809 14,362 23,332 7,411 Total unproved properties, not subject to amortization $ 194,532 $ 113,527 $ 47,888 $ 25,704 $ 7,413 The excluded costs will be included in the amortization base as properties are evaluated and proved reserves are established or impairment is determined. As a result of the Company’s evaluation of unproved property located in Block 2 offshore Mexico, specifically future exploratory drilling opportunities, results from exploratory wells drilled during the second quarter of 2019 and the Block 2 production sharing contract’s expiration date, the Company recorded a $12.2 million non-cash impairment presented as “Write-down of oil and natural gas properties” on the consolidated statements of operations for the year ended December 31, 2019. Asset Retirement Obligations The discounted asset retirement obligations included in the consolidated balance sheets in current and non-current liabilities, and the changes in that liability during each of the years ended December 31, 2019 and 2018 were as follows (in thousands): Year Ended December 31, 2019 2018 Asset retirement obligations at January 1 $ 382,817 $ 214,733 Fair value of asset retirement obligations acquired (1) 5,047 244,766 Obligations settled (75,331 ) (112,946 ) Fair value of asset retirement obligations divested (5,450 ) — Accretion expense 34,389 35,344 Obligations incurred 4,111 358 Changes in estimate 23,895 562 Asset retirement obligations at December 31 $ 369,478 $ 382,817 Less: Current portion (61,051 ) (68,965 ) Long-term portion $ 308,427 $ 313,852 (1) |
Leases
Leases | 12 Months Ended |
Dec. 31, 2019 | |
Leases [Abstract] | |
Leases | Note 5 — Leases The Company enters into service contracts and other contractual arrangements for the use of office space, drilling, completion and abandonment equipment (e.g., drilling rigs), production related equipment (e.g., compressors) and other equipment from third-party lessors to support its operations. The Company’s leasing activities as a lessor are negligible. At inception, contracts are reviewed to determine whether the agreement contains a lease. To the extent an arrangement is determined to include a lease, it is classified as either an operating or a finance lease, which dictates the pattern of expense recognition in the income statement. On August 2, 2016, the Company executed a seven-year Prior to implementation, the HP-I lease was accounted for as a capital lease under previous lease accounting treatments. The Company initially recorded a capital lease asset and liability of $124.3 million on its consolidated balance sheet at lease inception. As the HP-I is utilized in the Company’s oil and natural gas development activities, the capital lease asset was included within proved property and depleted as part of the full cost pool. Upon adoption of Topic 842, the HP-I capital lease was classified as a finance lease resulting in no change to the amounts recognized on the consolidated balance sheet. The Company has operating leases expiring at various dates, principally for office space, drilling rigs, compressors and other equipment necessary to support the Company’s operations. Operating leases are reflected as operating lease assets, current portion of operating lease liabilities and operating lease liabilities on the consolidated balance sheet. The Company’s operating lease liabilities recognized on the balance sheet as of December 31, 2019 was $18.8 million. Costs associated with the Company’s operating leases are either expensed or capitalized depending on how the underlying asset is utilized. The amounts disclosed herein primarily represent costs associated with properties operated by the Company that are presented on a gross basis and do not reflect the Company’s net proportionate share of such amounts. A portion of these costs have been or will be billed to other working interest owners. The Company’s share of these costs is included in property and equipment, lease operating expense or general and administrative expense, as applicable. The components of lease costs were as follows (in thousands): December 31, 2019 Finance lease cost - interest on lease liabilities (1) $ 19,115 Operating lease cost, excluding short-term leases (2) 3,261 Short-term lease cost (3) 85,865 Variable lease cost (4) 11 Total lease cost $ 108,252 (1) The HP-I is utilized in the Company’s oil and natural gas development activities and the right-of-use asset was capitalized and included in proved property and depleted as part of the full cost pool. Once items are included in the full cost pool, they are indistinguishable from other proved properties. The capitalized costs within the full cost pool are amortized over the life of the total proved reserved using the unit-of-production method, computed quarterly. (2) Operating lease cost reflect a single lease cost, calculated so that the cost of the lease is allocated over the lease term on a straight-line basis. (3) Short-term lease costs are reported at gross amounts and primarily represent costs incurred for drilling rigs, most of which are short-term contracts not recognized as a right-of-use asset and lease liability on the balance sheet. (4) Variable lease costs primarily represent differences between minimum payment obligations and actual operating charges incurred by the Company related to its long-term leases. The present value of the fixed lease payments recorded as the Company’s right-of-use asset and liability, adjusted for initial direct costs and incentives are as follows (in thousands): December 31, 2019 Operating leases: Operating lease assets $ 7,779 Current portion of operating lease liabilities $ 1,594 Operating lease liabilities 17,239 Total operating lease liabilities $ 18,833 Finance leases: Proved property (1) $ 124,299 Other current liabilities $ 17,509 Other long-term liabilities 62,026 Total finance lease liabilities $ 79,535 (1) The HP-I is utilized in the Company’s oil and natural gas development activities and the right-of-use asset was capitalized and included in proved property and depleted as part of the full cost pool. Once items are included in the full cost pool, they are indistinguishable from other proved properties. The capitalized costs within the full cost pool are amortized over the life of the total proved reserves using the unit-of-production method, computed quarterly. The table below presents the lease maturity by year as of December 31, 2019 (in thousands). Such commitments are reflected at undiscounted values and are reconciled to the discounted present value recognized on the consolidated balance sheet. Operating Leases Finance Leases 2020 $ 2,744 $ 33,257 2021 4,079 33,257 2022 4,302 33,257 2023 4,239 13,857 2024 3,315 — Thereafter 15,790 — Total lease payments $ 34,469 $ 113,628 Imputed interest (15,636 ) (34,093 ) Total $ 18,833 $ 79,535 The table below presents the weighted average remaining lease term and discount rate related to leases for the year ended December 31, 2019 (in thousands): December 31, 2019 Weighted average remaining lease term: Operating leases 8.4 years Finance leases 3.4 years Weighted average discount rate: Operating leases 10.2 % Finance leases 21.9 % The table below presents the supplemental cash flow information related to leases for the year ended December 31, 2019 (in thousands): Operating cash outflow from finance leases $ 19,115 Financing cash outflow from finance leases $ 14,133 Operating cash outflow from operating leases $ 1,812 Right-of-use assets obtained in exchange for new finance lease liabilities $ — Right-of-use assets obtained in exchange for new operating lease liabilities $ 2,225 |
Financial Instruments
Financial Instruments | 12 Months Ended |
Dec. 31, 2019 | |
Financial Instruments [Abstract] | |
Financial Instruments | Note 6 — Financial Instruments The following table presents the carrying amounts and estimated fair values of the Company’s financial instruments (in thousands): December 31, 2019 December 31, 2018 Carrying Amount Fair Value Carrying Amount Fair Value 11.00% Second-Priority Senior Secured Notes – due April 2022 (1) $ 383,871 $ 401,128 $ 381,229 $ 362,168 7.50% Senior Notes – due May 2022 $ 6,060 $ 5,030 $ 6,060 $ 5,151 Bank Credit Facility – matures May 2022 (1) $ 343,050 $ 350,000 $ 257,448 $ 265,000 Oil and Natural Gas Derivatives $ (11,594 ) $ (11,594 ) $ 74,923 $ 74,923 (1) As of December 31, 2019 and 2018, the carrying amounts of cash and cash equivalents, accounts receivable, restricted cash and accounts payable approximate their fair values because of the short-term nature of these instruments. 11.00% Second-Priority Senior Secured Notes – due April 2022 The $390.9 million aggregate principal amount of 11.00% Notes is reported on the consolidated balance sheet at its carrying value, net of original issue discount and deferred financing costs, see Note 7 — Debt 7.50% Senior Notes – due May 2022 The $6.1 million aggregate principal amount of 7.50% Notes is reported on the consolidated balance sheet as of December 31, 2019 at its carrying value, see Note 7 — Debt Bank Credit Facility – matures May 2022 The Company and Talos Production Inc., our wholly-owned subsidiary that was formerly known as Talos Production LLC, maintains a bank credit facility with a borrowing base of $950.0 million at December 31, 2019 (the “Bank Credit Facility”), which is reported on the consolidated balance sheet at its carrying value net of deferred financing costs (see Note 7 – Debt Oil and natural gas derivatives The Company attempts to mitigate a portion of its commodity price risk and stabilize cash flows associated with sales of oil and natural gas production through the use of oil and natural gas swaps and costless collars. Swaps are contracts where the Company either receives or pays depending on whether the oil or natural gas floating market price is above or below the contracted fixed price. Costless collars consist of a purchased put option and a sold call option with no net premiums paid to or received from counterparties. Collar contracts typically require payments by the Company if the NYMEX average closing price is above the ceiling price or payments to the Company if the NYMEX average closing price is below the floor price. The Company has elected not to designate any of its derivative contracts for hedge accounting. Accordingly, commodity derivatives are recorded on the consolidated balance sheet at fair value with settlements of such contracts, and changes in the unrealized fair value, recorded as price risk management activities income (expense) on the consolidated statements of operations in each period. The following table presents the impact that derivatives, not qualifying as hedging instruments, had on its consolidated statements of operations (in thousands): Year Ended December 31, 2019 2018 2017 Net cash received (paid) on settled derivative instruments $ (8,820 ) $ (111,147 ) $ 23,834 Unrealized gain (loss) (86,517 ) 171,582 (51,397 ) Price risk management activities income (expense) $ (95,337 ) $ 60,435 $ (27,563 ) The following table reflects the contracted volumes and weighted average prices the Company will receive under the terms of its derivative contracts as of December 31, 2019: Production Period Instrument Type Average Daily Volumes Weighted Average Swap Price Weighted Average Put Price Weighted Average Call Price Crude Oil – WTI: (Bbls) (per Bbl) (per Bbl) (per Bbl) January 2020 – December 2020 Swap 17,862 $ 56.21 $ — $ — January 2021 – June 2021 Swap 2,000 $ 53.30 $ — $ — January 2020 – December 2020 Collar 7,481 $ — $ 55.00 $ 64.23 Natural Gas – Henry Hub NYMEX: (MMBtu) (per MMBtu) (per MMBtu) (per MMBtu) January 2020 – December 2020 Swaps 16,216 $ 2.78 $ — $ — The following tables provide additional information related to financial instruments measured at fair value on a recurring basis (in thousands): December 31, 2019 Level 1 Level 2 Level 3 Total Assets: Oil and natural gas swaps and costless collars $ — $ 8,393 $ — $ 8,393 Liabilities: Oil and natural gas swaps and costless collars — (19,987 ) — (19,987 ) Total net asset $ — $ (11,594 ) $ — $ (11,594 ) December 31, 2018 Level 1 Level 2 Level 3 Total Assets: Oil and natural gas swaps and costless collars $ — $ 75,473 $ — $ 75,473 Liabilities: Oil and natural gas swaps and costless collars — (550 ) — (550 ) Total net liability $ — $ 74,923 $ — $ 74,923 Financial Statement Presentation Derivatives are classified as either current or non-current assets or liabilities based on their anticipated settlement dates. Although the Company has master netting arrangements with its counterparties, the Company presents its derivative financial instruments on a gross basis in its consolidated balance sheets. On derivative contracts recorded as assets in the table below, the Company is exposed to the risk the counterparties may not perform. The following table presents the fair value of derivative financial instruments at December 31, 2019 and 2018 (in thousands): December 31, 2019 December 31, 2018 Assets Liabilities Assets Liabilities Oil and natural gas derivatives: Current $ 8,393 $ 19,476 $ 75,473 $ 550 Non-current — 511 — — Total $ 8,393 $ 19,987 $ 75,473 $ 550 Credit Risk The Company is subject to the risk of loss on its financial instruments as a result of nonperformance by counterparties pursuant to the terms of their contractual obligations. The Company entered into International Swaps and Derivative Association agreements with counterparties to mitigate this risk. The Company also maintains credit policies with regard to its counterparties to minimize overall credit risk. These policies require (i) the evaluation of potential counterparties’ financial condition to determine their credit worthiness; (ii) the regular monitoring of counterparties’ credit exposures; (iii) the use of contract language that affords the Company netting or set off opportunities to mitigate exposure risk; and (iv) potentially requiring counterparties to post cash collateral, parent guarantees, or letters of credit to minimize credit risk. The Company’s assets and liabilities from commodity price risk management activities at December 31, 2019 represent derivative instruments from eleven counterparties; all of which are registered swap dealers that have an “investment grade” (minimum Standard & Poor’s rating of BBB- or better) credit rating, and all of which are parties under the Company’s Bank Credit Facility. The Company enters into derivatives directly with these counterparties and, subject to the terms of the Company’s Bank Credit Facility, is not required to post collateral or other securities for credit risk in relation to the derivative activities. Subsequent event The following table reflects the contracted volumes and weighted average prices the Company will receive under the terms of its derivative contracts entered into subsequent to December 31, 2019, which are not reflected in the table above: Production Period Instrument Type Average Daily Volumes Weighted Average Swap Price Weighted Average Put Price Weighted Average Call Price Crude Oil – WTI: (Bbls) (per Bbl) (per Bbl) (per Bbl) April 2020 – December 2020 Swap 4,664 $ 40.98 $ — $ — January 2021 – December 2021 Swap 1,992 $ 48.48 $ — $ — Natural Gas – Henry Hub NYMEX: (MMBtu) (per MMBtu) (per MMBtu) (per MMBtu) April 2020 – December 2020 Swaps 6,000 $ 2.15 $ — $ — January 2021 – December 2021 Swaps 5,000 $ 2.39 $ — $ — |
Debt
Debt | 12 Months Ended |
Dec. 31, 2019 | |
Debt Disclosure [Abstract] | |
Debt | Note 7 — Debt A summary of the detail comprising the Company’s debt and the related book values for the respective periods presented is as follows (in thousands): Year Ended December 31, 2019 2018 11.00% Second-Priority Senior Secured Notes – due April 2022 $ 390,868 $ 390,868 7.50% Senior Notes – due May 2022 6,060 6,060 Bank Credit Facility – matures May 2022 350,000 265,000 4.20% Building Loan – matures November 2030 — 10,567 Total debt, before discount and deferred financing cost 746,928 672,495 Discount and deferred financing cost (13,947 ) (17,191 ) Total debt, net of discount and deferred financing costs 732,981 655,304 Less: Current portion of long-term debt — (443 ) Long-term debt, net of discount and deferred financing costs $ 732,981 $ 654,861 In connection with the Stone Combination, the Company consummated the Transactions, pursuant to which (i) the Apollo Funds and Riverstone Funds contributed $102.0 million in aggregate principal amount of 9.75% Senior Notes to the Company in exchange for Common Stock; (ii) the holders of 11.00% Bridge Loans exchanged such 11.00% Bridge Loans for $172.0 million aggregate principal amount of 11.00% Notes and (iii) Franklin Noteholders and MacKay Noteholders exchanged their 7.50% Notes for $137.4 million aggregate principal amount of 11.00% Notes. An additional $81.5 million of 7.50% Notes held by non-affiliates were also exchanged for 11.00% Notes pursuant to an Exchange Offer and Consent Solicitation in connection with the Stone Combination. The exchanges to 11.00% Notes were accounted for as a debt modification. Under a debt modification, a new effective interest rate that equates the revised cash flows to the carrying amount of the 11.00% Notes is computed and applied prospectively. Costs incurred with third parties directly related to the modification are expensed as incurred. The Company incurred approximately $4.3 million of transaction fees related to the modification which were expensed and reflected in general and administrative expense on the consolidated statements of operations during the year ended December 31, 2018. The Company also paid $9.3 million in work fees to holders of the 11.00% Notes, which are reflected as debt discount reducing long-term debt on the consolidated balance sheet. 11.00% Second-Priority Senior Secured Notes – due April 2022 The 11.00% Notes were issued pursuant to an indenture dated May 10, 2018, between the Talos Issuers, the subsidiary guarantors party thereto and Wilmington Trust, National Association, as trustee and collateral agent. The 11.00% Notes mature April 3, 2022 and have interest payable semi-annually each April 15 and October 15. Prior to May 10, 2020, the Company may, at its option, redeem all or a portion of the 11.00% Notes at 105.5% of the principal amount plus accrued and unpaid interest and a make-whole premium. Thereafter, the Company may redeem all or a portion of the 11.00% Notes at redemption prices decreasing annually at May 10 from 102.75% to 100.0% plus accrued and unpaid interest. The indenture governing the 11.00% Notes applies certain limitations on the Company’s ability and the ability of its subsidiaries to, among other things, (i) incur additional indebtedness or issue certain preferred shares; (ii) pay dividends and make certain other restricted payments; (iii) create restrictions on the payment of dividends or other distributions to the Company from its restricted subsidiaries; (iv) create liens on certain assets to secure debt; (v) make certain investments; (vi) engage in sales of assets and subsidiary stock; (vii) transfer all or substantially all of its assets or enter into merger or consolidation transactions; and (viii) engage in transactions with affiliates. The 11.00% Notes contain customary quarterly and annual reporting, financial and administrative covenants. The Company was in compliance with all debt covenants at December 31, 2019. 7.50% Senior Notes – due May 2022 The 7.50% Notes represent the remaining $6.1 million of long-term debt assumed in the Stone Combination that were not exchanged for 11.00% Notes pursuant to the Exchange Offer and Consent Solicitation, and thus remain outstanding. As a result of the Exchange Offer and Consent Solicitation, substantially all of the restrictive covenants relating to the 7.50% Notes have been removed and collateral securing the 7.50% Notes has been released. The 7.50% Notes mature May 31, 2022 and have interest payable semi-annually each May 31 and November 30. Prior to May 31, 2020, the Company may, at its option, redeem up to 35% of the 7.50% Notes at 107.5% of the principal amount plus accrued and unpaid interest and a make-whole premium. Thereafter, the Company may redeem all or a portion of the 7.50% Notes at redemption prices decreasing annually at May 31 from 105.625% to 100.0% plus accrued and unpaid interest. Bank Credit Facility – matures May 2022 The Company and Talos Production Inc., a subsidiary of the Company that was formerly known as Talos Production LLC, maintains a Bank Credit Facility with a syndicate of financial institutions, with a borrowing base of $950.0 million as of year ended December 31, 2019. The Bank Credit Facility matures on May 10, 2022, provided that the Bank Credit Facility mandates a springing maturity that is 120 days prior to May 10, 2022, if greater than $25.0 million of the 11.00% Notes or any permitted refinancing indebtedness in resect thereof is outstanding on such date. The Bank Credit Facility bears interest based on the borrowing base usage, at the applicable London InterBank Offered Rate, plus applicable margins ranging from 2.75% to 3.75% or an alternate base rate, based on the federal funds effective rate plus applicable margins ranging from 1.75% to 2.75%. In addition, the Company is obligated to pay a commitment fee of 0.50% on the unfunded portion of the commitments. The Bank Credit Facility has certain debt covenants, the most restrictive of which is that the Company must maintain a total debt to EBITDAX Ratio (as defined in the Bank Credit Facility) of no greater than 3.00 to 1.00 each quarter. The Company must also maintain a current ratio no less than 1.00 to 1.00 each quarter. According to the Bank Credit Facility, undrawn commitments are included in current assets in the current ratio calculation. The Bank Credit Facility is secured by substantially all of the oil and natural gas assets of the Company. The Bank Credit Facility is fully and unconditionally guaranteed by the Company and certain of its wholly-owned subsidiaries. The Bank Credit Facility provides for determination of the borrowing base based on the Company’s proved producing reserves and a portion of its proved undeveloped reserves. The borrowing base is redetermined by the lenders at least semi-annually during the second quarter and fourth quarter. On July 3, 2019, the Company entered into a Joinder, First Amendment to Credit Agreement, and Borrowing Base Reaffirmation Agreement in which , (a) the $850.0 million borrowing base was reaffirmed, (b) the commitments were increased from $600.0 million to $850.0 million and (c) certain other amendments will be made to the Bank Credit Facility as more particularly described therein. On December 10, 2019, the Company entered into a Joinder, Commitment Increase Agreement, Second Amendment to Credit Agreement, Borrowing Base Redetermination Agreement, and Amendment to Other Credit Documents certain other amendments were made to the Bank Credit Facility as more particularly described therein. Upon closing of the ILX and Castex Acquisition, As of December 31, 2019, the Company’s borrowing base and commitments were $ 950.0 million Building Loan In connection with the Stone Combination, the Company assumed Stone’s 4.20% term loan maturing on November 20, 2030 (the “Building Loan”). The Building Loan bears interest at a rate of 4.20% per annum and is to be repaid in 180 equal monthly installments of approximately $0.1 million. During June 2019, the Company repaid $10.4 million aggregate remaining principal, plus accrued interest, of the Building Loan using proceeds from the sale of an office building in Lafayette acquired in the Stone Combination and cash on hand. As of December 31, 2019, there is no outstanding balance under the Building Loan. Subsequent Event On January 17, 2020, the Company borrowed $25.0 million from the Bank Credit Facility to fund 2020 general corporate activities. On February 27, 2020, the Company borrowed $275.0 million to fund the cash portion of the purchase price in the ILX and Castex Acquisition. On February 28, 2020, as a result of the closing of the ILX and Castex Acquisition, See Note 16 Subsequent Events |
Employee Benefits Plans and Sha
Employee Benefits Plans and Share-Based Compensation | 12 Months Ended |
Dec. 31, 2019 | |
Disclosure Of Compensation Related Costs Sharebased Payments [Abstract] | |
Employee Benefits Plans and Share-Based Compensation | Note 8 — Employee Benefits Plans and Share-Based Compensation Stone Change of Control and Severance Plans As a result of the Stone Combination, t he Company assumed the Stone Energy Corporation Executive Severance Plan and Stone Energy Corporation Employee Severance Plan, each a legacy plan of Talos Petroleum LLC (f/k/a Stone Energy Corporation). The plans provided for the payment of severance and change in control benefits to certain individuals who, prior to the Stone Combination, were executive officers or employees of Talos Petroleum LLC, in each case upon an involuntary termination within twelve months of the Stone Closing Date. For the years ended December 31, 2019 and 2018 the Company incurred $0.2 million and $7.8 million of severance expense, reflected in general and administrative expense on the consolidated statements of operations. The plans were terminated on July 11, 2019. Talos Energy Inc. Long Term Incentive Plan In 2018, the Company adopted the Talos Energy Inc. Long Term Incentive Plan (the “LTIP”), pursuant to which the Company may, subject to approval by the Talos board of directors, grant options, stock appreciation rights, restricted stock, restricted stock units, stock awards, dividend equivalents, other stock-based awards, cash awards, substitute awards or any combination of the foregoing to employees, directors and consultants. The LTIP authorizes the Company to grant awards of up to 5,374,340 shares of the Company’s Common Stock. Restricted Stock Units – Employees — RSUs granted to employees under the LTIP primarily vest ratably over an approximate three year period subject to such employee’s continued service through each vesting date. Upon vesting, each RSU represents a contingent right to receive one share of Common Stock. The total unrecognized share-based compensation expense related to these RSUs at December 31, 2019 was approximately $12.9 million, which is expected to be recognized over a weighted average period of 2.1 years. Restricted Stock Units – — RSUs granted to non-employee directors under the LTIP vested approximately one year following the date of grant, subject to such non-employee director’s continued service through the vesting date. Upon vesting, these RSUs represent a contingent right to receive one share of Common Stock for each RSU for 60%, and cash for the remaining 40%. The total unrecognized share-based compensation expense related to these RSUs at December 31, 2019 was approximately $0.1 million, which is expected to be recognized over a weighted average period of 0.2 years. Of the unrecognized share-based compensation expense, $0.1 million relates to liability awards and will be subsequently remeasured at each reporting period. The following table summarizes RSU activity for the years ended December 31, 2019 and 2018: Restricted Stock Units Weighted Average Grant Date Fair Value Unvested RSUs at December 31, 2017 — $ — Granted 139,411 33.85 Vested (53 ) 32.86 Forfeited (654 ) 32.86 Unvested RSUs at December 31, 2018 138,704 $ 33.85 Granted 732,771 24.39 Vested (69,235 ) 33.72 Forfeited (68,463 ) 25.43 Unvested RSUs at December 31, 2019 733,777 $ 25.20 Performance Share Units – Employees — PSUs granted to employees under the LTIP represent the contingent right to receive one share of Common Stock. However, the number of shares of Common Stock issuable upon vesting ranges from zero to 200% of the target number of PSUs granted based on the TSR of the Common Stock relative to the TSR achieved by a specific industry peer group over an approximate three-year The following table summarizes PSU activity for the years ended December 31, 2019 and 2018: Performance Share Units Weighted Average Grant Date Fair Value Unvested PSUs at December 31, 2017 — $ — Granted 232,891 44.47 Vested — — Forfeited (1,349 ) 42.94 Unvested PSUs at December 31, 2018 231,542 $ 44.47 Granted 218,060 33.96 Vested — — Forfeited (31,771 ) 40.27 Unvested PSUs at December 31, 2019 417,831 $ 39.31 The grant date fair value of the PSUs, calculated using a Monte Carlo simulation, was $7.4 million and $10.4 million for the years ended December 31, 2019 and 2018. The following table summarizes the assumptions used to calculate the grant date fair value of the PSUs granted for the years ended December 31, 2019 and 2018: 2019 Grant Date 2018 Grant Date March 5 May 16 August 29 September 28 Number of simulations 100,000 100,000 100,000 100,000 Expected term (in years) 2.8 2.6 2.7 2.6 Expected volatility 46.9 % 44.8 % 50.6 % 47.4 % Risk-free interest rate 2.5 % 2.1 % 2.7 % 2.9 % Dividend yield — % — % — % — % Talos Energy LLC Series B Units Prior to the Stone Combination, the Limited Liability Company Agreement of Talos Energy LLC established Series A, Series B and Series C Units. Series B Units were generally intended to be used as incentives for Talos Energy LLC employees. Series B Units do not participate in distributions prior to vesting or until Series A Units have received cumulative distributions equal to (i) the original cash contributed to the Company for such Series A Units and (ii) an 8% return, compounded annually (the “Aggregate Series A Payout”), and Series C Units have received no distributions. In connection with the Transactions, the Series A, Series B and Series C Units were exchanged for an equivalent number of units in each of an entity affiliated with the Apollo Funds and an entity affiliated with the Riverstone Funds, each of which hold Common Stock of the Company. The modification did not result in incremental value to the Series B Units. For accounting and financial reporting purposes, the Series B Units are deemed to be equity awards, and the compensation expense related to these awards is recorded on a straight-line basis over the vesting period in the Company’s consolidated financial statements and is reflected as a corresponding credit to accumulated deficit on the consolidated balance sheet. The Company’s unrecognized compensation expense at December 31, 2019 is approximately $2.4 million. Of this amount, approximately $0.2 million of the unrecognized compensation expense will continue to be recognized on a straight-line basis over the remainder of the four year requisite service period. The remaining $2.2 million will be recognized upon an Aggregate Series A Payout. The weighted-average period over which the unrecognized compensation expense for the Series B Units will be recognized is 1.1 years. New Talos Energy LLC Series B Units In connection with the transactions contemplated in the Exchange Agreement on May 10, 2018, an entity affiliated with the Apollo Funds and an entity affiliated with the Riverstone Funds, each of which hold Common Stock in the Company as a result of the Sponsor Debt Exchange, established new Series A Units (“New Series A Units”) and new Series B Units (“New Series B Units”). The New Series B Units are generally intended to be used as incentives for Talos Energy LLC employees. The New Series B Units do not participate in distributions prior to vesting or until the New Series A Units have received cumulative distributions of $102.0 million. After issuance, 80% of the New Series B Units vest on a monthly basis over a four year period based on the initial vesting schedule of the original Series B Units, subject to continued employment. All unvested New Series B Units fully vest upon the cumulative distribution of $102.0 million. For accounting and financial reporting purposes, the New Series B Units are deemed to be equity awards, and the compensation expense related to these awards is recorded on a straight-line basis over the vesting period in the Company’s consolidated financial statements and is reflected as a corresponding credit to accumulated deficit on the consolidated balance sheet. The New Series B Units issued were valued using the option pricing method for valuing securities. In this method, the rights and claims of each security are modeled as a portfolio of Black-Scholes-Merton call options written on the total equity of the entities affiliated with the Apollo Funds and Riverstone Funds. The total value of the equity is calculated in an iterative process that results in the New Series A Units being valued at par. The risk-free rate of interest is based on the U.S. Treasury yield curve on the grant date. The expected time to a liquidity event is based on a weighted average calculation of management’s estimate considering market conditions and expectations. The expected volatility of equity is based on the volatility of the assets of similar publicly traded companies using a Black-Scholes-Merton model. The discount for lack of marketability is based on the restrictions on the New Series B Units and the volatility of the New Series B Units using a Black-Scholes-Merton model. The Company’s unrecognized compensation expense at December 31, 2019 is approximately $1.0 million. Of this amount, approximately $0.1 million of the unrecognized compensation expense will continue to be recognized on a straight-line basis over the remainder of the four year requisite service period. The remaining $1.0 million will be recognized upon the New Series A Units receiving the cumulative distribution. The weighted-average period over which the unrecognized compensation expense will be recognized is 0.6 years. Share-based Compensation Expense, net Share-based compensation expense associated with RSUs, PSUs and Series B Units are reflected as general administrative expense, net amounts capitalized to oil and gas properties, in the consolidated statements of operations. Because of the non-cash nature of share-based compensation, the expensed portion of share-based compensation is added back to net income in arriving at net cash used in or provided by operating activities in the consolidated statements of cash flows. For the year ended December 31, 2019, share-based compensation expense did not have any associated income tax benefit. The Company recognized the following share-based compensation expense, net for the years ended December 31, 2019, 2018 and 2017 (in thousands): Year Ended December 31, 2019 2018 2017 Talos Energy Inc. Long Term Incentive Plan $ 12,523 $ 2,091 $ — Talos Energy LLC Series B Units 256 666 1,795 New Talos Energy LLC Series B Units 145 3,752 — Total share-based compensation expense 12,924 6,509 1,795 Less: amounts capitalized to oil and gas properties (5,960 ) (3,616 ) (920 ) Total share-based compensation expense, net $ 6,964 $ 2,893 $ 875 |
Income Taxes
Income Taxes | 12 Months Ended |
Dec. 31, 2019 | |
Income Tax Disclosure [Abstract] | |
Income Taxes | Note 9 — Income Taxes Prior to the Stone Combination, Talos Energy LLC was a partnership for U.S. federal income tax purposes and was not subject to U.S. federal income tax or state income tax (in most states) at the entity level. As such, Talos Energy LLC did not recognize U.S. federal income tax expense or state income tax expense in most states. Talos Energy LLC’s operations in the shallow waters off the coast of Mexico were conducted under a different legal form and are subject to foreign income taxes. Tax Cuts and Jobs Act On December 22, 2017, the President signed into law Public Law No. 115-97 (“Tax Act”), an Act to provide for reconciliation pursuant to titles II and V of the concurrent resolution on the budget for fiscal year 2018. The Tax Act made broad and complex changes to the U.S. tax code. The SEC issued Staff Accounting Bulletin 118, which has since been codified into ASC 740, providing guidance on the accounting for the tax effects of the Tax Act. ASC 740 provides a measurement period that should not extend beyond one year from the Tax Act enactment date to complete the accounting under ASC 740. In accordance with this pronouncement, the Company completed its assessment on certain effects of the Tax Act in the financial statements for the period ending December 31, 2018. In assessing the need for a valuation allowance on its deferred tax assets, the Company considered whether it was more likely than not that some portion or all of them will not be realized. Due to a full valuation allowance against the Company’s deferred tax assets, the adjustments did not have any net impact on tax expense for 2018. Income Tax Expense (Benefit) The components of income tax expense (benefit) were as follows (in thousands): Year Ended December 31, 2019 2018 2017 Current income tax expense United States $ 437 $ — $ — Mexico 1,183 1,345 — Total current income tax expense $ 1,620 $ 1,345 $ — Deferred income tax expense (benefit) United States $ (37,131 ) $ 1,064 $ — Mexico (630 ) 513 — Total deferred income tax expense (benefit) (37,761 ) 1,577 — Total income tax expense (benefit) $ (36,141 ) $ 2,922 $ — The reconciliation of income taxes computed at the U.S. f ederal statutory tax rate to the Company’s income tax expense is as follows (in thousands, except percentages): Year Ended December 31, 2019 2018 2017 Income tax expense (benefit) at the federal statutory tax rate $ 4,744 $ 47,137 $ (22,004 ) Earnings not subject to tax — 9,980 22,004 State income taxes 1,396 11,738 — Foreign income taxes — 1,008 — Permanent differences 340 — — Foreign rate differential (4,948 ) 432 — Prior year taxes (1,950 ) 417 — Other adjustments 137 800 — Change in tax status — (35,925 ) — Legal entity reorganization 39,336 — — Change in valuation allowance (75,196 ) (32,665 ) — Total income tax expense (benefit) $ (36,141 ) $ 2,922 $ — Effective tax rate (159.99 )% 1.30 % — % The Company’s effective tax rate for the year ending December 31, 2019 differed from the federal statutory rate of 21.0% primarily due to a non-cash tax benefit of $75.2 million related to the full release of the valuation allowance for its federal and a significant portion of its state deferred tax assets. The federal and state portion of the release equals $80.2 million, partially offset by a $5.0 million increase in valuation allowance recorded against foreign deferred tax assets. Additionally, the Company recorded a tax expense of $39.3 million related to the reorganization of our subsidiaries, of which $38.9 million represents the non-cash impact from the legal entity conversion of a partnership to a corporation. The effective tax rate for years 2018 differed from the federal statutory rate of 21% primarily due to recording a full valuation allowance against its deferred tax assets. The effective tax rate for year 2017 differed from the federal statutory rate of 35.0% because the Company was not subject to U.S. federal or state taxation as a partnership and the Company’s Mexico operations did not incur a material income tax expense. D eferred Tax Assets and Liabilities Deferred taxes reflect the net tax effects of temporary differences between the carrying amounts of assets and liabilities for financial reporting purposes and the amounts used for income tax purposes. Significant components of deferred tax assets and liabilities were as follows (in thousands): Year Ended December 31, 2019 2018 Deferred tax assets: Federal net operating loss $ 131,204 $ 117,546 Foreign tax loss carryforward 2,316 2,303 State net operating loss 24,270 23,542 Asset retirement obligations 89,059 95,546 Tax credits 449 12 Interest — 33,867 Derivatives 2,794 — Other well equipment inventory 10,014 12,901 Accrued bonus 3,753 4,042 Operating lease liabilities 2,317 2,509 Other 7,004 — Total deferred tax assets 273,180 292,268 Valuation allowance (19,118 ) (94,085 ) Total deferred tax assets, net $ 254,062 $ 198,183 Deferred tax liabilities: Oil and gas properties 211,216 179,780 Deferred financing 3,752 — Operating lease assets 1,814 — Derivatives — 18,246 Prepaid 3,419 3,371 Other — 642 Deferred tax liabilities 220,201 202,039 Net deferred tax asset (liability) $ 33,861 $ (3,856 ) Net Operating Loss The table below presents the details of the Company’s net operating loss and tax credit carryovers as of December 31, 2019 (in thousands): Amount Expiration Year Federal net operating losses $ 536,463 2035 - 2037 Federal net operating losses $ 60,948 Unlimited Foreign tax loss carryforward $ 26,879 2025 - 2029 State net operating losses $ 380,609 2020 - 2038 As of December 31, 2019, the Company had U.S. federal net operating loss carryforwards (“NOLs”) of approximately Valuation Allowance The Company recorded a valuation allowance of $19.1 million and $94.1 million as of December 31, 2019 and December 31, 2018, respectively. Deferred income tax assets and liabilities are recorded related to net operating losses and temporary differences between the book and tax basis of assets and liabilities expected to produce tax deductions and income in the future. The realization of these assets depends on recognition of sufficient future taxable income in specific tax jurisdictions in which those temporary differences or net operating losses relate. In assessing the need for a valuation allowance, the Company considers whether it is more likely than not that some portion or all of them will not be realized. Through the third quarter of 2019 and period ended December 31, 2018, the Company maintained a valuation allowance related to federal, state and foreign deferred tax assets, as there was insufficient positive evidence to overcome the substantial negative evidence of cumulative losses in these periods. During the fourth quarter of 2019, the Company reached the conclusion that it was appropriate to release the valuation allowances against its federal deferred tax assets and a significant portion of its state deferred tax assets due to the sustained positive operating performance and the availability of expected future taxable income. Additionally, the Company achieved a cumulative three-year Uncertain Tax Positions The table below sets forth the beginning and ending balance of the total amount of unrecognized tax benefits. There are no unrecognized benefits that would impact the effective tax rate if recognized. While amounts could change during the next 12 months, the Company does not anticipate having a material impact on its financial statements. Balances in the uncertain tax positions are as follows (in thousands): Year Ended December 31, 2019 2018 Total unrecognized tax benefits, beginning balance $ 360 $ — Increases in unrecognized tax benefits as a result of: Tax positions taken during a prior period 8 360 Tax positions taken during the current period 423 — Settlements with taxing authorities — — Lapse of applicable statute of limitations — — Total unrecognized tax benefits, ending balance $ 791 $ 360 The Company recognizes interest and penalties related to uncertain tax positions as interest expense and general and administrative expenses, respectively. Years open to examination The 2016 through 2018 tax years remain open to examination by the tax jurisdictions in which the Company is subject to tax. The statute of limitations with respect to the U.S. federal income tax returns of the Company for years ending on or before December 31, 2015 are closed. |
Income (Loss) Per Share
Income (Loss) Per Share | 12 Months Ended |
Dec. 31, 2019 | |
Earnings Per Share [Abstract] | |
Income (Loss) Per Share | Note 10 — Income (Loss) Per Share Basic earnings per common share is computed by dividing net income (loss) attributable to common stockholders by the weighted average number of shares of common stock outstanding during the period. Except when the effect would be antidilutive, diluted earnings per common share includes the impact of RSUs, PSUs and outstanding warrants. The following table presents the computation of the Company’s basic and diluted income (loss) per share were as follows (in thousands, except for the per share amounts): Year Ended December 31, 2019 2018 2017 Net income (loss) $ 58,729 $ 221,540 $ (62,868 ) Weighted average common shares outstanding — basic 54,185 46,058 31,244 Dilutive effect of securities 228 3 — Weighted average common shares outstanding — diluted 54,413 46,061 31,244 Net income (loss) per common share: Basic $ 1.08 $ 4.81 $ (2.01 ) Diluted $ 1.08 $ 4.81 $ (2.01 ) Anti-dilutive potentially issuable securities excluded from diluted common shares 4,220 3,538 4,282 For the periods prior to May 10, 2018, the Company retrospectively adjusted the weighted average shares used in determining earnings per share to reflect the number of shares Talos Energy LLC received in the Stone Combination. There is no impact in fiscal year 2017 on diluted earnings per common share from the RSUs, PSUs and outstanding warrants as these instruments did not exist throughout such periods. |
Related Party Transactions
Related Party Transactions | 12 Months Ended |
Dec. 31, 2019 | |
Related Party Transactions [Abstract] | |
Related Party Transactions | Note 11 — Related Party Transactions ILX and Castex Acquisition On December 10, 2019, the Company and Talos Production Inc. entered into separate Purchase Agreements with the Sellers. On February 24, 2020, the Company, Talos Production Inc. and the Riverstone Sellers amended the Riverstone Purchase Agreements. Pursuant to the Purchase Agreements, as amended, among other things, the Company will acquire all of the issued and outstanding limited liability company interest in certain wholly owned subsidiaries of each of the respective entities for aggregate consideration consisting of the following, subject to certain negotiated adjustments: (i) an aggregate amount of cash from the Company equal to $385.0 million and (ii) an aggregate of 110,000 shares of a series of the Company’s preferred stock, par value $0.01 per share, designated as the “Series A Convertible Preferred Stock.” The Series A Convertible Preferred Stock is subject to automatic conversion into Common Stock upon the terms of that certain Certificate of Designation, Preferences, Rights and Limitations related thereto (such Common Stock, the “Conversion Stock”), to be newly issued to the Riverstone Sellers. As of signing, the Company deposited into escrow $31.8 million that will be applied at closing towards the cash component of the purchase price under each Purchase Agreement. See additional details in Note 3 – Acquisitions. Whistler Acquisition On August 31, 2018, the Company acquired Whistler from Whistler Energy II Holdco, LLC, an affiliate of the Apollo Funds, for $52.6 million ($14.8 million, net of $37.8 million of cash acquired). Included in current assets acquired as of December 31, 2019 is $1.1 million in receivables from an affiliate of the Apollo Funds to reimburse the Company for certain payments made post closing. See additional details in Note 3 – Acquisitions. Equity Registration Rights Agreement On May 10, 2018, the Company entered into a Registration Rights Agreement (the “Original Equity Registration Rights Agreement”) with certain of the Apollo Funds and the Riverstone Funds, Franklin and MacKay Shields LLC, The Company and the Riverstone Sellers (and their designated affiliates) agreed under the Purchase Agreements to enter into an amendment to the Original Equity Registration Rights Agreement (such amendment, the “Registration Rights Agreement Amendment,” and the Original Equity Registration Rights Agreement, as amended by the Registration Rights Agreement Amendment, the “Registration Rights Agreement”). The Registration Rights Agreement Amendment will add each of the Riverstone Sellers (or one or more of its designated affiliates) as parties to the Registration Rights Agreement and provide such parties with customary registration rights with respect to the Series A Convertible Preferred Stock (and Conversion Stock) (each as defined below) that the Riverstone Sellers received at the closing of the ILX and Castex Acquisition (the “New Registrable Securities” and together with the Original Registrable Securities, the “Registrable Securities”). Under the Registration Rights Agreement, we are required to file a shelf registration statement within 30 days of the Company’s receipt of written request by a holder of Registrable Securities (a “Holder”). Each Holder will be limited to two demand registrations in any twelve-month period. The Holders have the right to request that we initiate underwritten offerings of the Company’s common stock; provided, that the Apollo Funds and the Riverstone Funds will have the right to demand three underwritten offerings in any twelve-month period, and Franklin and MacKay Shields will only have the collective right to demand one underwritten offering. The Holders have customary piggyback rights with respect to any underwritten offering that we conduct for as long as the Holders and their respective affiliates own 5% of the Registrable Securities. Each Holder will agree to a lock up with underwriters in the event of an underwritten offering, provided that the lock up will not apply to any Holder who does not have a right to participate in such underwritten offering. The Registration Rights Agreement will terminate with respect to Franklin and MacKay Shields in the event that either Franklin or MacKay Shields ceases to beneficially own 5% or more of the then outstanding shares of the Company’s common stock. The Registration Rights Agreement will otherwise terminate at such time as there are no Registrable Securities outstanding. The Company will bear all of the expenses incurred in connection with the offer and sale, while the Apollo Funds, the Riverstone Funds, Franklin and MacKay Shields will be responsible for paying underwriting fees, discounts and selling commissions. Fees incurred by the Company in conjunction with the Original Equity Registration Rights Agreement were $0.7 million and $1.8 million for the fiscal years ended December 31, 2019 and 2018, respectively. Stockholders’ Agreement Amendment On May 10, 2018, the Company entered into a Stockholders’ Agreement (the “Stockholders’ Agreement”) by and among the Company and the other parties thereto. On February 24, 2020, the Company and the other parties thereto amended the Stockholders’ Agreement (the “Stockholders’ Agreement Amendment”) to, among other things, add each of the Riverstone Sellers (or one or more of its designated affiliates) as parties to the Stockholders’ Agreement and provide that for purposes of determining whether the Riverstone Sellers and their affiliates continue to satisfy certain stock ownership requirements necessary to retain their rights to nominate directors to the board of directors, the Series A Convertible Preferred Stock owned by the Riverstone Sellers will be counted towards such ownership requirements on an as converted basis at the closing of the ILX and Castex Acquisition. Registration Rights Agreement Amendment In connection with the closing of the ILX and Castex Acquisition, and pursuant to the Purchase Agreements, as amended, the Company and ILX Holdings, ILX Holdings II, ILX Holdings III and Riverstone V Castex 2014 Holdings, L.P., a Delaware limited partnership and designee of Castex 2014, entered into the Registration Rights Agreement Amendment to the Registration Rights Agreement to, among other things, add each of the Riverstone Sellers (or one or more of its designated affiliates) as parties to the Registration Rights Agreement and provide such parties with customary registration rights with respect to the Company’s Series A Convertible Preferred Stock issued to the Riverstone Sellers at the closing of the ILX and Castex Acquisition. Legal Fees The Company has engaged the law firm Vinson & Elkins L.L.P. to provide legal services. An immediate family member of William S. Moss III, the Company’s Executive Vice President and General Counsel and one of its executive officers, is a partner at Vinson & Elkins L.L.P. For the years ended December 31, 2019, 2018 and 2017 approximately 4.4 Service Fee Agreement The Company entered into service fee agreements with Apollo Funds and Riverstone Funds for the provision of certain management consulting and advisory services. Under each agreement, the Company paid a fee equal to the higher of (i) a certain percentage of earnings before interest, income taxes, depletion, depreciation and amortization and (ii) a fixed fee payable quarterly, provided, however, such fees did not exceed in each case $0.5 million, in aggregate, for any calendar year. For the years ended December 31, 2019, 2018 and 2017, the Company incurred approximately nil, $0.5 million and $0.5 million, respectively, for these services. These fees are recognized in general and administrative expense on the consolidated statements of operations. In connection with the Stone Combination on May 10, 2018, the Service Fee Agreement was terminated. Debt Modification Work Fees In 2018, the Company paid $9.3 million in work fees to holders of the 11.00% Bridge Loans and 7.50% Notes to exchange into 11.00% Notes as a result of the Stone Combination. The Apollo Funds and Riverstone Funds received $4.1 million and the Franklin Noteholders and McKay Noteholders received $3.3 million as a result of the work fees paid. |
Commitments and Contingencies
Commitments and Contingencies | 12 Months Ended |
Dec. 31, 2019 | |
Commitments And Contingencies Disclosure [Abstract] | |
Commitments and Contingencies | Note 12 — Commitments and Contingencies Legal Proceedings and Other Contingencies The Company is named as a party in certain lawsuits and regulatory proceedings arising in the ordinary course of business. The Company does not expect that these matters, individually or in the aggregate, will have a material adverse effect on its financial condition. Performance Obligations Regulations with respect to offshore operations govern, among other things, engineering and construction specifications for production facilities, safety procedures, plugging and abandonment of wells, removal of facilities and to guarantee the execution of the minimum work program under the Mexico production sharing contracts. As of December 31, 2019 and 2018, the Company had secured performance bonds totaling approximately $637.3 million and $644.1 million, respectively. As of December 31, 2019 and 2018, the Company had $13.6 million and $14.7 million, respectively, in letters of credit issued under its Bank Credit Facility. The table below summarizes the Company’s total minimum commitments associated with vessel commitments and purchase obligations as of December 31, 2019 (in thousands): 2020 2021 2022 2023 Thereafter Total Vessel Commitments (1) $ 28,260 $ — $ — $ — $ — $ 28,260 Committed purchase orders (2) 61,434 — — — — 61,434 Total $ 89,694 $ — $ — $ — $ — $ 89,694 (1) (2) |
Condensed Consolidating Financi
Condensed Consolidating Financial Information | 12 Months Ended |
Dec. 31, 2019 | |
Condensed Financial Information Of Parent Company Only Disclosure [Abstract] | |
Condensed Consolidating Financial Information | Note 13 — Condensed Consolidating Financial Information Talos Energy Inc. owns no operating assets and has no operations independent of its subsidiaries. Talos Production Inc. (formerly Talos Production LLC) and Talos Production Finance Inc. issued 11.00% Notes on May 10, 2018, which are fully and unconditionally guaranteed, jointly and severally, by Talos Energy Inc. and certain 100% owned subsidiaries on a senior unsecured basis. The following condensed consolidating financial information presents the financial information of the Company on an unconsolidated stand-alone basis and its combined guarantor and combined non-guarantor subsidiaries as of and for the period indicated. Such financial information may not necessarily be indicative of the Company’s results of operations, cash flows or financial position had these subsidiaries operated as independent entities. TALOS ENERGY INC. CONSOLIDATING BALANCE SHEET AS OF December 31, 2019 (In thousands) Parent Subsidiary Issuers Guarantors Non- Guarantors Elimination Consolidated ASSETS Current assets: Cash and cash equivalents $ — $ 78,780 $ 593 $ 7,649 $ — $ 87,022 Restricted cash — — — — — — Accounts receivable Trade, net — — 107,842 — — 107,842 Joint interest, net — — 11,567 4,985 — 16,552 Other — 474 5,555 317 — 6,346 Assets from price risk management activities — 8,393 — — — 8,393 Prepaid assets — 33,323 32,529 25 — 65,877 Income tax receivable — — 116 — — 116 Other current assets — — 1,836 — — 1,836 Total current assets — 120,970 160,038 12,976 — 293,984 Property and equipment: Proved properties — — 4,066,260 — — 4,066,260 Unproved properties, not subject to amortization — — 87,618 106,914 — 194,532 Other property and equipment — 23,142 6,484 217 — 29,843 Total property and equipment — 23,142 4,160,362 107,131 — 4,290,635 Accumulated depreciation, depletion and amortization — (11,001 ) (2,053,971 ) (51 ) — (2,065,023 ) Total property and equipment, net — 12,141 2,106,391 107,080 — 2,225,612 Other long-term assets: Other well equipment inventory — — 7,732 — — 7,732 Operating lease assets — 3,178 3,224 1,377 — 7,779 Investments in subsidiaries 1,045,886 1,690,362 — — (2,736,248 ) — Other assets 33,371 364 2,136 18,504 — 54,375 1,079,257 1,827,015 2,279,521 139,937 (2,736,248 ) 2,589,482 LIABILITIES AND STOCKHOLDERS' EQUITY (DEFICIT) Current liabilities: Accounts payable 428 5,145 58,827 6,957 — 71,357 Accrued liabilities — 4,740 145,051 5,025 — 154,816 Accrued royalties — — 31,729 — — 31,729 Current portion of asset retirement obligations — — 61,051 — — 61,051 Liabilities from price risk management activities — 19,476 — — — 19,476 Accrued interest payable — 10,211 38 — — 10,249 Current portion of operating lease liabilities — 196 821 577 — 1,594 Other current liabilities 255 — 19,925 — — 20,180 Total current liabilities 683 39,768 317,442 12,559 — 370,452 Long-term liabilities: Long-term debt, net of discount and deferred financing costs — 726,921 6,060 — — 732,981 Asset retirement obligations — — 308,427 — — 308,427 Liabilities from price risk management activities — 511 — — — 511 Operating lease liabilities — 13,929 2,416 894 — 17,239 Other long-term liabilities 297 — 81,298 — — 81,595 Total liabilities 980 781,129 715,643 13,453 — 1,511,205 Commitments and Contingencies (Note 12) Stockholders' equity 1,078,277 1,045,886 1,563,878 126,484 (2,736,248 ) 1,078,277 $ 1,079,257 $ 1,827,015 $ 2,279,521 $ 139,937 $ (2,736,248 ) $ 2,589,482 TALOS ENERGY INC. CONSOLIDATING BALANCE SHEET AS OF December 31, 2018 (In thousands) Parent Subsidiary Issuers Guarantors Non- Guarantors Elimination Consolidated ASSETS Current assets: Cash and cash equivalents $ — $ 13,541 $ 100,801 $ 25,572 $ — $ 139,914 Restricted cash — — 1,248 — — 1,248 Accounts receivable Trade, net — — 103,025 — — 103,025 Joint interest, net — — 15,870 4,374 — 20,244 Other — 3,100 9,566 7,020 — 19,686 Assets from price risk management activities — 75,473 — — — 75,473 Prepaid assets — 1,225 37,639 47 — 38,911 Income tax receivable — — 10,701 — — 10,701 Other current assets — — 7,644 — — 7,644 Total current assets — 93,339 286,494 37,013 — 416,846 Property and equipment: Proved properties — — 3,629,430 — — 3,629,430 Unproved properties, not subject to amortization — — 63,104 45,105 — 108,209 Other property and equipment — 20,670 12,440 81 — 33,191 Total property and equipment — 20,670 3,704,974 45,186 — 3,770,830 Accumulated depreciation, depletion and amortization — (8,310 ) (1,711,288 ) (11 ) — (1,719,609 ) Total property and equipment, net — 12,360 1,993,686 45,175 — 2,051,221 Other long-term assets: Other well equipment inventory — — 9,224 — — 9,224 Investments in subsidiaries 1,011,359 1,560,922 — — (2,572,281 ) — Other assets — 364 2,258 73 — 2,695 1,011,359 1,666,985 2,291,662 82,261 (2,572,281 ) 2,479,986 LIABILITIES AND STOCKHOLDERS' EQUITY (DEFICIT) Current liabilities: Accounts payable 144 1,242 42,736 6,897 — 51,019 Accrued liabilities — 4,995 159,491 24,164 — 188,650 Accrued royalties — — 38,520 — — 38,520 Current portion of long-term debt — — 443 — — 443 Current portion of asset retirement obligations — — 68,965 — — 68,965 Liabilities from price risk management activities 550 — — — 550 Accrued interest payable — 10,162 38 — — 10,200 Other current liabilities — — 22,071 — — 22,071 Total current liabilities 144 16,949 332,264 31,061 — 380,418 Long-term debt, net of discount and deferred financing costs — 638,677 16,184 — — 654,861 Asset retirement obligations — — 313,852 — — 313,852 Other long-term liabilities 3,719 — 119,432 208 — 123,359 Total liabilities 3,863 655,626 781,732 31,269 — 1,472,490 Commitments and Contingencies (Note 12) Stockholders' equity 1,007,496 1,011,359 1,509,930 50,992 (2,572,281 ) 1,007,496 $ 1,011,359 $ 1,666,985 $ 2,291,662 $ 82,261 $ (2,572,281 ) $ 2,479,986 TALOS ENERGY INC. CONSOLIDATING STATEMENT OF OPERATIONS FOR THE YEAR ENDED December 31, 2019 (In thousands) Parent Subsidiary Issuers Guarantors Non-Guarantors Elimination Consolidated Revenues: Oil revenue $ — $ — $ 832,909 $ 209 $ — $ 833,118 Natural gas revenue — — 55,278 — — 55,278 NGL revenue — — 19,668 — — 19,668 Other — — 19,556 — — 19,556 Total revenue — — 927,411 209 — 927,620 Operating expenses: Lease operating expense — — 243,427 — — 243,427 Production taxes — — 1,349 — — 1,349 Depreciation, depletion and amortization — 2,690 343,201 40 — 345,931 Write-down of oil and natural gas properties — — — 12,221 — 12,221 Accretion expense — — 34,389 — — 34,389 General and administrative expense 1,107 31,567 40,863 3,672 — 77,209 Total operating expenses 1,107 34,257 663,229 15,933 — 714,526 Operating income (loss) (1,107 ) (34,257 ) 264,182 (15,724 ) — 213,094 Interest expense (7 ) (67,582 ) (29,603 ) (655 ) — (97,847 ) Price risk management activities expenses — (95,337 ) — — — (95,337 ) Other income (loss) — 1,060 1,794 (176 ) — 2,678 Income tax expense (benefit) 36,579 (1 ) (313 ) (124 ) — 36,141 Equity earnings from subsidiaries 23,263 219,380 — — (242,643 ) — Net income (loss) $ 58,728 $ 23,263 $ 236,060 $ (16,679 ) $ (242,643 ) $ 58,729 TALOS ENERGY INC. CONSOLIDATING STATEMENT OF OPERATIONS FOR THE YEAR ENDED December 31, 2018 (In thousands) Parent Subsidiary Issuers Guarantors Non-Guarantors Elimination Consolidated Revenues: Oil revenue $ — $ — $ 781,815 $ — $ — $ 781,815 Natural gas revenue — — 73,610 — — 73,610 NGL revenue — — 35,863 — — 35,863 Total revenue — — 891,288 — — 891,288 Operating expenses: Lease operating expense — — 226,291 — — 226,291 Production taxes — — 1,989 — — 1,989 Depreciation, depletion and amortization — 1,955 286,760 4 — 288,719 Accretion expense — — 35,344 — — 35,344 General and administrative expense 142 43,841 40,035 1,798 — 85,816 Total operating expenses 142 45,796 590,419 1,802 — 638,159 Operating income (loss) (142 ) (45,796 ) 300,869 (1,802 ) — 253,129 Interest expense — (58,172 ) (30,255 ) (1,687 ) — (90,114 ) Price risk management activities income — 50,025 10,410 — — 60,435 Other income (loss) — (1,563 ) 874 1,701 — 1,012 Income tax expense (1,065 ) — (360 ) (1,497 ) — (2,922 ) Equity earnings from subsidiaries 222,747 278,253 — — (501,000 ) — Net income (loss) $ 221,540 $ 222,747 $ 281,538 $ (3,285 ) $ (501,000 ) $ 221,540 TALOS ENERGY INC. CONSOLIDATING STATEMENT OF OPERATIONS FOR THE YEAR ENDED DECEMBER 31, 2017 (In thousands) Parent Subsidiary Issuers Guarantors Non-Guarantors Elimination Consolidated Revenues: Oil revenue $ — $ — $ 344,781 $ — $ — $ 344,781 Natural gas revenue — — 48,886 — — 48,886 NGL revenue — — 16,658 — — 16,658 Other — — 2,503 — — 2,503 Total revenue — — 412,828 — — 412,828 Operating expenses: Lease operating expense — — 152,748 — — 152,748 Production taxes — — 1,460 — — 1,460 Depreciation, depletion and amortization — 1,401 155,947 4 — 157,352 Accretion expense — — 19,295 — — 19,295 General and administrative expense — 21,882 14,172 619 — 36,673 Total operating expenses — 23,283 343,622 623 — 367,528 Operating income (loss) — (23,283 ) 69,206 (623 ) — 45,300 Interest expense — (48,236 ) (30,252 ) (2,446 ) — (80,934 ) Price risk management activities expense — (22,998 ) (4,565 ) — — (27,563 ) Other income (expense) — 600 (333 ) 62 — 329 Equity earnings (losses) from subsidiaries (62,868 ) 31,049 — — 31,819 — Net income (loss) $ (62,868 ) $ (62,868 ) $ 34,056 $ (3,007 ) $ 31,819 $ (62,868 ) TALOS ENERGY INC. CONSOLIDATING STATEMENT OF CASH FLOWS FOR THE YEAR ENDED December 31, 2019 (In thousands) Parent Subsidiary Issuers Guarantors Non- Guarantors Elimination Consolidated Cash flows from operating activities: Net cash provided by (used in) operating activities $ (828 ) $ (95,960 ) $ 512,956 $ (22,435 ) $ — $ 393,733 Cash flows from investing activities: Exploration, development, and other capital expenditures — (1,614 ) (380,622 ) (81,173 ) — (463,409 ) Cash paid for acquisitions, net of cash acquired — — (37,916 ) — — (37,916 ) Investments in subsidiaries — (1,580,833 ) — — 1,580,833 — Proceeds from sale of other property and equipment — — 5,369 — — 5,369 Distributions from subsidiaries — 1,660,609 — — (1,660,609 ) — Net cash provided by (used in) investing activities — 78,162 (413,169 ) (81,173 ) (79,776 ) (495,956 ) Cash flows from financing activities: Redemption of Senior Notes and other long-term debt — — (10,567 ) — — (10,567 ) Proceeds from Bank Credit Facility — 110,000 — — — 110,000 Repayment of Bank Credit Facility — (25,000 ) — — — (25,000 ) Repayment of LLC Bank Credit Facility — — — — — — Deferred financing costs — (1,963 ) — — — (1,963 ) Other deferred payments — — (9,921 ) — — (9,921 ) Payment of capital lease — — (14,133 ) — — (14,133 ) Employee stock transactions — — (333 ) — — (333 ) Capital contributions 828 — 1,350,086 229,919 (1,580,833 ) — Distributions to Subsidiary Issuer — — (1,516,375 ) (144,234 ) 1,660,609 — Net cash provided by (used in) financing activities 828 83,037 (201,243 ) 85,685 79,776 48,083 Net increase (decrease) in cash, cash equivalents and restricted cash — 65,239 (101,456 ) (17,923 ) — (54,140 ) Cash, cash equivalents and restricted cash Balance, beginning of period — 13,541 102,049 25,572 — 141,162 Balance, end of period $ — $ 78,780 $ 593 $ 7,649 $ — $ 87,022 TALOS ENERGY INC. CONSOLIDATING STATEMENT OF CASH FLOWS FOR THE YEAR ENDED December 31, 2018 (In thousands) Parent Subsidiary Issuers Guarantors Non- Guarantors Elimination Consolidated Cash flows from operating activities: Net cash provided by (used in) operating activities $ — $ (193,088 ) $ 442,890 $ 13,643 $ — $ 263,445 Cash flows from investing activities: Exploration, development, and other capital expenditures — (13,404 ) (227,228 ) (282 ) — (240,914 ) Cash paid for acquisitions, net of cash acquired — — 278,409 — — 278,409 Investments in subsidiaries — (1,316,588 ) — — 1,316,588 — Proceeds from sale of other property and equipment — — — — — — Distributions from subsidiaries — 1,694,460 9 — (1,694,469 ) — Net cash provided by (used in) investing activities — 364,468 51,190 (282 ) (377,881 ) 37,495 Cash flows from financing activities: Redemption of Senior Notes and other long-term debt — (25,152 ) (105 ) — — (25,257 ) Proceeds from Bank Credit Facility — 319,000 — — — 319,000 Repayment of Bank Credit Facility — (54,000 ) — — — (54,000 ) Repayment of LLC Bank Credit Facility — (403,000 ) — — — (403,000 ) Deferred financing costs — (17,002 ) — — — (17,002 ) Other deferred payments — — — — — — Payment of capital lease — — (12,952 ) — — (12,952 ) Employee stock transactions — — — — — — Capital contributions — — 1,301,876 14,712 (1,316,588 ) — Distributions to Subsidiary Issuer — — (1,689,898 ) (4,571 ) 1,694,469 — Net cash provided by (used in) financing activities — (180,154 ) (401,079 ) 10,141 377,881 (193,211 ) Net increase (decrease) in cash, cash equivalents and restricted cash — (8,774 ) 93,001 23,502 — 107,729 Cash, cash equivalents and restricted cash Balance, beginning of period — 22,315 9,048 2,070 — 33,433 Balance, end of period $ — $ 13,541 $ 102,049 $ 25,572 $ — $ 141,162 TALOS ENERGY INC. CONSOLIDATING STATEMENT OF CASH FLOWS FOR THE YEAR ENDED DECEMBER 31, 2017 (In thousands) Parent Subsidiary Issuers Guarantors Non- Guarantors Elimination Consolidated Cash flows from operating activities: Net cash provided by (used in) operating activities $ — $ (30,245 ) $ 204,419 $ 1,879 $ — $ 176,053 Cash flows from investing activities: Exploration, development, and other capital expenditures — (260 ) (132,317 ) (22,600 ) — (155,177 ) Cash paid for acquisitions, net of cash acquired — — (2,464 ) — — (2,464 ) Investments in subsidiaries — (577,055 ) — — 577,055 — Proceeds from sale of other property and equipment — — — — — — Distributions from subsidiaries — 611,526 6,041 — (617,567 ) — Net cash provided by (used in) investing activities — 34,211 (128,740 ) (22,600 ) (40,512 ) (157,641 ) Cash flows from financing activities: Redemption of 2018 Senior Notes — (1,000 ) — — — (1,000 ) Proceeds from Bank Credit Facility — 10,000 — — — 10,000 Repayment of Bank Credit Facility — (15,000 ) — — — (15,000 ) Payments of capital lease — — (12,412 ) — — (12,412 ) Capital contributions — — 550,555 26,500 (577,055 ) — Distributions to subsidiaries — — (611,526 ) (6,041 ) 617,567 — Net cash provided by (used in) financing activities — (6,000 ) (73,383 ) 20,459 40,512 (18,412 ) Net increase (decrease) in cash, cash equivalents and restricted cash — (2,034 ) 2,296 (262 ) — — Cash, cash equivalents and restricted cash: Balance, beginning of period — 24,349 6,752 2,332 — 33,433 Balance, end of period $ — $ 22,315 $ 9,048 $ 2,070 $ — $ 33,433 |
Selected Quarterly Financial Da
Selected Quarterly Financial Data | 12 Months Ended |
Dec. 31, 2019 | |
Quarterly Financial Information Disclosure [Abstract] | |
Selected Quarterly Financial Data (Unaudited) | Note 14 —Selected Quarterly Financial Data (Unaudited) Unaudited quarterly financial data are as follows (in thousands): March 31 June 30 September 30 December 31 Quarter Ended 2019 Revenues $ 178,713 $ 286,810 $ 228,857 $ 233,240 Operating income $ 18,369 $ 94,872 $ 52,883 $ 46,970 Price risk management activities income (expense) $ (109,579 ) $ 29,990 $ 43,760 $ (59,508 ) Net income (loss) $ (109,636 ) $ 94,764 $ 73,297 $ 304 Net income (loss) per common share: Basic $ (2.02 ) $ 1.75 $ 1.35 $ 0.01 Diluted $ (2.02 ) $ 1.74 $ 1.35 $ 0.01 Weighted average common shares outstanding: Basic 54,156 54,178 54,200 54,203 Diluted 54,156 54,451 54,430 54,559 Quarter Ended 2018 Revenues $ 145,850 $ 203,906 $ 282,868 $ 258,664 Operating income $ 48,584 $ 39,211 $ 91,361 $ 73,973 Price risk management activities income (expense) $ (51,976 ) $ (91,176 ) $ (53,330 ) $ 256,917 Net income (loss) $ (22,943 ) $ (74,912 ) $ 13,109 $ 306,286 Net income (loss) per common share: Basic $ (0.73 ) $ (1.69 ) $ 0.24 $ 5.66 Diluted $ (0.73 ) $ (1.69 ) $ 0.24 $ 5.66 Weighted average common shares outstanding: Basic 31,244 44,336 54,156 54,156 Diluted 31,244 44,336 54,164 54,159 |
Supplemental Oil and Gas Disclo
Supplemental Oil and Gas Disclosures (Unaudited) | 12 Months Ended |
Dec. 31, 2019 | |
Extractive Industries [Abstract] | |
Supplemental Oil and Gas Disclosures (Unaudited) | Note 15 —Supplemental Oil and Gas Disclosures (Unaudited) Capitalized Costs Aggregate amounts of capitalized costs relating to oil, natural gas and NGL activities and the aggregate amount of related accumulated depletion and amortization as of the dates indicated are presented below (in thousands): Year Ended December 31, 2019 2018 Proved properties $ 4,066,260 $ 3,629,430 Unproved oil and gas properties, not subject to amortization (1) 194,532 108,209 Total oil and gas properties 4,260,792 3,737,639 Less: Accumulated depletion (2,051,856 ) (1,709,614 ) Net capitalized costs $ 2,208,936 $ 2,028,025 Depletion and amortization rate (Per Boe) $ 18.05 $ 17.07 (1) Included in the depletable basis of proved oil and gas properties is the estimate of the Company’s proportionate share of asset retirement costs relating to these properties which are also reflected as asset retirement obligations in the accompanying consolidated balance sheets. At December 31, 2019 and 2018, the Company’s liability for oil and gas asset retirement obligations totaled $369.5 million and $382.8 million, respectively. Costs Incurred for Property Acquisition, Exploration and Development Activities The following table reflects the costs incurred in oil, natural gas and NGL property acquisition, exploration and development activities during the years indicated (in thousands). Costs incurred also include new asset retirement obligations established in the current year, as well as increases or decreases to the asset retirement obligations resulting from changes to cost estimates during the year. Year Ended December 31, 2019 2018 2017 Property acquisition costs: Proved properties $ 27,660 $ 850,515 $ 1,108 Unproved properties, not subject to amortization 16,062 65,063 5,778 Total property acquisition costs 43,722 915,578 6,886 Exploration costs (1) 209,161 93,780 82,887 Development costs 292,547 215,467 114,846 Total costs incurred $ 545,430 $ 1,224,825 $ 204,619 (1) Amount includes $74.2 million, $16.9 million and $22.8 million of exploration costs related to the Company’s Mexico properties for the year ended December 31, 2019, 2018 and 2017, respectively. Estimated Quantities of Proved Oil, Natural Gas and NGL Reserves The Company employs full-time experienced reserve engineers and geologists who are responsible for determining proved reserves in compliance with SEC guidelines. There are numerous uncertainties inherent in estimating quantities of proved reserves and projecting future rates of production and timing of development expenditures. The reserve data in the following tables only represent estimates and should not be construed as being exact. Engineering reserve estimates were prepared based upon interpretation of production performance data and sub-surface information obtained from the drilling of existing wells. The Company’s Director of Reserves, At December 31, 2019, 2018 and 2017, 100% of proved oil, natural gas and NGL reserves attributable to all of the Company’s oil and natural gas properties were estimated and compiled for reporting purposes by the Company’s reservoir engineers and audited by Netherland, Sewell & Associates, Inc. (“NSAI”), independent petroleum engineers and geologists. The following table presents the Company’s estimated proved reserves at its net ownership interest: Oil (MBbls) Gas (MMcf) NGL (MBbls) Oil Equivalent (MBoe) Total proved reserves at December 31, 2016 72,366 150,604 6,236 103,702 Revision of previous estimates (2,673 ) (15,860 ) 250 (5,067 ) Production (7,048 ) (16,308 ) (706 ) (10,472 ) Extensions and discoveries 10,159 9,220 767 12,462 Total proved reserves at December 31, 2017 72,804 127,656 6,547 100,625 Revision of previous estimates 2,595 (37,933 ) 3,187 (539 ) Production (11,771 ) (22,771 ) (1,176 ) (16,742 ) Purchases of reserves 44,788 95,661 2,074 62,806 Extensions and discoveries 4,123 8,411 64 5,589 Total proved reserves at December 31, 2018 112,539 171,024 10,696 151,739 Revision of previous estimates (5,553 ) (15,898 ) (1,237 ) (9,440 ) Production (13,844 ) (23,306 ) (1,228 ) (18,956 ) Purchases of reserves 2,094 2,626 130 2,662 Extensions and discoveries 11,518 21,552 620 15,730 Total proved reserves at December 31, 2019 106,754 155,998 8,981 141,735 Total proved developed reserves as of: December 31, 2017 37,460 77,577 3,315 53,704 December 31, 2018 85,530 131,364 8,104 115,528 December 31, 2019 72,016 115,381 6,733 97,979 Total proved undeveloped reserves as of: December 31, 2017 35,344 50,079 3,232 46,921 December 31, 2018 27,009 39,660 2,592 36,211 December 31, 2019 34,738 40,617 2,248 43,756 (2) During 2019, proved reserves decreased by 10.0 MMBoe primarily due to a decrease of 19.0 MMBoe of production and revision to previous estimates of 9.7 MMBoe due to the Phoenix and Ram Powell Fields. The decrease was partially offset by the addition of 15.7 MMBoe of estimated proved reserves from extensions and discoveries primarily from an evaluation of Green Canyon 21, Pompano, and Ewing Bank 305 as well as 3.0 MMBoe added through purchases from the Gunflint Acquisition. During 2018, the Company added 51.1 MMBoe of estimated proved reserves, which included 62.8 MMBoe added through purchases of 59.3 MMBoe from the Stone Combination and 3.5 MMBoe from the Whistler Acquisition. The Company also added 5.6 MMBoe of estimated proved reserves from extensions and discoveries primarily from an evaluation of Green Canyon Block 18. The increase was partially offset by a decrease of 16.7 MMBoe of production. During 2017, the Company added 12.5 MMBoe of estimated proved reserves from extensions and discoveries primarily from drilling the Tornado 2 exploration prospect in the Phoenix Field. The increase was offset by a decrease of 10.5 MMBoe of production and 5.1 MMBoe of negative performance revisions. Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil, Natural Gas and NGL Reserves The following table reflects the standardized measure of discounted future net cash flows relating to the Company’s interest in proved oil, natural gas and NGL reserves (in thousands): Year Ended December 31, 2019 2018 2017 Future cash inflows $ 7,151,875 $ 8,654,631 $ 4,308,863 Future costs: Production (1,633,432 ) (1,740,850 ) (815,509 ) Development and abandonment (1,464,270 ) (1,349,005 ) (823,164 ) Future net cash flows before income taxes 4,054,173 5,564,776 2,670,190 Future income tax expense (1) (662,317 ) (862,473 ) — Future net cash flows after income taxes 3,391,856 4,702,303 2,670,190 Discount at 10% annual rate (854,261 ) (1,362,057 ) (862,521 ) Standardized measure of discounted future net cash flows $ 2,537,595 $ 3,340,246 $ 1,807,669 (1) Future cash inflows are computed by applying SEC Pricing to year-end quantities of proved reserves. The discounted future cash flow estimates do not include the effects of derivative instruments. See the following table for base prices used in determining the standardized measure: Year Ended December 31, 2019 2018 2017 Oil price per Bbl $ 61.01 $ 69.42 $ 51.36 Natural gas price per Mcf $ 2.59 $ 3.08 $ 3.20 NGL price per Bbl $ 26.17 $ 29.50 $ 24.64 Future net cash flows are discounted at the prescribed rate of 10%. Actual future net cash flows may vary considerably from these estimates. Although the Company’s estimates of total proved reserves, development costs and production rates were based on the best information available, the development and production of oil and gas reserves may not occur in the periods assumed. Actual prices realized, costs incurred and production quantities may vary significantly from those used. Therefore, such estimated future net cash flow computations should not be considered to represent the Company’s estimate of the expected revenues or the current value of existing proved reserves. F-48 Changes in Standardized Measure of Discounted Future Net Cash Flows Principal changes in the standardized measure of discounted future net cash flows attributable to the Company’s proved oil, natural gas and NGL reserves are as follows (in thousands): Year Ended December 31, 2019 2018 2017 Standardized measure, beginning of year $ 3,340,246 $ 1,807,669 $ 1,336,035 Sales and transfers of oil, net gas and NGLs produced during the period (665,226 ) (727,969 ) (288,942 ) Net change in prices and production costs (849,696 ) 1,578,330 555,100 Changes in estimated future development costs (75,564 ) 32,328 (156,282 ) Previously estimated development costs incurred 117,049 45,937 146,687 Accretion of discount 392,526 180,767 133,603 Net change in income taxes (1) 129,590 (585,017 ) — Purchases of reserves 75,009 943,519 — Extensions and discoveries 306,515 148,068 328,565 Net change due to revision in quantity estimates (199,576 ) 190,853 (113,629 ) Changes in production rates (timing) and other (33,278 ) (274,239 ) (133,468 ) Standardized measure, end of year $ 2,537,595 $ 3,340,246 $ 1,807,669 (1) |
Subsequent Events
Subsequent Events | 12 Months Ended |
Dec. 31, 2019 | |
Subsequent Events [Abstract] | |
Subsequent Events | Note 16 —Subsequent Events ILX and Castex Acquisition For additional information, see Note 3 — Acquisitions. Derivative Contracts For additional information, see Note 6 — Financial Instruments. Debt For additional information, see Note 7 — Debt |
Summary of Significant Accoun_2
Summary of Significant Accounting Policies (Policies) | 12 Months Ended |
Dec. 31, 2019 | |
Organization Consolidation And Presentation Of Financial Statements [Abstract] | |
Formation and Nature of Business | Formation and Nature of Business Talos Energy Inc. (“Talos” or the “Company”) is a technically driven independent exploration and production company focused on safely and efficiently maximizing value through our operations, currently in the United States (“U.S.”) Gulf of Mexico and offshore Mexico. The Company leverages decades of geology, geophysics and offshore operations expertise towards the acquisition, exploration, exploitation and development of assets in key geological trends that are present in many offshore basins around the world. Talos Energy Inc. was formed in connection with the previously disclosed business combination between Talos Energy LLC and Stone Energy Corporation (“Stone”) that occurred on May 10, 2018, pursuant to which Talos Energy LLC and Stone became indirect wholly owned subsidiaries of Talos Energy Inc. Talos Energy LLC — Talos Energy LLC was formed in 2011 and commenced commercial operations on February 6, 2013. Prior to February 6, 2013, Talos Energy LLC had incurred certain general and administrative expenses associated with the start-up of its operations. On February 3, 2012, Talos Energy LLC completed a transaction with funds and other alternative investment vehicles managed by Apollo Management VII, L.P. and Apollo Commodities Management, L.P., with respect to Series I (“Apollo Funds”), and entities controlled by or affiliated with Riverstone Energy Partners V, L.P. (“Riverstone Funds”, and together with the Apollo Funds, the “Sponsors”) and members of management pursuant to which the Company received a private equity capital commitment. Stone Combination — On May 10, 2018 (the “Stone Closing Date”), the Company (f/k/a Sailfish Energy Holdings Corporation) consummated the transactions contemplated by that certain Transaction Agreement, dated as of November 21, 2017 (the “Transaction Agreement”), by and among Stone, the Company, Sailfish Merger Sub Corporation (“Merger Sub”), Talos Energy LLC and Talos Production LLC (which was converted into a Delaware Corporation and named Talos Production Inc. in 2019), pursuant to which, among other items, each of Stone, Talos Production LLC and Talos Energy LLC became wholly-owned subsidiaries of the Company (the “Stone Combination”). Prior to the Stone Closing Date, the Company did not conduct any material activities other than those incident to its formation and the matters contemplated by the Transaction Agreement. On the Stone Closing Date, the following transactions, among others, occurred: (i) Stone underwent a reorganization pursuant to which Merger Sub merged with and into Stone, with Stone continuing as the surviving corporation and a direct wholly-owned subsidiary of the Company (the “Merger”) and each share of Stone’s common stock outstanding immediately prior to the Merger (other than treasury shares held by Stone, which were cancelled for no consideration) was converted into the right to receive one share of the Company’s common stock, par value $0.01 (the “Common Stock”) and (ii) the Sponsors contributed all of the equity interests in Talos Production LLC (which at that time owned 100% of the equity interests in Talos Energy LLC) to the Company in exchange for an aggregate of 31,244,085 shares of Common Stock (the “Sponsor Equity Exchange”). Concurrently with the consummation of the Transaction Agreement, the Company consummated the transactions contemplated by that certain Exchange Agreement, dated as of November 21, 2017 (the “Exchange Agreement”), among the Company, Stone, the Talos Issuers (defined below), the various lenders and noteholders of the Talos Issuers listed therein, certain funds controlled by Franklin Advisers, Inc. (“Franklin”) (such controlled noteholders, the “Franklin Noteholders”), and certain clients of MacKay Shields LLC (“MacKay Shields”) (such noteholders, the “MacKay Noteholders”), pursuant to which (i) the Apollo Funds and Riverstone Funds contributed $102.0 million in aggregate principal amount of 9.75% Senior Notes due 2022 (“9.75% Senior Notes”) issued by Talos Production LLC and Talos Production Finance, Inc. (together, the “Talos Issuers”) to the Company in exchange for an aggregate of 2,874,049 shares of Common Stock (the “Sponsor Debt Exchange”); (ii) the holders of second lien bridge loans (“11.00% Bridge Loans”) issued by the Talos Issuers exchanged such 11.00% Bridge Loans for $172.0 million aggregate principal amount of 11.00% Second-Priority Senior Secured Notes due 2022 of the Talos Issuers (“11.00% Notes”) and (iii) Franklin Noteholders and MacKay Noteholders exchanged their 7.50% Senior Notes due 2022 issued by Stone (“7.50% Notes”) for $137.4 million aggregate principal amount of 11.00% Notes. Substantially concurrent therewith, the Company consummated an exchange offer and consent solicitation, pursuant to which the holders of the 7.50% Notes, excluding the 7.50% Notes held by the Franklin Noteholders and the MacKay Noteholders, exchanged their 7.50% Notes for 11.00% Notes and a cash payment, and a solicitation of consents to proposed amendments to the 7.50% Notes. Approximately $81.5 million in aggregate principal amount of the 7.50% Notes were validly tendered, and approximately $6.1 million in aggregate principal amount of 7.50% Notes remained outstanding as of the Stone Closing Date. As a result of the closing of the transactions contemplated by the Transaction Agreement and the Exchange Agreement (the “Transactions”) the former stakeholders of Talos Energy LLC held approximately 63% of the Company’s outstanding Common Stock and the former stockholders of Stone held approximately 37% of the Company’s outstanding Common Stock as of the Stone Closing Date. |
Basis of Presentation and Consolidation | Basis of Presentation and Consolidation The consolidated financial statements have been prepared in accordance with accounting principles generally accepted in the United States of America (“GAAP”) and include each subsidiary from the date of inception. All intercompany transactions have been eliminated. All adjustments are of a normal, recurring nature and are necessary to fairly present the financial position, results of operations and cash flows for the periods are reflected herein. The Company has evaluated subsequent events through the date the consolidated financial statements were issued. Talos Energy LLC was considered the accounting acquirer in the Stone Combination under GAAP. Accordingly, the historical financial and operating data of Talos Energy Inc., which covers periods prior to the Stone Closing Date, reflects the assets, liabilities and results of operations of Talos Energy LLC and does not reflect the assets, liabilities and results of operations of Stone. For the periods prior to May 10, 2018, the Company retrospectively adjusted its Statement of Changes in Stockholders’ Equity and the weighted average shares used in determining earnings per share to reflect the number of shares Talos Energy LLC received in the Stone Combination. Beginning on May 10, 2018, common stock is presented to reflect the legal capital of Talos Energy Inc. The preparation of financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities as of the date of the financial statements, the reported amounts of revenues and expenses during the reporting periods and the reported amounts of proved oil and natural gas reserves. Actual results could differ from those estimates. For presentation purposes, as of December 31, 2019, operating expenses previously presented as “Direct lease operating expense,” “Insurance” and “Workover and maintenance expense” have been combined and presented as “Lease operating expense” on our Consolidated Statements of Operations. Such reclassification had no effect on our results of operations, financial position or cash flows. The Company has one reportable segment, which is the exploration and production of oil and natural gas. Substantially all the Company’s long-lived assets, proved reserves and production sales are related to the Company’s operations in the United States. |
Recently Adopted Or Issued Accounting Standards | Recently Adopted Accounting Standards Leases — In February 2016, the Financial Accounting Standards Board issued Accounting Standards Codification 2016-02, Leases (“Topic 842”) requiring an entity to recognize a right-of-use asset representing the right to use an underlying asset for the lease term and a lease liability representing the obligation associated with future lease payments for virtually all leases. The pattern of expense recognition in the income statement is dependent on lease classification as finance or operating. A lease is defined as a contract, or part of a contract, that conveys the right to control the use of identified property, plant or equipment (an identified asset) for a period of time in exchange for consideration. However, Topic 842 does not apply to leases of mineral rights. On January 1, 2019, the Company adopted Topic 842, using the modified retrospective approach, which does not require an adjustment to comparative-period financial statements. As such, results for reporting periods beginning January 1, 2019 are presented in accordance with Topic 842, while prior period amounts are reported in accordance with previous lease accounting treatment. The Company elected the package of practical expedients permitted under the transition guidance within the new standard, which, among other items, allowed Talos not to reassess whether expired or existing contracts, including land easements, contain a lease or reassess the classification and indirect costs associated with existing or expired leases. On the January 1, 2019 adoption date, the Company recorded a right-of-use asset of approximately $7.3 million and corresponding lease liability of $16.9 million representing the present value of its future operating lease payments. Upon the adoption of Topic 842, lease incentives are presented as a reduction to the right-of-use asset resulting in the difference between the right-of-use asset and lease liability. Adoption of this standard did not require an adjustment to retained earnings and did not impact the consolidated statements of operations, consolidated statements of cash flows or consolidated statements of changes in stockholders’ equity. See Note 5 – Leases Recently Issued Accounting Standards In June 2016, the FASB issued ASU 2016-13, Financial Instruments - Credit Losses (Topic 326): Measurement of Credit Losses on Financial Instruments |
Cash and Cash Equivalents | Cash and Cash Equivalents — The Company presents cash as cash and cash equivalents on the Company’s consolidated balance sheets. The Company considers all cash, money market funds and highly liquid investments with an original maturity of three months or less as cash and cash equivalents. Cash and cash equivalents are carried at cost, which approximates fair value. |
Accounts Receivable and Allowance for Uncollectible Accounts | Accounts Receivable and Allowance for Uncollectible Accounts — Accounts receivable are stated at the historical carrying amount net of an allowance for uncollectible accounts of $9.9 million at December 31, 2019 and $8.7 million at December 31, 2018. The Company establishes provisions for losses on accounts receivable with other parties if it believes that it will not collect all or part of the outstanding balance. On a quarterly basis, the Company reviews collectability and establishes or adjusts the Company’s allowance as necessary using the specific identification method. The Company presented $18.0 million of refund claims for value added taxes paid in Mexico in other assets on the consolidated balance sheets as of December 31, 2019. |
Prepaid Assets | Prepaid Assets — Prepaid assets primarily represent deposits with the Office of Natural Resources Revenue (“ONRR”) and transaction escrow related to the ILX and Castex Acquisition as further defined in Note 3 — Acquisitions. The deposits with ONRR represent the Company’s estimated federal royalties payable within thirty days of the production date. On a monthly basis the Company adjusts the deposit based on actual royalty payments remitted to the ONRR. The transaction escrow was applied to the purchase price that closed in the first quarter of 2020. The escrow for the year ended December 31, 2019 was $31.8 million. |
Revenue Recognition | Revenue Recognition — Revenues are recorded based from the sale of oil, natural gas and NGL quantities sold to purchasers. The Company records revenues from the sale of oil, natural gas and NGLs based on quantities of production sold to purchasers under short-term contracts (less than twelve months) at market prices when delivery to the customer has occurred, title has transferred, prices are fixed and determinable and collection is reasonably assured. This occurs when production has been delivered to a pipeline or when a barge lifting has occurred. The Company recognizes transportation costs as a component of lease operating expense when it is the shipper of the product. Each unit of product typically represents a separate performance obligation, therefore, future volumes are wholly unsatisfied and disclosure of the transaction price allocated to remaining performance obligations is not required. Gas Imbalances — Prior to the adoption of A ccounting Standards Codification (“ASC”) 606 in 2018 , the Company used the entitlement method to account for sales and production. Under the entitlement method, revenue was recorded based on the Company’s entitled share of production with any difference recorded as an imbalance on the consolidated balance sheet. Upon the adoption of ASC 606 in 2018 , revenues are recorded based on the actual sales volumes sold to purchasers. An imbalance receivable or payable is recorded only to the extent the imbalance is in excess of its share of remaining proved developed reserves in an underlying property. The change in accounting method from the entitlements method to the sales method resulted in an immaterial cumulative-effect adjustment to stockholders’ deficit on the date of adoption. Production Handling Fees — Prior to the adoption of ASC 606 in 2018, the Company presented certain reimbursements for costs from certain third parties as other revenue on the consolidated statements of operations. Upon the adoption of ASC 606 in 2018, the reimbursements are presented as a reduction of lease operating expense on the consolidated statements of operations. The impact of the reclassification for the year ended December 31, 2018 was immaterial . Other Revenue — Other revenues primarily represents a multi -year federal royalty refund claim from the ONRR. The company records revenue when a refund is filed and its collection is reasonably assured. The refunds for the year ended December 31, 2019 was $19.3 million. |
Accounting for Oil and Natural Gas Activities | Accounting for Oil and Natural Gas Activities — The Company follows the full cost method of accounting for oil and natural gas exploration and development activities. Under the full cost method, substantially all costs incurred in connection with the acquisition, development and exploration of oil and natural gas reserves are capitalized. These capitalized amounts include the internal costs directly related to acquisition, development and exploration activities, asset retirement costs and capitalized interest. Under the full cost method, dry hole costs and geological and geophysical costs are capitalized into the full cost pool, which is subject to amortization and assessed for impairment on a quarterly basis through a ceiling test calculation as discussed below. Capitalized costs associated with proved reserves are amortized on a country by country basis over the life of the total proved reserves using the unit of production method, computed quarterly. Conversely, capitalized costs associated with unproved properties and related geological and geophysical costs, exploration wells currently drilling and capitalized interest are initially excluded from the amortizable base. The Company transfers unproved property costs into the amortizable base when properties are determined to have proved reserves or when the Company has completed an unproved properties evaluation resulting in an impairment. The Company evaluates each of these unproved properties individually for impairment at least quarterly. Additionally, the amortizable base includes future development costs, dismantlement, restoration and abandonment costs, net of estimated salvage values, and geological and geophysical costs incurred that cannot be associated with specific unproved properties or prospects in which the Company owns a direct interest. The Company capitalizes overhead costs that are directly related to exploration, acquisition and development activities. Capitalized overhead for the years ended December 31, 2019, 2018 and 2017 was $28.2 million, $21.9 million and $13.7 million, respectively. The Company’s capitalized costs are limited to a ceiling based on the present value of future net revenues from proved reserves, computed using a discount factor of 10 percent, plus the lower of cost or estimated fair value of unproved oil and natural gas properties not being amortized less the related tax effects. Any costs in excess of the ceiling are recognized as a non-cash impairment expense on the consolidated statements of operations and an increase to accumulated depreciation, depletion and amortization on the Company’s consolidated balance sheets. The expense may not be reversed in future periods, even though higher oil, natural gas and NGL prices may subsequently increase the ceiling. The Company performs this ceiling test calculation each quarter. In accordance with the SEC rules and regulations, the Company utilizes SEC Pricing when performing the ceiling test. The Company also holds prices and costs constant over the life of the reserves, even though actual prices and costs of oil and natural gas are often volatile and may change from period to period. Under the full cost method of accounting for oil and natural gas operations, assets whose costs are currently being depreciated, depleted or amortized are assets in use in the earnings activities of the enterprise and do not qualify for capitalization of interest cost. Investments in unproved properties for which exploration and development activities are in progress and other major development projects that are not being currently depreciated, depleted or amortized are assets qualifying for capitalization of interest costs. When the Company sells or conveys interests in oil and natural gas properties, the Company reduces its oil and natural gas reserves for the amount attributable to the sold or conveyed interest. The Company treats sales proceeds on non-significant sales as reductions to the cost of the Company’s oil and natural gas properties. The Company does not recognize a gain or loss on sales of oil and natural gas properties, unless those sales would significantly alter the relationship between capitalized costs and proved reserves. |
Other Property and Equipment | Other Property and Equipment — Other property and equipment is recorded at cost and consists primarily of leasehold improvements, office furniture and fixtures, computer hardware and software. Acquisitions, renewals and betterments are capitalized; maintenance and repairs are expensed as incurred. Depreciation is provided using the straight-line method over estimated useful lives of three to ten years |
Other Well Equipment Inventory | Other Well Equipment Inventory — Other well equipment inventory primarily represents the cost of equipment to be used in the Company’s oil and natural gas drilling and development activities such as drilling pipe, tubulars and certain wellhead equipment. When this inventory is supplied to wells, the cost of this inventory is capitalized in oil and gas properties, and if such property is jointly owned, the proportionate costs will be reimbursed by third party participants. The Company’s inventory is stated at the lower of cost or net realizable value. The Company recorded $0.2 million, $0.2 million, and $0.3 million of impairment to adjust inventory to net realizable value, which was expensed and reflected in lease operating expense, during the years ended December 31, 2019, 2018 and 2017, respectively. |
Fair Value Measure of Financial Instruments | Fair Value Measure of Financial Instruments — Financial instruments generally consist of cash and cash equivalents, restricted cash, accounts receivable, commodity derivatives, accounts payable and debt. The carrying amount of cash and cash equivalents, restricted cash, accounts receivable and accounts payable approximates fair value due to the highly liquid nature of these instruments. Current fair value accounting standards define fair value, establish a consistent framework for measuring fair value and stipulate the related disclosure requirements for each major asset and liability category measured at fair value on either a recurring or nonrecurring basis. These standards also clarify fair value is an exit price, presenting the amount that would be received to sell an asset or paid to transfer a liability, in an orderly transaction between market participants. The Company follows a three-level hierarchy, prioritizing and defining the types of inputs used to measure fair value depending on the degree to which they are observable as follows: Level 1 – Inputs to the valuation methodology are quoted prices (unadjusted) for identical assets or liabilities in active markets. Level 2 – Inputs to the valuation methodology include quoted prices for similar assets and liabilities in active markets, and inputs that are observable for the asset or liability, either directly or indirectly, for substantially the full term of the financial statement. Level 3 – Inputs to the valuation methodology are unobservable (little or no market data), which require the reporting entity to develop its own assumptions, and are significant to the fair value measurement. Assets and liabilities measured at fair value are based on one or more of three valuation techniques. The valuation techniques are as follows: Market Approach – Prices and other relevant information generated by market transactions involving identical or comparable assets or liabilities. Cost Approach – Amount that would be required to replace the service capacity of an asset (replacement cost). Income Approach – Techniques to convert expected future cash flows to a single present value amount based on market expectations (including present value techniques, option-pricing and excess earnings models). Authoritative guidance on financial instruments requires certain fair value disclosures to be presented. The estimated fair value amounts have been determined using available market information and valuation methodologies. Considerable judgment is required in interpreting market data to develop the estimates of fair value. The use of different assumptions or valuation methodologies may have a material effect on the estimated fair value amounts. |
Asset Retirement Obligations | Asset Retirement Obligations — The Company has obligations associated with the retirement of its oil and natural gas wells and related infrastructure. The Company has obligations to plug wells when production on those wells is exhausted, when the Company no longer plans to use them or when the Company abandons them. The Company accrues a liability with respect to these obligations based on its estimate of the timing and amount to replace, remove or retire the associated assets. In estimating the liability associated with its asset retirement obligations, the Company utilizes several assumptions, including a credit-adjusted risk-free interest rate, estimated costs of decommissioning services, estimated timing of when the work will be performed and a projected inflation rate. Changes in estimate represent changes to the expected amount and timing of payments to settle its asset retirement obligations. Typically, these changes result from obtaining new information about the timing of its obligations to plug and abandon oil and natural gas wells and the costs to do so. After initial recording, the liability is increased for the passage of time, with the increase being reflected as accretion expense in the Company’s consolidated statements of operations. If the Company incurs an amount different from the amount accrued for decommissioning obligations, the Company recognizes the difference as an adjustment to proved properties. |
Price Risk Management Activities | Price Risk Management Activities — The Company uses commodity price derivatives to manage fluctuating oil and natural gas market risks. The Company periodically enters into commodity derivative contracts, which may require payments to (or receipts from) counterparties based on the differential between a fixed price and a variable price for a fixed quantity of oil or natural gas without the exchange of underlying volumes. Commodity derivatives are recorded on the consolidated balance sheets at fair value with settlements of such contracts and changes in the unrealized fair value recorded in earnings each period. Realized gains and losses on the settlement of commodity derivatives and changes in their unrealized gains and losses are reported in price risk management activities income (expense) in the consolidated statements of operations. The Company classifies cash flows related to derivative contracts based on the nature and purpose of the derivative. As the derivative cash flows are considered an integral part of the Company’s oil and natural gas operations, they are classified as cash flows from operating activities. The Company does not enter into derivative agreements for trading or other speculative purposes. The commodity derivative’s fair value reflects the Company’s best estimate with priority based upon exchange or over-the-counter quotations. Quoted valuations may not be available due to location differences or terms that extend beyond the period for which quotations are available. Where quotes are not available, the Company then utilizes other valuation techniques or models to estimate market values. These modeling techniques require the Company to make estimations of future prices, price correlation, market volatility and liquidity. The Company’s actual results may differ from its estimates, and these differences can be favorable or unfavorable. |
Leases | Leases — At inception, contracts are reviewed to determine whether the agreement contains a lease. To the extent an arrangement is determined to include a lease, it is classified as either an operating or a finance lease, which dictates the pattern of expense recognition in the income statement. Operating leases are reflected as operating lease assets, current portion of operating lease liabilities and operating lease liabilities on the consolidated balance sheet. Finance leases are included in property and equipment, other current liabilities, and other long-term liabilities in our consolidated balance sheets. A right-of-use (“ROU”) asset representing our right to use an underlying asset for the lease term and a lease liability representing our obligation to make lease payments arising from the lease are recognized on the consolidated balance sheet for all leases, regardless of classification. The ROU asset is initially measured as the present value of the lease liability adjusted for any payments made prior to commencement, including any initial direct costs incurred and incentives received. Lease liabilities are initially measured at the present value of future minimum lease payments, excluding variable lease payments, over the lease term. As most of our leases do not provide an implicit rate, we generally use our incremental borrowing rate based on the estimated rate of interest for collateralized borrowing over a similar term of the lease payments at commencement date. The Company has elected to account for lease and non-lease components in its contracts as a single lease component for all asset classes. Our lease terms may include options to extend or terminate the lease when it is reasonably certain that we will exercise that option. The Company has elected to not apply the recognition requirements of Topic 842 to leases with durations of twelve months or less (i.e. short-term). |
Income Taxes | Income Taxes — Prior to the Stone Combination, Talos Energy LLC was a partnership for U.S. federal income tax purposes and was not subject to U.S. federal income tax or state income tax (in most states) at the entity level. As such, Talos Energy LLC did not recognize U.S. federal income tax expense or state income tax expense in most states. In connection with the Stone Combination, Talos Energy LLC was contributed to the Company, which is subject to U.S. federal and state income taxes. The Company records current income taxes based on estimates of current taxable income and provides for deferred income taxes to reflect estimated future income tax payments and receipts. Changes in tax laws are recorded in the period they are enacted. Deferred taxes represent the tax impacts of differences between the financial statement and tax bases of assets and liabilities and carryovers at each year end. The Company classifies all deferred tax assets and liabilities, along with any related valuation allowance, as long-term on the consolidated balance sheets. The realization of deferred tax assets depends on recognition of sufficient future taxable income during periods in which those temporary differences are deductible. The Company reduces deferred tax assets by a valuation allowance when, based on estimates, it is more likely than not that a portion of those assets will not be realized in a future period. The deferred tax asset estimates are subject to revision, either up or down, in future periods based on new facts or circumstances. In evaluating the Company’s valuation allowances, the Company considers cumulative book losses, the reversal of existing temporary differences, the existence of taxable income in carryback years, tax planning strategies and future taxable income for each of its taxable jurisdictions, the latter two of which involve the exercise of significant judgment. Changes to the Company’s valuation allowances could materially impact its results of operations. The Company’s policy is to classify interest and penalties associated with underpayment of income taxes as interest expense and general and administrative expense on the consolidated statements of operations, respectively. |
Income (Loss) Per Share | Income (Loss) Per Share — Basic net income per common share (“EPS”) is computed by dividing net income (loss) by the weighted average number of shares of common stock outstanding during the period. Except when the effect would be antidilutive, diluted EPS includes the impact of restricted stock units (“RSUs”), performance share units (“PSUs”) and outstanding warrants. See Note 10 — Income (Loss) Per Share for additional information. |
Share-Based Compensation | Share-Based Compensation — Certain of the Company’s employees participate in its equity based compensation. The Company measures all employee equity based compensation awards at fair value as calculated using an option pricing method for valuing such securities on the date awards are granted to its employees and recognize compensation cost on a straight-line basis in the Company’s financial statements over the vesting period of each grant according to ASC 718, Compensation—Stock Compensation. During 2019, the Company issued RSUs and PSUs to certain employees and non-employee directors. The fair value of the stock-based awards is determined at the date of grant and is not remeasured for awards classified as equity, but is remeasured at each reporting period for awards classified as a liability. The Company records share-based compensation, net of actual forfeitures, for the RSUs and PSUs in general and administrative expense on the consolidated statements of operations, net of amounts capitalized to oil and gas properties. See Note 8 — Employee Benefits Plans and Share-Based Compensation RSUs — Share-based compensation is based on the market price of the Company’s Common Stock on the grant date and recognized over the vesting period using the straight-line method as the requisite service period is fulfilled. PSUs — Share-based compensation is based on the grant date fair value determined using a Monte Carlo valuation model and recognized over the vesting period using the straight-line method. Estimates used in the Monte Carlo valuation model are considered highly-complex and subjective. The number of shares of Common Stock issuable upon vesting ranges from zero to 200% of the number of PSUs granted based on the Company’s total shareholder return (“TSR”) relative to the TSR achieved by a specified industry peer group. Share-based compensation related to PSUs is recognized as the requisite service period is fulfilled, even if the market condition is not achieved |
Concentration of Credit Risk | Concentration of Credit Risk Consisting principally of cash and cash equivalents, restricted cash, accounts receivable and commodity derivatives, the Company is subject to concentrated financial instruments credit risk. Cash and cash equivalents and restricted cash balances are maintained in financial institutions, which at times, exceed federally insured limits. The Company monitors the financial condition of these institutions and has not experienced losses on these accounts. Commodity derivatives are entered into with registered swap dealers, the majority of which participate in the Company’s senior reserve-based revolving credit facility (the “Bank Credit Facility”). The Company monitors the financial condition of these institutions and has not experienced losses due to counterparty default on these instruments. The Company markets substantially all of its oil and natural gas production, and all of its revenues are attributable to the U.S. The majority of the Company’s oil, natural gas and NGL production is sold to customers under short-term (less than 12 months) contracts at market-based prices. The Company’s customers consist primarily of major oil and natural gas companies, well-established oil and pipeline companies and independent oil and gas producers and suppliers. The Company performs ongoing credit evaluations of its customers and provide allowances for probable credit losses when necessary. The percent of consolidated revenue of major customers, those whose total represented 10% or more of the Company’s oil, natural gas and NGL revenues, was as follows: Year Ended December 31, 2019 2018 2017 Shell Trading (US) Company 58 % 65 % 80 % Phillips 66 28 % 18 % ** ** less than 10% The loss of a major customer could have material adverse effect on the Company in the short term. However, the Company believes it would be able to obtain other customers to market its oil, natural gas and NGL production. |
Summary of Significant Accoun_3
Summary of Significant Accounting Policies (Tables) | 12 Months Ended |
Dec. 31, 2019 | |
Accounting Policies [Abstract] | |
Schedule of Percent of Consolidated Revenue of Major Customers, Those Whose Total Represented 10% or More of Oil, Natural Gas and NGL Revenues | The percent of consolidated revenue of major customers, those whose total represented 10% or more of the Company’s oil, natural gas and NGL revenues, was as follows: Year Ended December 31, 2019 2018 2017 Shell Trading (US) Company 58 % 65 % 80 % Phillips 66 28 % 18 % ** ** less than 10% |
Acquisitions (Tables)
Acquisitions (Tables) | 12 Months Ended |
Dec. 31, 2019 | |
Stone Energy Corporation | |
Business Acquisition [Line Items] | |
Summary of Allocation of Purchase Price to Assets Acquired and Liabilities Assumed | The following table presents the final allocation of the purchase price to the assets acquired and liabilities assumed, based on their fair values on May 10, 2018 (in thousands): Current assets (1) $ 372,963 Property and equipment 886,406 Other long-term assets 19,494 Current liabilities (132,846 ) Long-term debt (235,416 ) Other long-term liabilities (178,637 ) Allocated purchase price $ 731,964 (1) |
Summary of Purchase Price | The following table summarizes the purchase price (in thousands, except per share data): Stone Energy common stock - issued and outstanding as of May 9, 2018 20,038 Stone Energy common stock price $ 35.49 Common stock value $ 711,149 Stone Energy common stock warrants - issued and outstanding as of May 9, 2018 3,528 Stone Energy common stock warrants price $ 5.90 Common stock warrants value $ 20,815 Total purchase price $ 731,964 |
Summary of Revenue and Net Income Attributable to Assets Acquired | The follow table presents revenue and net income attributable to the assets acquired in the Stone Combination for the years ended December 31, 2019 and 2018: Year Ended December 31, 2019 2018 Revenue $ 414,056 332,944 Net income $ 187,428 148,473 |
Supplemental Proforma Information | The following supplemental pro forma information (in thousands, except per common share amounts), presents the consolidated results of operations for the years ended December 31, 2018 and 2017 as if the Stone Combination had occurred on January 1, 2017. The unaudited pro forma information was derived from historical statements of operations of the Company and Stone and adjusted to include (i) depletion and accretion expense applied to the adjusted basis of the oil and natural gas properties acquired, (ii) interest expense to reflect the debt transactions contemplated by the Exchange Agreement and (iii) general and administrative expense adjusted for transaction related costs incurred. This information does not purport to be indicative of results of operations that would have occurred had the Stone Combination occurred on January 1, 2017, nor is such information indicative of any expected future results of operations. Year Ended December 31, 2018 2017 Revenue $ 1,013,184 $ 712,648 Net income (loss) $ 274,577 $ (100,980 ) Basic net income (loss) per common share $ 5.07 $ (1.86 ) Diluted net income (loss) per common share $ 5.07 $ (1.86 ) |
Gunflint Acquisition | |
Business Acquisition [Line Items] | |
Summary of Allocation of Purchase Price to Assets Acquired and Liabilities Assumed | The following table presents the allocation of the purchase price to the assets acquired and liabilities assumed, based on their relative fair values, on January 11, 2019 (in thousands): Property and equipment $ 28,912 Asset retirement obligations (996 ) Allocated purchase price $ 27,916 |
Whistler Energy II, LLC | |
Business Acquisition [Line Items] | |
Summary of Allocation of Purchase Price to Assets Acquired and Liabilities Assumed | The following table presents the allocation of the purchase price to the assets acquired and liabilities assumed, based on their relative fair values, on August 31, 2018 (in thousands): Current assets (1) $ 45,337 Property and equipment 35,344 Other long-term assets 66 Current liabilities (4,261 ) Asset retirement obligations (23,862 ) Allocated purchase price $ 52,624 (1) |
Property, Plant and Equipment (
Property, Plant and Equipment (Tables) | 12 Months Ended |
Dec. 31, 2019 | |
Oil And Gas Property [Abstract] | |
Summary of Oil and Natural Gas Property Costs Not Being Amortized | The following table sets forth a summary of the Company’s oil and natural gas property costs not being amortized at December 31, 2019, by the year in which such costs were incurred (in thousands): Year Ended December 31, Total 2019 2018 2017 2016 and Prior Acquisition United States $ 42,501 $ 16,062 $ 26,439 $ — $ — Exploration United States 45,117 35,656 7,087 2,372 2 Exploration Mexico 106,914 61,809 14,362 23,332 7,411 Total unproved properties, not subject to amortization $ 194,532 $ 113,527 $ 47,888 $ 25,704 $ 7,413 |
Schedule of Asset Retirement Obligations | Asset Retirement Obligations The discounted asset retirement obligations included in the consolidated balance sheets in current and non-current liabilities, and the changes in that liability during each of the years ended December 31, 2019 and 2018 were as follows (in thousands): Year Ended December 31, 2019 2018 Asset retirement obligations at January 1 $ 382,817 $ 214,733 Fair value of asset retirement obligations acquired (1) 5,047 244,766 Obligations settled (75,331 ) (112,946 ) Fair value of asset retirement obligations divested (5,450 ) — Accretion expense 34,389 35,344 Obligations incurred 4,111 358 Changes in estimate 23,895 562 Asset retirement obligations at December 31 $ 369,478 $ 382,817 Less: Current portion (61,051 ) (68,965 ) Long-term portion $ 308,427 $ 313,852 (1) |
Leases (Tables)
Leases (Tables) | 12 Months Ended |
Dec. 31, 2019 | |
Leases [Abstract] | |
Components of Lease Costs | The components of lease costs were as follows (in thousands): December 31, 2019 Finance lease cost - interest on lease liabilities (1) $ 19,115 Operating lease cost, excluding short-term leases (2) 3,261 Short-term lease cost (3) 85,865 Variable lease cost (4) 11 Total lease cost $ 108,252 (1) The HP-I is utilized in the Company’s oil and natural gas development activities and the right-of-use asset was capitalized and included in proved property and depleted as part of the full cost pool. Once items are included in the full cost pool, they are indistinguishable from other proved properties. The capitalized costs within the full cost pool are amortized over the life of the total proved reserved using the unit-of-production method, computed quarterly. (2) Operating lease cost reflect a single lease cost, calculated so that the cost of the lease is allocated over the lease term on a straight-line basis. (3) Short-term lease costs are reported at gross amounts and primarily represent costs incurred for drilling rigs, most of which are short-term contracts not recognized as a right-of-use asset and lease liability on the balance sheet. (4) Variable lease costs primarily represent differences between minimum payment obligations and actual operating charges incurred by the Company related to its long-term leases. |
Schedule of Right-of-Use Asset and Liability, Adjusted for Initial Direct Costs and Incentives | The present value of the fixed lease payments recorded as the Company’s right-of-use asset and liability, adjusted for initial direct costs and incentives are as follows (in thousands): December 31, 2019 Operating leases: Operating lease assets $ 7,779 Current portion of operating lease liabilities $ 1,594 Operating lease liabilities 17,239 Total operating lease liabilities $ 18,833 Finance leases: Proved property (1) $ 124,299 Other current liabilities $ 17,509 Other long-term liabilities 62,026 Total finance lease liabilities $ 79,535 (1) The HP-I is utilized in the Company’s oil and natural gas development activities and the right-of-use asset was capitalized and included in proved property and depleted as part of the full cost pool. Once items are included in the full cost pool, they are indistinguishable from other proved properties. The capitalized costs within the full cost pool are amortized over the life of the total proved reserves using the unit-of-production method, computed quarterly. |
Schedule of Lease Maturity | The table below presents the lease maturity by year as of December 31, 2019 (in thousands). Such commitments are reflected at undiscounted values and are reconciled to the discounted present value recognized on the consolidated balance sheet. Operating Leases Finance Leases 2020 $ 2,744 $ 33,257 2021 4,079 33,257 2022 4,302 33,257 2023 4,239 13,857 2024 3,315 — Thereafter 15,790 — Total lease payments $ 34,469 $ 113,628 Imputed interest (15,636 ) (34,093 ) Total $ 18,833 $ 79,535 |
Schedule of Weighted Average Remaining Lease Term and Discount Rate | The table below presents the weighted average remaining lease term and discount rate related to leases for the year ended December 31, 2019 (in thousands): December 31, 2019 Weighted average remaining lease term: Operating leases 8.4 years Finance leases 3.4 years Weighted average discount rate: Operating leases 10.2 % Finance leases 21.9 % |
Supplemental Cash Flow Information Related to Leases | The table below presents the supplemental cash flow information related to leases for the year ended December 31, 2019 (in thousands): Operating cash outflow from finance leases $ 19,115 Financing cash outflow from finance leases $ 14,133 Operating cash outflow from operating leases $ 1,812 Right-of-use assets obtained in exchange for new finance lease liabilities $ — Right-of-use assets obtained in exchange for new operating lease liabilities $ 2,225 |
Financial Instruments (Tables)
Financial Instruments (Tables) | 12 Months Ended |
Dec. 31, 2019 | |
Financial Instruments [Abstract] | |
Schedule of Carrying Amounts and Estimated Fair Values of Financial Instruments | The following table presents the carrying amounts and estimated fair values of the Company’s financial instruments (in thousands): December 31, 2019 December 31, 2018 Carrying Amount Fair Value Carrying Amount Fair Value 11.00% Second-Priority Senior Secured Notes – due April 2022 (1) $ 383,871 $ 401,128 $ 381,229 $ 362,168 7.50% Senior Notes – due May 2022 $ 6,060 $ 5,030 $ 6,060 $ 5,151 Bank Credit Facility – matures May 2022 (1) $ 343,050 $ 350,000 $ 257,448 $ 265,000 Oil and Natural Gas Derivatives $ (11,594 ) $ (11,594 ) $ 74,923 $ 74,923 (1) |
Schedule of Impact that Derivatives not Qualifying as Hedging Instruments in Condensed Consolidated Statements of Operations | The following table presents the impact that derivatives, not qualifying as hedging instruments, had on its consolidated statements of operations (in thousands): Year Ended December 31, 2019 2018 2017 Net cash received (paid) on settled derivative instruments $ (8,820 ) $ (111,147 ) $ 23,834 Unrealized gain (loss) (86,517 ) 171,582 (51,397 ) Price risk management activities income (expense) $ (95,337 ) $ 60,435 $ (27,563 ) |
Schedule of Contracted Volumes and Weighted Average Prices and will Receive Under the Terms of Derivative Contracts | The following table reflects the contracted volumes and weighted average prices the Company will receive under the terms of its derivative contracts as of December 31, 2019: Production Period Instrument Type Average Daily Volumes Weighted Average Swap Price Weighted Average Put Price Weighted Average Call Price Crude Oil – WTI: (Bbls) (per Bbl) (per Bbl) (per Bbl) January 2020 – December 2020 Swap 17,862 $ 56.21 $ — $ — January 2021 – June 2021 Swap 2,000 $ 53.30 $ — $ — January 2020 – December 2020 Collar 7,481 $ — $ 55.00 $ 64.23 Natural Gas – Henry Hub NYMEX: (MMBtu) (per MMBtu) (per MMBtu) (per MMBtu) January 2020 – December 2020 Swaps 16,216 $ 2.78 $ — $ — Subsequent event The following table reflects the contracted volumes and weighted average prices the Company will receive under the terms of its derivative contracts entered into subsequent to December 31, 2019, which are not reflected in the table above: Production Period Instrument Type Average Daily Volumes Weighted Average Swap Price Weighted Average Put Price Weighted Average Call Price Crude Oil – WTI: (Bbls) (per Bbl) (per Bbl) (per Bbl) April 2020 – December 2020 Swap 4,664 $ 40.98 $ — $ — January 2021 – December 2021 Swap 1,992 $ 48.48 $ — $ — Natural Gas – Henry Hub NYMEX: (MMBtu) (per MMBtu) (per MMBtu) (per MMBtu) April 2020 – December 2020 Swaps 6,000 $ 2.15 $ — $ — January 2021 – December 2021 Swaps 5,000 $ 2.39 $ — $ — |
Summary of Additional Information Related to Financial Instruments Measured at Fair Value on Recurring Basis | The following tables provide additional information related to financial instruments measured at fair value on a recurring basis (in thousands): December 31, 2019 Level 1 Level 2 Level 3 Total Assets: Oil and natural gas swaps and costless collars $ — $ 8,393 $ — $ 8,393 Liabilities: Oil and natural gas swaps and costless collars — (19,987 ) — (19,987 ) Total net asset $ — $ (11,594 ) $ — $ (11,594 ) December 31, 2018 Level 1 Level 2 Level 3 Total Assets: Oil and natural gas swaps and costless collars $ — $ 75,473 $ — $ 75,473 Liabilities: Oil and natural gas swaps and costless collars — (550 ) — (550 ) Total net liability $ — $ 74,923 $ — $ 74,923 |
Schedule of Fair Value of Derivative Financial Instruments | The following table presents the fair value of derivative financial instruments at December 31, 2019 and 2018 (in thousands): December 31, 2019 December 31, 2018 Assets Liabilities Assets Liabilities Oil and natural gas derivatives: Current $ 8,393 $ 19,476 $ 75,473 $ 550 Non-current — 511 — — Total $ 8,393 $ 19,987 $ 75,473 $ 550 |
Debt (Tables)
Debt (Tables) | 12 Months Ended |
Dec. 31, 2019 | |
Debt Disclosure [Abstract] | |
Summary of Detail Comprising Debt and Related Book Values | A summary of the detail comprising the Company’s debt and the related book values for the respective periods presented is as follows (in thousands): Year Ended December 31, 2019 2018 11.00% Second-Priority Senior Secured Notes – due April 2022 $ 390,868 $ 390,868 7.50% Senior Notes – due May 2022 6,060 6,060 Bank Credit Facility – matures May 2022 350,000 265,000 4.20% Building Loan – matures November 2030 — 10,567 Total debt, before discount and deferred financing cost 746,928 672,495 Discount and deferred financing cost (13,947 ) (17,191 ) Total debt, net of discount and deferred financing costs 732,981 655,304 Less: Current portion of long-term debt — (443 ) Long-term debt, net of discount and deferred financing costs $ 732,981 $ 654,861 |
Employee Benefits Plans and S_2
Employee Benefits Plans and Share-Based Compensation (Tables) | 12 Months Ended |
Dec. 31, 2019 | |
Disclosure Of Compensation Related Costs Sharebased Payments [Abstract] | |
Summary of Restricted Stock Units Activity | The following table summarizes RSU activity for the years ended December 31, 2019 and 2018: Restricted Stock Units Weighted Average Grant Date Fair Value Unvested RSUs at December 31, 2017 — $ — Granted 139,411 33.85 Vested (53 ) 32.86 Forfeited (654 ) 32.86 Unvested RSUs at December 31, 2018 138,704 $ 33.85 Granted 732,771 24.39 Vested (69,235 ) 33.72 Forfeited (68,463 ) 25.43 Unvested RSUs at December 31, 2019 733,777 $ 25.20 |
Summary of Performance Share Units Activity | The following table summarizes PSU activity for the years ended December 31, 2019 and 2018: Performance Share Units Weighted Average Grant Date Fair Value Unvested PSUs at December 31, 2017 — $ — Granted 232,891 44.47 Vested — — Forfeited (1,349 ) 42.94 Unvested PSUs at December 31, 2018 231,542 $ 44.47 Granted 218,060 33.96 Vested — — Forfeited (31,771 ) 40.27 Unvested PSUs at December 31, 2019 417,831 $ 39.31 |
Summary of Assumptions Used to Calculate the Grant Date Fair Value of PSUs Granted | The following table summarizes the assumptions used to calculate the grant date fair value of the PSUs granted for the years ended December 31, 2019 and 2018: 2019 Grant Date 2018 Grant Date March 5 May 16 August 29 September 28 Number of simulations 100,000 100,000 100,000 100,000 Expected term (in years) 2.8 2.6 2.7 2.6 Expected volatility 46.9 % 44.8 % 50.6 % 47.4 % Risk-free interest rate 2.5 % 2.1 % 2.7 % 2.9 % Dividend yield — % — % — % — % |
Schedule of Recognized Share Based Compensation Expense, Net | For the year ended December 31, 2019, share-based compensation expense did not have any associated income tax benefit. The Company recognized the following share-based compensation expense, net for the years ended December 31, 2019, 2018 and 2017 (in thousands): Year Ended December 31, 2019 2018 2017 Talos Energy Inc. Long Term Incentive Plan $ 12,523 $ 2,091 $ — Talos Energy LLC Series B Units 256 666 1,795 New Talos Energy LLC Series B Units 145 3,752 — Total share-based compensation expense 12,924 6,509 1,795 Less: amounts capitalized to oil and gas properties (5,960 ) (3,616 ) (920 ) Total share-based compensation expense, net $ 6,964 $ 2,893 $ 875 |
Income Taxes (Tables)
Income Taxes (Tables) | 12 Months Ended |
Dec. 31, 2019 | |
Income Tax Disclosure [Abstract] | |
Components of Income Tax Expense (Benefit) | Income Tax Expense (Benefit) The components of income tax expense (benefit) were as follows (in thousands): Year Ended December 31, 2019 2018 2017 Current income tax expense United States $ 437 $ — $ — Mexico 1,183 1,345 — Total current income tax expense $ 1,620 $ 1,345 $ — Deferred income tax expense (benefit) United States $ (37,131 ) $ 1,064 $ — Mexico (630 ) 513 — Total deferred income tax expense (benefit) (37,761 ) 1,577 — Total income tax expense (benefit) $ (36,141 ) $ 2,922 $ — |
Summary of Reconciliation of Income Taxes Computed at U.S. Federal Statutory Tax Rate to Income Tax Expense | The reconciliation of income taxes computed at the U.S. f ederal statutory tax rate to the Company’s income tax expense is as follows (in thousands, except percentages): Year Ended December 31, 2019 2018 2017 Income tax expense (benefit) at the federal statutory tax rate $ 4,744 $ 47,137 $ (22,004 ) Earnings not subject to tax — 9,980 22,004 State income taxes 1,396 11,738 — Foreign income taxes — 1,008 — Permanent differences 340 — — Foreign rate differential (4,948 ) 432 — Prior year taxes (1,950 ) 417 — Other adjustments 137 800 — Change in tax status — (35,925 ) — Legal entity reorganization 39,336 — — Change in valuation allowance (75,196 ) (32,665 ) — Total income tax expense (benefit) $ (36,141 ) $ 2,922 $ — Effective tax rate (159.99 )% 1.30 % — % |
Summary of Significant Components of Deferred Tax Assets and Liabilities | Deferred taxes reflect the net tax effects of temporary differences between the carrying amounts of assets and liabilities for financial reporting purposes and the amounts used for income tax purposes. Significant components of deferred tax assets and liabilities were as follows (in thousands): Year Ended December 31, 2019 2018 Deferred tax assets: Federal net operating loss $ 131,204 $ 117,546 Foreign tax loss carryforward 2,316 2,303 State net operating loss 24,270 23,542 Asset retirement obligations 89,059 95,546 Tax credits 449 12 Interest — 33,867 Derivatives 2,794 — Other well equipment inventory 10,014 12,901 Accrued bonus 3,753 4,042 Operating lease liabilities 2,317 2,509 Other 7,004 — Total deferred tax assets 273,180 292,268 Valuation allowance (19,118 ) (94,085 ) Total deferred tax assets, net $ 254,062 $ 198,183 Deferred tax liabilities: Oil and gas properties 211,216 179,780 Deferred financing 3,752 — Operating lease assets 1,814 — Derivatives — 18,246 Prepaid 3,419 3,371 Other — 642 Deferred tax liabilities 220,201 202,039 Net deferred tax asset (liability) $ 33,861 $ (3,856 ) |
Summary of Net Operating Loss and Tax Credit Carryovers | The table below presents the details of the Company’s net operating loss and tax credit carryovers as of December 31, 2019 (in thousands): Amount Expiration Year Federal net operating losses $ 536,463 2035 - 2037 Federal net operating losses $ 60,948 Unlimited Foreign tax loss carryforward $ 26,879 2025 - 2029 State net operating losses $ 380,609 2020 - 2038 |
Summary of Balances In Uncertain Tax Positions | Balances in the uncertain tax positions are as follows (in thousands): Year Ended December 31, 2019 2018 Total unrecognized tax benefits, beginning balance $ 360 $ — Increases in unrecognized tax benefits as a result of: Tax positions taken during a prior period 8 360 Tax positions taken during the current period 423 — Settlements with taxing authorities — — Lapse of applicable statute of limitations — — Total unrecognized tax benefits, ending balance $ 791 $ 360 |
Income (Loss) Per Share (Tables
Income (Loss) Per Share (Tables) | 12 Months Ended |
Dec. 31, 2019 | |
Earnings Per Share [Abstract] | |
Summary of Computation of Basic and Diluted Income (Loss) Per Share | The following table presents the computation of the Company’s basic and diluted income (loss) per share were as follows (in thousands, except for the per share amounts): Year Ended December 31, 2019 2018 2017 Net income (loss) $ 58,729 $ 221,540 $ (62,868 ) Weighted average common shares outstanding — basic 54,185 46,058 31,244 Dilutive effect of securities 228 3 — Weighted average common shares outstanding — diluted 54,413 46,061 31,244 Net income (loss) per common share: Basic $ 1.08 $ 4.81 $ (2.01 ) Diluted $ 1.08 $ 4.81 $ (2.01 ) Anti-dilutive potentially issuable securities excluded from diluted common shares 4,220 3,538 4,282 |
Commitments and Contingencies (
Commitments and Contingencies (Tables) | 12 Months Ended |
Dec. 31, 2019 | |
Commitments And Contingencies Disclosure [Abstract] | |
Summary of Total Minimum Commitments Associated With Long-Term Non-cancelable Operating Lease | The table below summarizes the Company’s total minimum commitments associated with vessel commitments and purchase obligations as of December 31, 2019 (in thousands): 2020 2021 2022 2023 Thereafter Total Vessel Commitments (1) $ 28,260 $ — $ — $ — $ — $ 28,260 Committed purchase orders (2) 61,434 — — — — 61,434 Total $ 89,694 $ — $ — $ — $ — $ 89,694 (1) (2) |
Condensed Consolidating Finan_2
Condensed Consolidating Financial Information (Tables) | 12 Months Ended |
Dec. 31, 2019 | |
Condensed Financial Information Of Parent Company Only Disclosure [Abstract] | |
Summary of Condensed Consolidating Financial Information | The following condensed consolidating financial information presents the financial information of the Company on an unconsolidated stand-alone basis and its combined guarantor and combined non-guarantor subsidiaries as of and for the period indicated. Such financial information may not necessarily be indicative of the Company’s results of operations, cash flows or financial position had these subsidiaries operated as independent entities. TALOS ENERGY INC. CONSOLIDATING BALANCE SHEET AS OF December 31, 2019 (In thousands) Parent Subsidiary Issuers Guarantors Non- Guarantors Elimination Consolidated ASSETS Current assets: Cash and cash equivalents $ — $ 78,780 $ 593 $ 7,649 $ — $ 87,022 Restricted cash — — — — — — Accounts receivable Trade, net — — 107,842 — — 107,842 Joint interest, net — — 11,567 4,985 — 16,552 Other — 474 5,555 317 — 6,346 Assets from price risk management activities — 8,393 — — — 8,393 Prepaid assets — 33,323 32,529 25 — 65,877 Income tax receivable — — 116 — — 116 Other current assets — — 1,836 — — 1,836 Total current assets — 120,970 160,038 12,976 — 293,984 Property and equipment: Proved properties — — 4,066,260 — — 4,066,260 Unproved properties, not subject to amortization — — 87,618 106,914 — 194,532 Other property and equipment — 23,142 6,484 217 — 29,843 Total property and equipment — 23,142 4,160,362 107,131 — 4,290,635 Accumulated depreciation, depletion and amortization — (11,001 ) (2,053,971 ) (51 ) — (2,065,023 ) Total property and equipment, net — 12,141 2,106,391 107,080 — 2,225,612 Other long-term assets: Other well equipment inventory — — 7,732 — — 7,732 Operating lease assets — 3,178 3,224 1,377 — 7,779 Investments in subsidiaries 1,045,886 1,690,362 — — (2,736,248 ) — Other assets 33,371 364 2,136 18,504 — 54,375 1,079,257 1,827,015 2,279,521 139,937 (2,736,248 ) 2,589,482 LIABILITIES AND STOCKHOLDERS' EQUITY (DEFICIT) Current liabilities: Accounts payable 428 5,145 58,827 6,957 — 71,357 Accrued liabilities — 4,740 145,051 5,025 — 154,816 Accrued royalties — — 31,729 — — 31,729 Current portion of asset retirement obligations — — 61,051 — — 61,051 Liabilities from price risk management activities — 19,476 — — — 19,476 Accrued interest payable — 10,211 38 — — 10,249 Current portion of operating lease liabilities — 196 821 577 — 1,594 Other current liabilities 255 — 19,925 — — 20,180 Total current liabilities 683 39,768 317,442 12,559 — 370,452 Long-term liabilities: Long-term debt, net of discount and deferred financing costs — 726,921 6,060 — — 732,981 Asset retirement obligations — — 308,427 — — 308,427 Liabilities from price risk management activities — 511 — — — 511 Operating lease liabilities — 13,929 2,416 894 — 17,239 Other long-term liabilities 297 — 81,298 — — 81,595 Total liabilities 980 781,129 715,643 13,453 — 1,511,205 Commitments and Contingencies (Note 12) Stockholders' equity 1,078,277 1,045,886 1,563,878 126,484 (2,736,248 ) 1,078,277 $ 1,079,257 $ 1,827,015 $ 2,279,521 $ 139,937 $ (2,736,248 ) $ 2,589,482 TALOS ENERGY INC. CONSOLIDATING BALANCE SHEET AS OF December 31, 2018 (In thousands) Parent Subsidiary Issuers Guarantors Non- Guarantors Elimination Consolidated ASSETS Current assets: Cash and cash equivalents $ — $ 13,541 $ 100,801 $ 25,572 $ — $ 139,914 Restricted cash — — 1,248 — — 1,248 Accounts receivable Trade, net — — 103,025 — — 103,025 Joint interest, net — — 15,870 4,374 — 20,244 Other — 3,100 9,566 7,020 — 19,686 Assets from price risk management activities — 75,473 — — — 75,473 Prepaid assets — 1,225 37,639 47 — 38,911 Income tax receivable — — 10,701 — — 10,701 Other current assets — — 7,644 — — 7,644 Total current assets — 93,339 286,494 37,013 — 416,846 Property and equipment: Proved properties — — 3,629,430 — — 3,629,430 Unproved properties, not subject to amortization — — 63,104 45,105 — 108,209 Other property and equipment — 20,670 12,440 81 — 33,191 Total property and equipment — 20,670 3,704,974 45,186 — 3,770,830 Accumulated depreciation, depletion and amortization — (8,310 ) (1,711,288 ) (11 ) — (1,719,609 ) Total property and equipment, net — 12,360 1,993,686 45,175 — 2,051,221 Other long-term assets: Other well equipment inventory — — 9,224 — — 9,224 Investments in subsidiaries 1,011,359 1,560,922 — — (2,572,281 ) — Other assets — 364 2,258 73 — 2,695 1,011,359 1,666,985 2,291,662 82,261 (2,572,281 ) 2,479,986 LIABILITIES AND STOCKHOLDERS' EQUITY (DEFICIT) Current liabilities: Accounts payable 144 1,242 42,736 6,897 — 51,019 Accrued liabilities — 4,995 159,491 24,164 — 188,650 Accrued royalties — — 38,520 — — 38,520 Current portion of long-term debt — — 443 — — 443 Current portion of asset retirement obligations — — 68,965 — — 68,965 Liabilities from price risk management activities 550 — — — 550 Accrued interest payable — 10,162 38 — — 10,200 Other current liabilities — — 22,071 — — 22,071 Total current liabilities 144 16,949 332,264 31,061 — 380,418 Long-term debt, net of discount and deferred financing costs — 638,677 16,184 — — 654,861 Asset retirement obligations — — 313,852 — — 313,852 Other long-term liabilities 3,719 — 119,432 208 — 123,359 Total liabilities 3,863 655,626 781,732 31,269 — 1,472,490 Commitments and Contingencies (Note 12) Stockholders' equity 1,007,496 1,011,359 1,509,930 50,992 (2,572,281 ) 1,007,496 $ 1,011,359 $ 1,666,985 $ 2,291,662 $ 82,261 $ (2,572,281 ) $ 2,479,986 TALOS ENERGY INC. CONSOLIDATING STATEMENT OF OPERATIONS FOR THE YEAR ENDED December 31, 2019 (In thousands) Parent Subsidiary Issuers Guarantors Non-Guarantors Elimination Consolidated Revenues: Oil revenue $ — $ — $ 832,909 $ 209 $ — $ 833,118 Natural gas revenue — — 55,278 — — 55,278 NGL revenue — — 19,668 — — 19,668 Other — — 19,556 — — 19,556 Total revenue — — 927,411 209 — 927,620 Operating expenses: Lease operating expense — — 243,427 — — 243,427 Production taxes — — 1,349 — — 1,349 Depreciation, depletion and amortization — 2,690 343,201 40 — 345,931 Write-down of oil and natural gas properties — — — 12,221 — 12,221 Accretion expense — — 34,389 — — 34,389 General and administrative expense 1,107 31,567 40,863 3,672 — 77,209 Total operating expenses 1,107 34,257 663,229 15,933 — 714,526 Operating income (loss) (1,107 ) (34,257 ) 264,182 (15,724 ) — 213,094 Interest expense (7 ) (67,582 ) (29,603 ) (655 ) — (97,847 ) Price risk management activities expenses — (95,337 ) — — — (95,337 ) Other income (loss) — 1,060 1,794 (176 ) — 2,678 Income tax expense (benefit) 36,579 (1 ) (313 ) (124 ) — 36,141 Equity earnings from subsidiaries 23,263 219,380 — — (242,643 ) — Net income (loss) $ 58,728 $ 23,263 $ 236,060 $ (16,679 ) $ (242,643 ) $ 58,729 TALOS ENERGY INC. CONSOLIDATING STATEMENT OF OPERATIONS FOR THE YEAR ENDED December 31, 2018 (In thousands) Parent Subsidiary Issuers Guarantors Non-Guarantors Elimination Consolidated Revenues: Oil revenue $ — $ — $ 781,815 $ — $ — $ 781,815 Natural gas revenue — — 73,610 — — 73,610 NGL revenue — — 35,863 — — 35,863 Total revenue — — 891,288 — — 891,288 Operating expenses: Lease operating expense — — 226,291 — — 226,291 Production taxes — — 1,989 — — 1,989 Depreciation, depletion and amortization — 1,955 286,760 4 — 288,719 Accretion expense — — 35,344 — — 35,344 General and administrative expense 142 43,841 40,035 1,798 — 85,816 Total operating expenses 142 45,796 590,419 1,802 — 638,159 Operating income (loss) (142 ) (45,796 ) 300,869 (1,802 ) — 253,129 Interest expense — (58,172 ) (30,255 ) (1,687 ) — (90,114 ) Price risk management activities income — 50,025 10,410 — — 60,435 Other income (loss) — (1,563 ) 874 1,701 — 1,012 Income tax expense (1,065 ) — (360 ) (1,497 ) — (2,922 ) Equity earnings from subsidiaries 222,747 278,253 — — (501,000 ) — Net income (loss) $ 221,540 $ 222,747 $ 281,538 $ (3,285 ) $ (501,000 ) $ 221,540 TALOS ENERGY INC. CONSOLIDATING STATEMENT OF OPERATIONS FOR THE YEAR ENDED DECEMBER 31, 2017 (In thousands) Parent Subsidiary Issuers Guarantors Non-Guarantors Elimination Consolidated Revenues: Oil revenue $ — $ — $ 344,781 $ — $ — $ 344,781 Natural gas revenue — — 48,886 — — 48,886 NGL revenue — — 16,658 — — 16,658 Other — — 2,503 — — 2,503 Total revenue — — 412,828 — — 412,828 Operating expenses: Lease operating expense — — 152,748 — — 152,748 Production taxes — — 1,460 — — 1,460 Depreciation, depletion and amortization — 1,401 155,947 4 — 157,352 Accretion expense — — 19,295 — — 19,295 General and administrative expense — 21,882 14,172 619 — 36,673 Total operating expenses — 23,283 343,622 623 — 367,528 Operating income (loss) — (23,283 ) 69,206 (623 ) — 45,300 Interest expense — (48,236 ) (30,252 ) (2,446 ) — (80,934 ) Price risk management activities expense — (22,998 ) (4,565 ) — — (27,563 ) Other income (expense) — 600 (333 ) 62 — 329 Equity earnings (losses) from subsidiaries (62,868 ) 31,049 — — 31,819 — Net income (loss) $ (62,868 ) $ (62,868 ) $ 34,056 $ (3,007 ) $ 31,819 $ (62,868 ) TALOS ENERGY INC. CONSOLIDATING STATEMENT OF CASH FLOWS FOR THE YEAR ENDED December 31, 2019 (In thousands) Parent Subsidiary Issuers Guarantors Non- Guarantors Elimination Consolidated Cash flows from operating activities: Net cash provided by (used in) operating activities $ (828 ) $ (95,960 ) $ 512,956 $ (22,435 ) $ — $ 393,733 Cash flows from investing activities: Exploration, development, and other capital expenditures — (1,614 ) (380,622 ) (81,173 ) — (463,409 ) Cash paid for acquisitions, net of cash acquired — — (37,916 ) — — (37,916 ) Investments in subsidiaries — (1,580,833 ) — — 1,580,833 — Proceeds from sale of other property and equipment — — 5,369 — — 5,369 Distributions from subsidiaries — 1,660,609 — — (1,660,609 ) — Net cash provided by (used in) investing activities — 78,162 (413,169 ) (81,173 ) (79,776 ) (495,956 ) Cash flows from financing activities: Redemption of Senior Notes and other long-term debt — — (10,567 ) — — (10,567 ) Proceeds from Bank Credit Facility — 110,000 — — — 110,000 Repayment of Bank Credit Facility — (25,000 ) — — — (25,000 ) Repayment of LLC Bank Credit Facility — — — — — — Deferred financing costs — (1,963 ) — — — (1,963 ) Other deferred payments — — (9,921 ) — — (9,921 ) Payment of capital lease — — (14,133 ) — — (14,133 ) Employee stock transactions — — (333 ) — — (333 ) Capital contributions 828 — 1,350,086 229,919 (1,580,833 ) — Distributions to Subsidiary Issuer — — (1,516,375 ) (144,234 ) 1,660,609 — Net cash provided by (used in) financing activities 828 83,037 (201,243 ) 85,685 79,776 48,083 Net increase (decrease) in cash, cash equivalents and restricted cash — 65,239 (101,456 ) (17,923 ) — (54,140 ) Cash, cash equivalents and restricted cash Balance, beginning of period — 13,541 102,049 25,572 — 141,162 Balance, end of period $ — $ 78,780 $ 593 $ 7,649 $ — $ 87,022 TALOS ENERGY INC. CONSOLIDATING STATEMENT OF CASH FLOWS FOR THE YEAR ENDED December 31, 2018 (In thousands) Parent Subsidiary Issuers Guarantors Non- Guarantors Elimination Consolidated Cash flows from operating activities: Net cash provided by (used in) operating activities $ — $ (193,088 ) $ 442,890 $ 13,643 $ — $ 263,445 Cash flows from investing activities: Exploration, development, and other capital expenditures — (13,404 ) (227,228 ) (282 ) — (240,914 ) Cash paid for acquisitions, net of cash acquired — — 278,409 — — 278,409 Investments in subsidiaries — (1,316,588 ) — — 1,316,588 — Proceeds from sale of other property and equipment — — — — — — Distributions from subsidiaries — 1,694,460 9 — (1,694,469 ) — Net cash provided by (used in) investing activities — 364,468 51,190 (282 ) (377,881 ) 37,495 Cash flows from financing activities: Redemption of Senior Notes and other long-term debt — (25,152 ) (105 ) — — (25,257 ) Proceeds from Bank Credit Facility — 319,000 — — — 319,000 Repayment of Bank Credit Facility — (54,000 ) — — — (54,000 ) Repayment of LLC Bank Credit Facility — (403,000 ) — — — (403,000 ) Deferred financing costs — (17,002 ) — — — (17,002 ) Other deferred payments — — — — — — Payment of capital lease — — (12,952 ) — — (12,952 ) Employee stock transactions — — — — — — Capital contributions — — 1,301,876 14,712 (1,316,588 ) — Distributions to Subsidiary Issuer — — (1,689,898 ) (4,571 ) 1,694,469 — Net cash provided by (used in) financing activities — (180,154 ) (401,079 ) 10,141 377,881 (193,211 ) Net increase (decrease) in cash, cash equivalents and restricted cash — (8,774 ) 93,001 23,502 — 107,729 Cash, cash equivalents and restricted cash Balance, beginning of period — 22,315 9,048 2,070 — 33,433 Balance, end of period $ — $ 13,541 $ 102,049 $ 25,572 $ — $ 141,162 TALOS ENERGY INC. CONSOLIDATING STATEMENT OF CASH FLOWS FOR THE YEAR ENDED DECEMBER 31, 2017 (In thousands) Parent Subsidiary Issuers Guarantors Non- Guarantors Elimination Consolidated Cash flows from operating activities: Net cash provided by (used in) operating activities $ — $ (30,245 ) $ 204,419 $ 1,879 $ — $ 176,053 Cash flows from investing activities: Exploration, development, and other capital expenditures — (260 ) (132,317 ) (22,600 ) — (155,177 ) Cash paid for acquisitions, net of cash acquired — — (2,464 ) — — (2,464 ) Investments in subsidiaries — (577,055 ) — — 577,055 — Proceeds from sale of other property and equipment — — — — — — Distributions from subsidiaries — 611,526 6,041 — (617,567 ) — Net cash provided by (used in) investing activities — 34,211 (128,740 ) (22,600 ) (40,512 ) (157,641 ) Cash flows from financing activities: Redemption of 2018 Senior Notes — (1,000 ) — — — (1,000 ) Proceeds from Bank Credit Facility — 10,000 — — — 10,000 Repayment of Bank Credit Facility — (15,000 ) — — — (15,000 ) Payments of capital lease — — (12,412 ) — — (12,412 ) Capital contributions — — 550,555 26,500 (577,055 ) — Distributions to subsidiaries — — (611,526 ) (6,041 ) 617,567 — Net cash provided by (used in) financing activities — (6,000 ) (73,383 ) 20,459 40,512 (18,412 ) Net increase (decrease) in cash, cash equivalents and restricted cash — (2,034 ) 2,296 (262 ) — — Cash, cash equivalents and restricted cash: Balance, beginning of period — 24,349 6,752 2,332 — 33,433 Balance, end of period $ — $ 22,315 $ 9,048 $ 2,070 $ — $ 33,433 |
Selected Quarterly Financial _2
Selected Quarterly Financial Data (Tables) | 12 Months Ended |
Dec. 31, 2019 | |
Quarterly Financial Information Disclosure [Abstract] | |
Schedule Of Unaudited Quarterly Financial Data | Unaudited quarterly financial data are as follows (in thousands): March 31 June 30 September 30 December 31 Quarter Ended 2019 Revenues $ 178,713 $ 286,810 $ 228,857 $ 233,240 Operating income $ 18,369 $ 94,872 $ 52,883 $ 46,970 Price risk management activities income (expense) $ (109,579 ) $ 29,990 $ 43,760 $ (59,508 ) Net income (loss) $ (109,636 ) $ 94,764 $ 73,297 $ 304 Net income (loss) per common share: Basic $ (2.02 ) $ 1.75 $ 1.35 $ 0.01 Diluted $ (2.02 ) $ 1.74 $ 1.35 $ 0.01 Weighted average common shares outstanding: Basic 54,156 54,178 54,200 54,203 Diluted 54,156 54,451 54,430 54,559 Quarter Ended 2018 Revenues $ 145,850 $ 203,906 $ 282,868 $ 258,664 Operating income $ 48,584 $ 39,211 $ 91,361 $ 73,973 Price risk management activities income (expense) $ (51,976 ) $ (91,176 ) $ (53,330 ) $ 256,917 Net income (loss) $ (22,943 ) $ (74,912 ) $ 13,109 $ 306,286 Net income (loss) per common share: Basic $ (0.73 ) $ (1.69 ) $ 0.24 $ 5.66 Diluted $ (0.73 ) $ (1.69 ) $ 0.24 $ 5.66 Weighted average common shares outstanding: Basic 31,244 44,336 54,156 54,156 Diluted 31,244 44,336 54,164 54,159 |
Supplemental Oil and Gas Disc_2
Supplemental Oil and Gas Disclosures (Unaudited) (Tables) | 12 Months Ended |
Dec. 31, 2019 | |
Extractive Industries [Abstract] | |
Schedule of Capitalized Costs Related to Oil, Natural Gas and NGL Activities and Related Accumulated Depletion and Amortization | Aggregate amounts of capitalized costs relating to oil, natural gas and NGL activities and the aggregate amount of related accumulated depletion and amortization as of the dates indicated are presented below (in thousands): Year Ended December 31, 2019 2018 Proved properties $ 4,066,260 $ 3,629,430 Unproved oil and gas properties, not subject to amortization (1) 194,532 108,209 Total oil and gas properties 4,260,792 3,737,639 Less: Accumulated depletion (2,051,856 ) (1,709,614 ) Net capitalized costs $ 2,208,936 $ 2,028,025 Depletion and amortization rate (Per Boe) $ 18.05 $ 17.07 (1) |
Schedule of Costs Incurred in Oil, Natural Gas and NGL Property Acquisition, Exploration and Development Activities | The following table reflects the costs incurred in oil, natural gas and NGL property acquisition, exploration and development activities during the years indicated (in thousands). Costs incurred also include new asset retirement obligations established in the current year, as well as increases or decreases to the asset retirement obligations resulting from changes to cost estimates during the year. Year Ended December 31, 2019 2018 2017 Property acquisition costs: Proved properties $ 27,660 $ 850,515 $ 1,108 Unproved properties, not subject to amortization 16,062 65,063 5,778 Total property acquisition costs 43,722 915,578 6,886 Exploration costs (1) 209,161 93,780 82,887 Development costs 292,547 215,467 114,846 Total costs incurred $ 545,430 $ 1,224,825 $ 204,619 (1) Amount includes $74.2 million, $16.9 million and $22.8 million of exploration costs related to the Company’s Mexico properties for the year ended December 31, 2019, 2018 and 2017, respectively. |
Schedule of Estimated Proved Reserves at Net Ownership Interest | The following table presents the Company’s estimated proved reserves at its net ownership interest: Oil (MBbls) Gas (MMcf) NGL (MBbls) Oil Equivalent (MBoe) Total proved reserves at December 31, 2016 72,366 150,604 6,236 103,702 Revision of previous estimates (2,673 ) (15,860 ) 250 (5,067 ) Production (7,048 ) (16,308 ) (706 ) (10,472 ) Extensions and discoveries 10,159 9,220 767 12,462 Total proved reserves at December 31, 2017 72,804 127,656 6,547 100,625 Revision of previous estimates 2,595 (37,933 ) 3,187 (539 ) Production (11,771 ) (22,771 ) (1,176 ) (16,742 ) Purchases of reserves 44,788 95,661 2,074 62,806 Extensions and discoveries 4,123 8,411 64 5,589 Total proved reserves at December 31, 2018 112,539 171,024 10,696 151,739 Revision of previous estimates (5,553 ) (15,898 ) (1,237 ) (9,440 ) Production (13,844 ) (23,306 ) (1,228 ) (18,956 ) Purchases of reserves 2,094 2,626 130 2,662 Extensions and discoveries 11,518 21,552 620 15,730 Total proved reserves at December 31, 2019 106,754 155,998 8,981 141,735 Total proved developed reserves as of: December 31, 2017 37,460 77,577 3,315 53,704 December 31, 2018 85,530 131,364 8,104 115,528 December 31, 2019 72,016 115,381 6,733 97,979 Total proved undeveloped reserves as of: December 31, 2017 35,344 50,079 3,232 46,921 December 31, 2018 27,009 39,660 2,592 36,211 December 31, 2019 34,738 40,617 2,248 43,756 (2) |
Schedule of Standardized Measure of Discounted Future Net Cash Flows Related to Interest in Proved Oil, Natural Gas and NGL Reserves | The following table reflects the standardized measure of discounted future net cash flows relating to the Company’s interest in proved oil, natural gas and NGL reserves (in thousands): Year Ended December 31, 2019 2018 2017 Future cash inflows $ 7,151,875 $ 8,654,631 $ 4,308,863 Future costs: Production (1,633,432 ) (1,740,850 ) (815,509 ) Development and abandonment (1,464,270 ) (1,349,005 ) (823,164 ) Future net cash flows before income taxes 4,054,173 5,564,776 2,670,190 Future income tax expense (1) (662,317 ) (862,473 ) — Future net cash flows after income taxes 3,391,856 4,702,303 2,670,190 Discount at 10% annual rate (854,261 ) (1,362,057 ) (862,521 ) Standardized measure of discounted future net cash flows $ 2,537,595 $ 3,340,246 $ 1,807,669 (1) |
Schedule of Base Prices Used in Determining Standardized Measure | Future cash inflows are computed by applying SEC Pricing to year-end quantities of proved reserves. The discounted future cash flow estimates do not include the effects of derivative instruments. See the following table for base prices used in determining the standardized measure: Year Ended December 31, 2019 2018 2017 Oil price per Bbl $ 61.01 $ 69.42 $ 51.36 Natural gas price per Mcf $ 2.59 $ 3.08 $ 3.20 NGL price per Bbl $ 26.17 $ 29.50 $ 24.64 |
Schedule of Principal Changes in Standardized Measure of Discounted Future Net Cash Flows | Principal changes in the standardized measure of discounted future net cash flows attributable to the Company’s proved oil, natural gas and NGL reserves are as follows (in thousands): Year Ended December 31, 2019 2018 2017 Standardized measure, beginning of year $ 3,340,246 $ 1,807,669 $ 1,336,035 Sales and transfers of oil, net gas and NGLs produced during the period (665,226 ) (727,969 ) (288,942 ) Net change in prices and production costs (849,696 ) 1,578,330 555,100 Changes in estimated future development costs (75,564 ) 32,328 (156,282 ) Previously estimated development costs incurred 117,049 45,937 146,687 Accretion of discount 392,526 180,767 133,603 Net change in income taxes (1) 129,590 (585,017 ) — Purchases of reserves 75,009 943,519 — Extensions and discoveries 306,515 148,068 328,565 Net change due to revision in quantity estimates (199,576 ) 190,853 (113,629 ) Changes in production rates (timing) and other (33,278 ) (274,239 ) (133,468 ) Standardized measure, end of year $ 2,537,595 $ 3,340,246 $ 1,807,669 (1) |
Formation and Basis of Presen_2
Formation and Basis of Presentation - Additional Information (Details) $ / shares in Units, $ in Thousands | May 10, 2018USD ($)$ / sharesshares | Nov. 21, 2017USD ($)shares | Dec. 31, 2019USD ($)Segment$ / shares | Dec. 31, 2018USD ($)$ / shares | Jan. 01, 2019USD ($) |
Basis Of Presentation And Schedule Of Accounting Policy [Line Items] | |||||
Common stock par value | $ / shares | $ 0.01 | $ 0.01 | $ 0.01 | ||
Senior notes, outstanding amount | $ 746,928 | $ 672,495 | |||
Number of reportable segment | Segment | 1 | ||||
Operating lease right-of-use asset | $ 7,779 | $ 7,300 | |||
Operating lease liability | $ 18,833 | $ 16,900 | |||
Talos Energy LLC Stakeholders | Talos Energy Inc. | |||||
Basis Of Presentation And Schedule Of Accounting Policy [Line Items] | |||||
Percentage of voting interest acquired | 63.00% | ||||
Stone Energy Corporation Stockholders | Talos Energy Inc. | |||||
Basis Of Presentation And Schedule Of Accounting Policy [Line Items] | |||||
Percentage of voting interest acquired | 37.00% | ||||
7.50% Senior Notes due 2022 | |||||
Basis Of Presentation And Schedule Of Accounting Policy [Line Items] | |||||
Debt instrument interest rate | 7.50% | 7.50% | |||
Senior notes, maturity date | May 31, 2022 | May 31, 2022 | |||
Senior notes, principal amount | $ 6,100 | ||||
11.00% Second-Priority Senior Secured Notes – due April 2022 | |||||
Basis Of Presentation And Schedule Of Accounting Policy [Line Items] | |||||
Debt instrument interest rate | 11.00% | 11.00% | |||
Senior notes, maturity date | Apr. 3, 2022 | Apr. 3, 2022 | |||
Senior Notes | 9.75% Senior Notes | |||||
Basis Of Presentation And Schedule Of Accounting Policy [Line Items] | |||||
Proceeds from issuance of senior notes | $ 102,000 | ||||
Debt instrument interest rate | 9.75% | ||||
Shares issued on exchange agreement | shares | 2,874,049 | ||||
Senior Notes | 9.75% Senior Notes – due July 2022 | |||||
Basis Of Presentation And Schedule Of Accounting Policy [Line Items] | |||||
Senior notes, maturity date | Jul. 31, 2022 | ||||
Senior Notes | 7.50% Senior Notes due 2022 | |||||
Basis Of Presentation And Schedule Of Accounting Policy [Line Items] | |||||
Debt instrument interest rate | 7.50% | 7.50% | 7.50% | 7.50% | |
Senior notes, maturity date | May 31, 2022 | ||||
Proceeds from Issuance of senior secured notes in exchange of 11% senior secured notes | $ 137,400 | ||||
Senior notes, principal amount | $ 81,500 | ||||
Senior notes, outstanding amount | $ 6,100 | $ 6,060 | $ 6,060 | ||
Senior Notes | 11.00% Second-Priority Senior Secured Notes – due April 2022 | |||||
Basis Of Presentation And Schedule Of Accounting Policy [Line Items] | |||||
Debt instrument interest rate | 11.00% | 11.00% | 11.00% | ||
Senior notes, maturity date | Apr. 3, 2022 | ||||
Senior notes, outstanding amount | $ 390,868 | $ 390,868 | |||
Debt instrument interest rate exchanged percentage | 11.00% | ||||
Bridge Loans | 11.00% Bridge Loans | |||||
Basis Of Presentation And Schedule Of Accounting Policy [Line Items] | |||||
Debt instrument interest rate | 11.00% | ||||
Proceeds from issuance of bridge loans in exchange of 11% senior secured notes | $ 172,000 | ||||
Stone Energy Corporation | |||||
Basis Of Presentation And Schedule Of Accounting Policy [Line Items] | |||||
Closing date of merger agreement | May 10, 2018 | ||||
Stone Energy Corporation | 7.50% Senior Notes due 2022 | |||||
Basis Of Presentation And Schedule Of Accounting Policy [Line Items] | |||||
Debt instrument interest rate | 7.50% | ||||
Senior notes, maturity date | May 31, 2022 | ||||
Senior notes, principal amount | $ 6,100 | ||||
Stone Energy Corporation | 11.00% Second-Priority Senior Secured Notes – due April 2022 | |||||
Basis Of Presentation And Schedule Of Accounting Policy [Line Items] | |||||
Debt instrument interest rate | 11.00% | ||||
Senior notes, maturity date | Apr. 3, 2022 | ||||
Senior notes, principal amount | $ 390,900 | ||||
Talos Production LLC | |||||
Basis Of Presentation And Schedule Of Accounting Policy [Line Items] | |||||
Percentage of voting interest acquired | 100.00% | ||||
Share issued on merger | shares | 31,244,085 |
Summary of Significant Accoun_4
Summary of Significant Accounting Policies - Additional Information (Details) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2019 | Dec. 31, 2018 | Dec. 31, 2017 | |
Summary Of Significant Accounting Policies [Line Items] | |||
Allowance for uncollectible accounts | $ 9.9 | $ 8.7 | |
Income tax refund claims | 18 | ||
Capitalized overhead costs | 28.2 | 21.9 | $ 13.7 |
Impairment to adjust other well equipment inventory | $ 0.2 | $ 0.2 | $ 0.3 |
Minimum | |||
Summary Of Significant Accounting Policies [Line Items] | |||
Other property and equipment, estimated useful lives | 3 years | ||
Number of common stock issuable upon vesting, percentage range of PSUs granted | 0.00% | ||
Maximum | |||
Summary Of Significant Accounting Policies [Line Items] | |||
Other property and equipment, estimated useful lives | 10 years | ||
Number of common stock issuable upon vesting, percentage range of PSUs granted | 200.00% | ||
Measurement Input Discount Rate | |||
Summary Of Significant Accounting Policies [Line Items] | |||
Present value of future net revenues from proved reserves, discount rate | 10.00% | ||
Other Revenue | |||
Summary Of Significant Accounting Policies [Line Items] | |||
Refund liability | $ 19.3 | ||
ILX and Castex | |||
Summary Of Significant Accounting Policies [Line Items] | |||
Escrow deposit | $ 31.8 |
Summary of Significant Accoun_5
Summary of Significant Accounting Policies - Schedule of Percent of Consolidated Revenue of Major Customers, Those Whose Total Represented 10% or More of Oil, Natural Gas and NGL Revenues (Details) - Sales Revenue - Customer Concentration Risk | 12 Months Ended | ||
Dec. 31, 2019 | Dec. 31, 2018 | Dec. 31, 2017 | |
Shell Trading (US) Company | |||
Concentration Risk [Line Items] | |||
Concentration risk, percentage | 58.00% | 65.00% | 80.00% |
Phillips 66 | |||
Concentration Risk [Line Items] | |||
Concentration risk, percentage | 28.00% | 18.00% |
Summary of Significant Accoun_6
Summary of Significant Accounting Policies - Schedule of Percent of Consolidated Revenue of Major Customers, Those Whose Total Represented 10% or More of Oil, Natural Gas and NGL Revenues (Parenthetical) (Details) - Sales Revenue - Customer Concentration Risk - Phillips 66 | 12 Months Ended | ||
Dec. 31, 2019 | Dec. 31, 2018 | Dec. 31, 2017 | |
Concentration Risk [Line Items] | |||
Concentration risk, percentage | 28.00% | 18.00% | |
Maximum | |||
Concentration Risk [Line Items] | |||
Concentration risk, percentage | 10.00% |
Acquisitions - Asset Acquisitio
Acquisitions - Asset Acquisitions - Additional Information (Details) - USD ($) $ in Millions | Jan. 11, 2019 | Aug. 31, 2018 |
Gunflint Acquisition | ||
Business Acquisition [Line Items] | ||
Percentage of voting interest acquired | 9.60% | |
Purchase price | $ 29.6 | |
Customary purchase price adjustments | $ 27.9 | |
Whistler Energy II, LLC | ||
Business Acquisition [Line Items] | ||
Purchase price | $ 52.6 | |
Business acquisition purchase price net | 14.8 | |
Available cash acquired | 37.8 | |
Business combination cash collateral | 30.8 | |
Business combination cash on hand for working capital | $ 7 |
Acquisitions - Asset Acquisit_2
Acquisitions - Asset Acquisitions - Summary of Allocation of Purchase Price to Assets Acquired and Liabilities Assumed (Details) - USD ($) $ in Thousands | Jan. 11, 2019 | Aug. 31, 2018 |
Gunflint Acquisition | ||
Business Acquisition [Line Items] | ||
Property and equipment | $ 28,912 | |
Asset retirement obligations | (996) | |
Allocated purchase price | $ 27,916 | |
Whistler Energy II, LLC | ||
Business Acquisition [Line Items] | ||
Current assets | $ 45,337 | |
Property and equipment | 35,344 | |
Other long-term assets | 66 | |
Current liabilities | (4,261) | |
Asset retirement obligations | (23,862) | |
Allocated purchase price | $ 52,624 |
Acquisitions - Asset Acquisit_3
Acquisitions - Asset Acquisitions - Summary of Allocation of Purchase Price to Assets Acquired and Liabilities Assumed (Parenthetical) (Details) - Whistler Energy II, LLC $ in Millions | Aug. 31, 2018USD ($) |
Business Acquisition [Line Items] | |
Cash acquired | $ 37.8 |
Trade Accounts Receivable | |
Business Acquisition [Line Items] | |
Primary fair values of receivables acquired | $ 3.2 |
Acquisitions - Business Combina
Acquisitions - Business Combination - Additional Information (Details) - USD ($) $ in Thousands | Feb. 28, 2020 | Feb. 24, 2020 | May 10, 2018 | Dec. 31, 2018 |
Senior Notes | Second Priority Senior Secured Notes | ||||
Business Acquisition [Line Items] | ||||
Senior notes, stated interest rate | 11.00% | |||
Stone Energy Corporation | ||||
Business Acquisition [Line Items] | ||||
Purchase price | $ 731,964 | |||
Acquisition, transaction related cost | $ 88,600 | |||
Acquisition, transaction related fees to note holders and for seismic use agreements | 56,100 | |||
Acquisition, transaction related fees paid to note holders | 9,300 | |||
Acquisition, transaction related fees for seismic use agreements | 46,800 | |||
Stone Energy Corporation | General and Administrative Expense | ||||
Business Acquisition [Line Items] | ||||
Acquisition, transaction related cost | $ 32,500 | |||
Talos Energy LLC Stakeholders | Talos Energy Inc. | ||||
Business Acquisition [Line Items] | ||||
Percentage of voting interest acquired | 63.00% | |||
Talos Energy LLC Stakeholders | Subsequent Event | ILX and Castex | ||||
Business Acquisition [Line Items] | ||||
Purchase price | $ 385,000 | |||
Business acquisition, effective date | Jul. 1, 2019 | |||
Talos Energy LLC Stakeholders | Subsequent Event | ILX and Castex | Series A Convertible Preferred Stock | ||||
Business Acquisition [Line Items] | ||||
Aggregate shares issued | 110,000 | |||
Shares issued upon conversion | 100 | |||
Stone Energy Corporation Stockholders | Talos Energy Inc. | ||||
Business Acquisition [Line Items] | ||||
Percentage of voting interest acquired | 37.00% |
Acquisitions - Business Combi_2
Acquisitions - Business Combination - Summary of Purchase Price (Details) - USD ($) $ / shares in Units, $ in Thousands | May 10, 2018 | Dec. 31, 2019 | Dec. 31, 2018 | May 09, 2018 |
Business Acquisition [Line Items] | ||||
Common stock value | $ 542 | $ 542 | ||
Stone Energy Corporation | ||||
Business Acquisition [Line Items] | ||||
Stone Energy common stock - issued and outstanding as of May 9, 2018 | 20,038 | |||
Stone Energy common stock price | $ 35.49 | |||
Common stock value | $ 711,149 | |||
Stone Energy common stock warrants - issued and outstanding as of May 9, 2018 | 3,528 | |||
Stone Energy common stock warrants price | $ 5.90 | |||
Common stock warrants value | $ 20,815 | |||
Total purchase price | $ 731,964 |
Acquisitions - Business Combi_3
Acquisitions - Business Combination - Summary of Allocation of Purchase Price to Assets Acquired and Liabilities Assumed (Details) - Stone Energy Corporation $ in Thousands | May 10, 2018USD ($) |
Business Acquisition [Line Items] | |
Current assets | $ 372,963 |
Property and equipment | 886,406 |
Other long-term assets | 19,494 |
Current liabilities | (132,846) |
Long-term debt | (235,416) |
Other long-term liabilities | (178,637) |
Allocated purchase price | $ 731,964 |
Acquisitions - Business Combi_4
Acquisitions - Business Combination - Summary of Allocation of Purchase Price to Assets Acquired and Liabilities Assumed (Parenthetical) (Details) - Stone Energy Corporation $ in Millions | May 10, 2018USD ($) |
Business Acquisition [Line Items] | |
Cash acquired | $ 293 |
Trade Accounts Receivable | |
Business Acquisition [Line Items] | |
Primary fair values of receivables acquired | 43.3 |
Joint Interest Receivables | |
Business Acquisition [Line Items] | |
Primary fair values of receivables acquired | $ 3.5 |
Acquisitions - Business Combi_5
Acquisitions - Business Combination - Summary of Revenue and Net Income Attributable to Assets Acquired (Details) - Stone Energy Corporation - USD ($) $ in Thousands | 12 Months Ended | |
Dec. 31, 2019 | Dec. 31, 2018 | |
Business Acquisition [Line Items] | ||
Revenue | $ 414,056 | $ 332,944 |
Net income | $ 187,428 | $ 148,473 |
Acquisitions - Business Combi_6
Acquisitions - Business Combination - Summary of Supplemental Proforma Information (Details) - USD ($) $ / shares in Units, $ in Thousands | 12 Months Ended | |
Dec. 31, 2018 | Dec. 31, 2017 | |
Business Acquisition Pro Forma Information [Abstract] | ||
Revenue | $ 1,013,184 | $ 712,648 |
Net income (loss) | $ 274,577 | $ (100,980) |
Basic net income (loss) per common share | $ 5.07 | $ (1.86) |
Diluted net income (loss) per common share | $ 5.07 | $ (1.86) |
Property, Plant and Equipment -
Property, Plant and Equipment - Additional Information (Details) | 12 Months Ended | ||
Dec. 31, 2019USD ($)$ / bbl$ / Mcf | Dec. 31, 2018USD ($) | Dec. 31, 2017USD ($) | |
Property, Plant and Equipment [Line Items] | |||
Write-down of oil and natural gas properties | $ 12,386,000 | $ 244,000 | $ 260,000 |
US | |||
Property, Plant and Equipment [Line Items] | |||
Write-down of oil and natural gas properties | $ 0 | $ 0 | $ 0 |
Unweighted average first day of month commodity price for crude oil for prior twelve months | $ / bbl | 61.01 | ||
Unweighted average first day of month commodity price for natural gas for prior twelve months | $ / Mcf | 2.59 | ||
Unweighted average first day of month commodity price for natural gas liquids for prior twelve months | $ / bbl | 26.17 | ||
Mexico | Block 2 | |||
Property, Plant and Equipment [Line Items] | |||
Write-down of oil and natural gas properties | $ 12,200,000 | ||
Measurement Input Discount Rate | |||
Property, Plant and Equipment [Line Items] | |||
Present value of future net revenues from proved reserves, discount rate | 10.00% |
Property, Plant and Equipment_2
Property, Plant and Equipment - Summary of Oil and Natural Gas Property Costs Not Being Amortized (Details) $ in Thousands | 12 Months Ended |
Dec. 31, 2019USD ($) | |
Capitalized Costs Of Unproved Properties Excluded From Amortization [Line Items] | |
Total unproved properties, not subject to amortization | $ 194,532 |
United States | |
Capitalized Costs Of Unproved Properties Excluded From Amortization [Line Items] | |
Acquisition | 42,501 |
Exploration | 45,117 |
Mexico | |
Capitalized Costs Of Unproved Properties Excluded From Amortization [Line Items] | |
Exploration | 106,914 |
2019 | |
Capitalized Costs Of Unproved Properties Excluded From Amortization [Line Items] | |
Total unproved properties, not subject to amortization | 113,527 |
2019 | United States | |
Capitalized Costs Of Unproved Properties Excluded From Amortization [Line Items] | |
Acquisition | 16,062 |
Exploration | 35,656 |
2019 | Mexico | |
Capitalized Costs Of Unproved Properties Excluded From Amortization [Line Items] | |
Exploration | 61,809 |
2018 | |
Capitalized Costs Of Unproved Properties Excluded From Amortization [Line Items] | |
Total unproved properties, not subject to amortization | 47,888 |
2018 | United States | |
Capitalized Costs Of Unproved Properties Excluded From Amortization [Line Items] | |
Acquisition | 26,439 |
Exploration | 7,087 |
2018 | Mexico | |
Capitalized Costs Of Unproved Properties Excluded From Amortization [Line Items] | |
Exploration | 14,362 |
2017 | |
Capitalized Costs Of Unproved Properties Excluded From Amortization [Line Items] | |
Total unproved properties, not subject to amortization | 25,704 |
2017 | United States | |
Capitalized Costs Of Unproved Properties Excluded From Amortization [Line Items] | |
Exploration | 2,372 |
2017 | Mexico | |
Capitalized Costs Of Unproved Properties Excluded From Amortization [Line Items] | |
Exploration | 23,332 |
2016 and Prior | |
Capitalized Costs Of Unproved Properties Excluded From Amortization [Line Items] | |
Total unproved properties, not subject to amortization | 7,413 |
2016 and Prior | United States | |
Capitalized Costs Of Unproved Properties Excluded From Amortization [Line Items] | |
Exploration | 2 |
2016 and Prior | Mexico | |
Capitalized Costs Of Unproved Properties Excluded From Amortization [Line Items] | |
Exploration | $ 7,411 |
Property, Plant and Equipment_3
Property, Plant and Equipment - Schedule of Asset Retirement Obligations (Details) - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2019 | Dec. 31, 2018 | Dec. 31, 2017 | |
Oil And Gas Property [Abstract] | |||
Asset retirement obligations | $ 382,817 | $ 214,733 | |
Fair value of asset retirement obligations acquired | 5,047 | 244,766 | |
Obligations settled | (75,331) | (112,946) | |
Fair value of asset retirement obligations divested | (5,450) | ||
Accretion expense | 34,389 | 35,344 | $ 19,295 |
Obligations incurred | 4,111 | 358 | |
Changes in estimate | 23,895 | 562 | |
Asset retirement obligations | 369,478 | 382,817 | $ 214,733 |
Less: Current portion | (61,051) | (68,965) | |
Long-term portion | $ 308,427 | $ 313,852 |
Property, Plant and Equipment_4
Property, Plant and Equipment - Schedule of Asset Retirement Obligations (Parenthetical) (Details) $ in Millions | 12 Months Ended |
Dec. 31, 2018USD ($) | |
Stone Energy Corporation | |
Property, Plant and Equipment [Line Items] | |
Fair value of asset retirement obligations assumed | $ 220.6 |
Whistler Energy II, LLC | |
Property, Plant and Equipment [Line Items] | |
Fair value of asset retirement obligations assumed | $ 23.9 |
Leases - Additional Information
Leases - Additional Information (Details) - USD ($) $ in Thousands | Dec. 31, 2019 | Jan. 01, 2019 | Aug. 02, 2016 |
Leases [Line Items] | |||
Capital lease obligations | $ 124,300 | ||
Operating lease liability | $ 18,833 | $ 16,900 | |
Seven Year Lease Agreement | |||
Leases [Line Items] | |||
Lease agreement term | 7 years | ||
Agreed to pay annual fixed demand charge, year one | $ 49,000 | ||
Agreed to pay annual fixed demand charge, year two | 49,000 | ||
Agreed to pay annual fixed demand charge, year five and thereafter | $ 45,000 |
Leases - Components of Lease Co
Leases - Components of Lease Costs (Details) $ in Thousands | 12 Months Ended | |
Dec. 31, 2019USD ($) | ||
Leases [Abstract] | ||
Finance lease cost - interest on lease liabilities | $ 19,115 | [1] |
Operating lease cost, excluding short-term leases | 3,261 | [2] |
Short-term lease cost | 85,865 | [3] |
Variable lease cost | 11 | [4] |
Total lease cost | $ 108,252 | |
[1] | The HP-I is utilized in the Company’s oil and natural gas development activities and the right-of-use asset was capitalized and included in proved property and depleted as part of the full cost pool. Once items are included in the full cost pool, they are indistinguishable from other proved properties. The capitalized costs within the full cost pool are amortized over the life of the total proved reserved using the unit-of-production method, computed quarterly. | |
[2] | Operating lease cost reflect a single lease cost, calculated so that the cost of the lease is allocated over the lease term on a straight-line basis. | |
[3] | Short-term lease costs are reported at gross amounts and primarily represent costs incurred for drilling rigs, most of which are short-term contracts not recognized as a right-of-use asset and lease liability on the balance sheet. | |
[4] | Variable lease costs primarily represent differences between minimum payment obligations and actual operating charges incurred by the Company related to its long-term leases. |
Leases - Schedule of Right-of-U
Leases - Schedule of Right-of-Use Asset and Liability, Adjusted for Initial Direct Costs and Incentives (Details) - USD ($) $ in Thousands | Dec. 31, 2019 | Jan. 01, 2019 | |
Operating leases: | |||
Operating lease assets | $ 7,779 | $ 7,300 | |
Current portion of operating lease liabilities | $ 1,594 | ||
Operating Lease, Liability, Current, Statement of Financial Position [Extensible List] | us-gaap:OperatingLeaseLiabilityCurrent | ||
Operating lease liabilities | $ 17,239 | ||
Total operating lease liabilities | 18,833 | $ 16,900 | |
Finance leases: | |||
Proved property | [1] | 124,299 | |
Other current liabilities | $ 17,509 | ||
Finance Lease, Liability, Current, Statement of Financial Position [Extensible List] | us-gaap:OtherLiabilitiesCurrent | ||
Other long-term liabilities | $ 62,026 | ||
Finance Lease, Liability, Noncurrent, Statement of Financial Position [Extensible List] | us-gaap:OtherLiabilitiesNoncurrent | ||
Total finance lease liabilities | $ 79,535 | ||
[1] | The HP-I is utilized in the Company’s oil and natural gas development activities and the right-of-use asset was capitalized and included in proved property and depleted as part of the full cost pool. Once items are included in the full cost pool, they are indistinguishable from other proved properties. The capitalized costs within the full cost pool are amortized over the life of the total proved reserves using the unit-of-production method, computed quarterly. |
Leases - Schedule of Lease Matu
Leases - Schedule of Lease Maturity (Details) - USD ($) $ in Thousands | Dec. 31, 2019 | Jan. 01, 2019 |
Leases [Abstract] | ||
Operating Leases, 2020 | $ 2,744 | |
Operating Leases, 2021 | 4,079 | |
Operating Leases, 2022 | 4,302 | |
Operating Leases, 2023 | 4,239 | |
Operating Leases, 2024 | 3,315 | |
Operating Leases, Thereafter | 15,790 | |
Operating Leases, Total lease payments | 34,469 | |
Operating Leases, Imputed interest | (15,636) | |
Operating Leases | 18,833 | $ 16,900 |
Finance Leases, 2020 | 33,257 | |
Finance Leases, 2021 | 33,257 | |
Finance Leases, 2022 | 33,257 | |
Finance Leases, 2023 | 13,857 | |
Finance Leases, Total lease payments | 113,628 | |
Finance Leases, Imputed interest | (34,093) | |
Finance Leases | $ 79,535 |
Leases - Schedule of Weighted A
Leases - Schedule of Weighted Average Remaining Lease Term and Discount Rate (Details) | Dec. 31, 2019 |
Weighted average remaining lease term: | |
Operating leases | 8 years 4 months 24 days |
Finance leases | 3 years 4 months 24 days |
Weighted average discount rate: | |
Operating leases | 10.20% |
Finance leases | 21.90% |
Leases - Supplemental Cash Flow
Leases - Supplemental Cash Flow Information Related to Leases (Details) - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2019 | Dec. 31, 2018 | Dec. 31, 2017 | |
Cash Paid For Amounts Included In Measurement Of Lease Liabilities [Abstract] | |||
Operating cash outflow from finance leases | $ 19,115 | ||
Financing cash outflow from finance leases | 14,133 | $ 12,952 | $ 12,412 |
Operating cash outflow from operating leases | 1,812 | ||
Right-of-use assets obtained in exchange for new operating lease liabilities | $ 2,225 |
Financial Instruments - Schedul
Financial Instruments - Schedule of Carrying Amounts and Estimated Fair Values of Financial Instruments (Details) - USD ($) $ in Thousands | Dec. 31, 2019 | Dec. 31, 2018 | |
Oil and Natural Gas Derivatives | |||
Debt Instrument [Line Items] | |||
Carrying Amount | $ (11,594) | $ 74,923 | |
Fair Value | (11,594) | 74,923 | |
11.00% Second-Priority Senior Secured Notes – due April 2022 | |||
Debt Instrument [Line Items] | |||
Carrying Amount | [1] | 383,871 | 381,229 |
Fair Value | [1] | 401,128 | 362,168 |
7.50% Senior Notes – due May 2022 | |||
Debt Instrument [Line Items] | |||
Carrying Amount | 6,060 | 6,060 | |
Fair Value | 5,030 | 5,151 | |
Bank Credit Facility – matures May 2022 | |||
Debt Instrument [Line Items] | |||
Carrying Amount | 343,050 | 257,448 | |
Fair Value | $ 350,000 | $ 265,000 | |
[1] |
Financial Instruments - Sched_2
Financial Instruments - Schedule of Carrying Amounts and Estimated Fair Values of Financial Instruments (Parenthetical) (Details) | 12 Months Ended | |
Dec. 31, 2019 | Dec. 31, 2018 | |
Bank Credit Facility – matures May 2022 | ||
Debt Instrument [Line Items] | ||
Senior notes, maturity date | May 10, 2022 | May 10, 2022 |
11.00% Second-Priority Senior Secured Notes – due April 2022 | ||
Debt Instrument [Line Items] | ||
Debt instrument interest rate | 11.00% | 11.00% |
Senior notes, maturity date | Apr. 3, 2022 | Apr. 3, 2022 |
7.50% Senior Notes – due May 2022 | ||
Debt Instrument [Line Items] | ||
Debt instrument interest rate | 7.50% | 7.50% |
Senior notes, maturity date | May 31, 2022 | May 31, 2022 |
Financial Instruments - Additio
Financial Instruments - Additional Information (Details) | 12 Months Ended | |||
Dec. 31, 2019USD ($)counterparty | Dec. 31, 2018 | May 31, 2018USD ($) | May 10, 2018USD ($) | |
Investment Grade Credit Rating | ||||
Fair Value Balance Sheet Grouping Financial Statement Captions [Line Items] | ||||
Number of counterparties | counterparty | 11 | |||
11.00% Second-Priority Senior Secured Notes – due April 2022 | ||||
Fair Value Balance Sheet Grouping Financial Statement Captions [Line Items] | ||||
Debt instrument interest rate | 11.00% | 11.00% | ||
Senior notes, maturity date | Apr. 3, 2022 | Apr. 3, 2022 | ||
7.50% Senior Notes – due May 2022 | ||||
Fair Value Balance Sheet Grouping Financial Statement Captions [Line Items] | ||||
Debt instrument interest rate | 7.50% | 7.50% | ||
Senior notes, maturity date | May 31, 2022 | May 31, 2022 | ||
Senior notes, principal amount | $ 6,100,000 | |||
New Bank Credit Facility | ||||
Fair Value Balance Sheet Grouping Financial Statement Captions [Line Items] | ||||
Senior notes, maturity date | May 10, 2022 | |||
Credit facility, maximum borrowing capacity | $ 950,000,000 | |||
Stone Energy Corporation | 11.00% Second-Priority Senior Secured Notes – due April 2022 | ||||
Fair Value Balance Sheet Grouping Financial Statement Captions [Line Items] | ||||
Debt instrument interest rate | 11.00% | |||
Senior notes, maturity date | Apr. 3, 2022 | |||
Senior notes, principal amount | $ 390,900,000 | |||
Stone Energy Corporation | 7.50% Senior Notes – due May 2022 | ||||
Fair Value Balance Sheet Grouping Financial Statement Captions [Line Items] | ||||
Debt instrument interest rate | 7.50% | |||
Senior notes, maturity date | May 31, 2022 | |||
Senior notes, principal amount | $ 6,100,000 |
Financial Instruments - Sched_3
Financial Instruments - Schedule of Impact that Derivatives not Qualifying as Hedging Instruments in Condensed Consolidated Statements of Operations (Details) - USD ($) $ in Thousands | 3 Months Ended | 12 Months Ended | |||||||||
Dec. 31, 2019 | Sep. 30, 2019 | Jun. 30, 2019 | Mar. 31, 2019 | Dec. 31, 2018 | Sep. 30, 2018 | Jun. 30, 2018 | Mar. 31, 2018 | Dec. 31, 2019 | Dec. 31, 2018 | Dec. 31, 2017 | |
Derivative Instruments And Hedging Activities Disclosure [Abstract] | |||||||||||
Net cash received (paid) on settled derivative instruments | $ (8,820) | $ (111,147) | $ 23,834 | ||||||||
Unrealized gain (loss) | (86,517) | 171,582 | (51,397) | ||||||||
Price risk management activities income (expense) | $ (59,508) | $ 43,760 | $ 29,990 | $ (109,579) | $ 256,917 | $ (53,330) | $ (91,176) | $ (51,976) | $ (95,337) | $ 60,435 | $ (27,563) |
Financial Instruments - Sched_4
Financial Instruments - Schedule of Contracted Volumes and Weighted Average Prices and will Receive Under the Terms of Derivative Contracts (Details) | Jan. 01, 2020MMBTU$ / bbl$ / MMBTUbbl | Dec. 31, 2019MMBTU$ / bbl$ / MMBTUbbl |
January 2020 – December 2020 | Collar | NYMEX | Henry Hub | ||
Derivative [Line Items] | ||
Instrument Type | Swaps | |
Weighted Average Swap Price | $ / MMBTU | 2.78 | |
Average Daily Volumes | MMBTU | 16,216 | |
April 2020 – December 2020 | Swap | NYMEX | Henry Hub | Subsequent Event | ||
Derivative [Line Items] | ||
Instrument Type | Swaps | |
Weighted Average Swap Price | $ / MMBTU | 2.15 | |
Average Daily Volumes | MMBTU | 6,000 | |
January 2021 – December 2021 | Swap | NYMEX | Henry Hub | Subsequent Event | ||
Derivative [Line Items] | ||
Instrument Type | Swaps | |
Weighted Average Swap Price | $ / MMBTU | 2.39 | |
Average Daily Volumes | MMBTU | 5,000 | |
Crude Oil | WTI | January 2020 – December 2020 | Swap | ||
Derivative [Line Items] | ||
Instrument Type | Swap | |
Average Daily Volumes | bbl | 17,862 | |
Weighted Average Swap Price | 56.21 | |
Crude Oil | WTI | January 2020 – December 2020 | Collar | ||
Derivative [Line Items] | ||
Instrument Type | Collar | |
Average Daily Volumes | bbl | 7,481 | |
Weighted Average Put Price | 55 | |
Weighted Average Call Price | 64.23 | |
Crude Oil | WTI | January 2021 – June 2021 | Swap | ||
Derivative [Line Items] | ||
Instrument Type | Swap | |
Average Daily Volumes | bbl | 2,000 | |
Weighted Average Swap Price | 53.30 | |
Crude Oil | WTI | April 2020 – December 2020 | Swap | Subsequent Event | ||
Derivative [Line Items] | ||
Instrument Type | Swap | |
Average Daily Volumes | bbl | 4,664 | |
Weighted Average Swap Price | 40.98 | |
Crude Oil | WTI | January 2021 – December 2021 | Swap | Subsequent Event | ||
Derivative [Line Items] | ||
Instrument Type | Swap | |
Average Daily Volumes | bbl | 1,992 | |
Weighted Average Swap Price | 48.48 |
Financial Instruments - Summary
Financial Instruments - Summary of Additional Information Related to Financial Instruments Measured at Fair Value on Recurring Basis (Details) - USD ($) $ in Thousands | Dec. 31, 2019 | Dec. 31, 2018 |
Oil And Natural Gas Swaps | ||
Liabilities: | ||
Total net asset (liability) | $ (11,594) | $ 74,923 |
Fair Value on Recurring Basis | ||
Liabilities: | ||
Total net asset (liability) | (11,594) | 74,923 |
Fair Value on Recurring Basis | Oil And Natural Gas Swaps | ||
Assets: | ||
Oil and natural gas swaps and costless collars | 8,393 | 75,473 |
Liabilities: | ||
Oil and natural gas swaps and costless collars | (19,987) | (550) |
Fair Value on Recurring Basis | Level 2 | ||
Liabilities: | ||
Total net asset (liability) | (11,594) | 74,923 |
Fair Value on Recurring Basis | Level 2 | Oil And Natural Gas Swaps | ||
Assets: | ||
Oil and natural gas swaps and costless collars | 8,393 | 75,473 |
Liabilities: | ||
Oil and natural gas swaps and costless collars | $ (19,987) | $ (550) |
Financial Instruments - Sched_5
Financial Instruments - Schedule of Fair Value of Derivative Financial Instruments (Details) - USD ($) $ in Thousands | Dec. 31, 2019 | Dec. 31, 2018 |
Price Risk Derivatives [Line Items] | ||
Current, Assets | $ 8,393 | $ 75,473 |
Current, Liabilities | 19,476 | 550 |
Non-current, Liabilities | 511 | |
Oil and Natural Gas Derivatives | ||
Price Risk Derivatives [Line Items] | ||
Current, Assets | 8,393 | 75,473 |
Assets | 8,393 | 75,473 |
Current, Liabilities | 19,476 | 550 |
Non-current, Liabilities | 511 | |
Liabilities | $ 19,987 | $ 550 |
Debt - Summary of Detail Compri
Debt - Summary of Detail Comprising Debt and Related Book Values (Details) - USD ($) | Dec. 31, 2019 | Dec. 31, 2018 | May 10, 2018 |
Debt Instrument [Line Items] | |||
Total debt, before discount and deferred financing cost | $ 746,928,000 | $ 672,495,000 | |
Discount and deferred financing cost | (13,947,000) | (17,191,000) | |
Total debt, net of discount and deferred financing costs | 732,981,000 | 655,304,000 | |
Less: Current portion of long-term debt | (443,000) | ||
Long-term debt, net of discount and deferred financing costs | 732,981,000 | 654,861,000 | |
4.20% Building Loan - matures November 2030 | |||
Debt Instrument [Line Items] | |||
Total debt, before discount and deferred financing cost | 0 | ||
Senior Notes | 11.00% Second-Priority Senior Secured Notes – due April 2022 | |||
Debt Instrument [Line Items] | |||
Total debt, before discount and deferred financing cost | 390,868,000 | 390,868,000 | |
Senior Notes | 7.50% Senior Notes – due May 2022 | |||
Debt Instrument [Line Items] | |||
Total debt, before discount and deferred financing cost | 6,060,000 | 6,060,000 | $ 6,100,000 |
Bank Credit Facility | Bank Credit Facility – matures May 2022 | |||
Debt Instrument [Line Items] | |||
Total debt, before discount and deferred financing cost | $ 350,000,000 | 265,000,000 | |
Building Loan | 4.20% Building Loan - matures November 2030 | |||
Debt Instrument [Line Items] | |||
Total debt, before discount and deferred financing cost | $ 10,567,000 |
Debt - Summary of Detail Comp_2
Debt - Summary of Detail Comprising Debt and Related Book Values (Parenthetical) (Details) | 12 Months Ended | |||
Dec. 31, 2019 | Dec. 31, 2018 | May 10, 2018 | Nov. 21, 2017 | |
11.00% Second-Priority Senior Secured Notes – due April 2022 | ||||
Debt Instrument [Line Items] | ||||
Debt instrument interest rate | 11.00% | 11.00% | ||
Senior notes, maturity date | Apr. 3, 2022 | Apr. 3, 2022 | ||
7.50% Senior Notes – due May 2022 | ||||
Debt Instrument [Line Items] | ||||
Debt instrument interest rate | 7.50% | 7.50% | ||
Senior notes, maturity date | May 31, 2022 | May 31, 2022 | ||
Bank Credit Facility – matures May 2022 | ||||
Debt Instrument [Line Items] | ||||
Senior notes, maturity date | May 10, 2022 | |||
4.20% Building Loan - matures November 2030 | ||||
Debt Instrument [Line Items] | ||||
Debt instrument interest rate | 4.20% | |||
Senior notes, maturity date | Nov. 20, 2030 | |||
Senior Notes | 11.00% Second-Priority Senior Secured Notes – due April 2022 | ||||
Debt Instrument [Line Items] | ||||
Debt instrument interest rate | 11.00% | 11.00% | 11.00% | |
Senior notes, maturity date | Apr. 3, 2022 | |||
Senior Notes | 7.50% Senior Notes – due May 2022 | ||||
Debt Instrument [Line Items] | ||||
Debt instrument interest rate | 7.50% | 7.50% | 7.50% | 7.50% |
Senior notes, maturity date | May 31, 2022 | |||
Bank Credit Facility | Bank Credit Facility – matures May 2022 | ||||
Debt Instrument [Line Items] | ||||
Senior notes, maturity date | May 10, 2022 | |||
Building Loan | 4.20% Building Loan - matures November 2030 | ||||
Debt Instrument [Line Items] | ||||
Debt instrument interest rate | 4.20% | |||
Senior notes, maturity date | Nov. 30, 2030 |
Debt - Additional information (
Debt - Additional information (Details) - USD ($) | Feb. 28, 2020 | Jan. 17, 2020 | Nov. 21, 2017 | Dec. 31, 2019 | Dec. 31, 2018 | Feb. 27, 2020 | Dec. 10, 2019 | Dec. 09, 2019 | Jul. 03, 2019 | Jul. 02, 2019 | May 10, 2018 |
Debt Instrument [Line Items] | |||||||||||
Payments of debt issuance costs | $ 4,300,000 | ||||||||||
Debt instrument redemption, description | The indenture governing the 11.00% Notes applies certain limitations on the Company’s ability and the ability of its subsidiaries to, among other things, (i) incur additional indebtedness or issue certain preferred shares; (ii) pay dividends and make certain other restricted payments; (iii) create restrictions on the payment of dividends or other distributions to the Company from its restricted subsidiaries; (iv) create liens on certain assets to secure debt; (v) make certain investments; (vi) engage in sales of assets and subsidiary stock; (vii) transfer all or substantially all of its assets or enter into merger or consolidation transactions; and (viii) engage in transactions with affiliates. The 11.00% Notes contain customary quarterly and annual reporting, financial and administrative covenants. The Company was in compliance with all debt covenants at December 31, 2019. | ||||||||||
Debt amount outstanding | $ 746,928,000 | $ 672,495,000 | |||||||||
11.00% Bridge Loans | Bridge Loans | |||||||||||
Debt Instrument [Line Items] | |||||||||||
Debt instrument, interest rate, stated percentage | 11.00% | ||||||||||
Proceeds from issuance of bridge loans in exchange of 11% senior secured notes | $ 172,000,000 | ||||||||||
7.50% Senior Notes – due May 2022 | |||||||||||
Debt Instrument [Line Items] | |||||||||||
Debt instrument, interest rate, stated percentage | 7.50% | 7.50% | |||||||||
Debt instrument, face amount | $ 6,100,000 | ||||||||||
Debt instrument, redemption price, percentage | 107.50% | ||||||||||
Debt instrument maturity date | May 31, 2022 | May 31, 2022 | |||||||||
Debt instrument frequency of periodic payment | semi-annually | ||||||||||
Debt instrument payment terms | semi-annually each May 31 and November 30 | ||||||||||
7.50% Senior Notes – due May 2022 | Maximum | |||||||||||
Debt Instrument [Line Items] | |||||||||||
Debt instrument, redemption price, percentage | 105.625% | ||||||||||
Debt instrument, option to redeem, percentage | 35.00% | ||||||||||
7.50% Senior Notes – due May 2022 | Minimum | |||||||||||
Debt Instrument [Line Items] | |||||||||||
Debt instrument, redemption price, percentage | 100.00% | ||||||||||
Bank Credit Facility – matures May 2022 | |||||||||||
Debt Instrument [Line Items] | |||||||||||
Debt instrument, face amount | $ 25,000,000 | ||||||||||
Debt instrument maturity date | May 10, 2022 | ||||||||||
Credit facility, maximum borrowing capacity | $ 950,000,000 | $ 950,000,000 | $ 850,000,000 | $ 850,000,000 | |||||||
Bank credit facility, description | The Bank Credit Facility matures on May 10, 2022, provided that the Bank Credit Facility mandates a springing maturity that is 120 days prior to May 10, 2022, if greater than $25.0 million of the 11.00% Notes or any permitted refinancing indebtedness in resect thereof is outstanding on such date. | ||||||||||
Debt instrument springing maturity period | 120 days | ||||||||||
Commitment fee percentage | 0.50% | ||||||||||
Line of credit facility current commitment | $ 950,000,000 | 950,000,000 | 850,000,000 | $ 850,000,000 | $ 600,000,000 | ||||||
Undrawn commitment under credit facility | 586,400,000 | ||||||||||
Letters of credit outstanding amount | 13,600,000 | ||||||||||
Line of credit outstanding amount | 350,000,000 | ||||||||||
Bank Credit Facility – matures May 2022 | Subsequent Event | |||||||||||
Debt Instrument [Line Items] | |||||||||||
Credit facility, maximum borrowing capacity | $ 1,150,000,000 | ||||||||||
Line of credit facility current commitment | 1,150,000,000 | ||||||||||
Line of credit outstanding amount | $ 275,000,000 | ||||||||||
Credit facility drawn | $ 25,000,000 | ||||||||||
Bank Credit Facility – matures May 2022 | Letter of Credit | |||||||||||
Debt Instrument [Line Items] | |||||||||||
Credit facility, maximum borrowing capacity | $ 200,000,000 | ||||||||||
Bank Credit Facility – matures May 2022 | ILX and Castex | |||||||||||
Debt Instrument [Line Items] | |||||||||||
Credit facility, maximum borrowing capacity | 1,150,000,000 | 950,000,000 | |||||||||
Line of credit facility current commitment | $ 1,150,000,000 | $ 950,000,000 | |||||||||
Bank Credit Facility – matures May 2022 | ILX and Castex | Subsequent Event | |||||||||||
Debt Instrument [Line Items] | |||||||||||
Undrawn commitment under credit facility | 486,400,000 | ||||||||||
Letters of credit outstanding amount | 13,600,000 | ||||||||||
Credit facility drawn | $ 650,000,000 | ||||||||||
Bank Credit Facility – matures May 2022 | Maximum | |||||||||||
Debt Instrument [Line Items] | |||||||||||
Debt covenant to EBITDAX | 300.00% | ||||||||||
Bank Credit Facility – matures May 2022 | Maximum | London Interbank Offered Rate | |||||||||||
Debt Instrument [Line Items] | |||||||||||
Debt Instrument, Basis Spread on Variable Rate | 3.75% | ||||||||||
Bank Credit Facility – matures May 2022 | Maximum | Base Rate | |||||||||||
Debt Instrument [Line Items] | |||||||||||
Debt Instrument, Basis Spread on Variable Rate | 2.75% | ||||||||||
Bank Credit Facility – matures May 2022 | Minimum | |||||||||||
Debt Instrument [Line Items] | |||||||||||
Debt covenant current ratio | 100.00% | ||||||||||
Bank Credit Facility – matures May 2022 | Minimum | London Interbank Offered Rate | |||||||||||
Debt Instrument [Line Items] | |||||||||||
Debt Instrument, Basis Spread on Variable Rate | 2.75% | ||||||||||
Bank Credit Facility – matures May 2022 | Minimum | Base Rate | |||||||||||
Debt Instrument [Line Items] | |||||||||||
Debt Instrument, Basis Spread on Variable Rate | 1.75% | ||||||||||
4.20% Building Loan - matures November 2030 | |||||||||||
Debt Instrument [Line Items] | |||||||||||
Debt instrument, interest rate, stated percentage | 4.20% | ||||||||||
Debt instrument maturity date | Nov. 20, 2030 | ||||||||||
Debt instrument frequency of periodic payment | 180 equal monthly installments | ||||||||||
Debt instrument, periodic payment | $ 100,000 | ||||||||||
Repayment and discharge of aggregate remaining principal plus accrued interest | 10,400,000 | ||||||||||
Debt amount outstanding | $ 0 | ||||||||||
Senior Notes | 9.75% Senior Notes | |||||||||||
Debt Instrument [Line Items] | |||||||||||
Proceeds from issuance of senior notes | $ 102,000,000 | ||||||||||
Debt instrument, interest rate, stated percentage | 9.75% | ||||||||||
Senior Notes | 11.00% Second-Priority Notes – due April 2022 | |||||||||||
Debt Instrument [Line Items] | |||||||||||
Debt instrument, interest rate, stated percentage | 11.00% | 11.00% | |||||||||
Work fees to debt holders | $ 9,300,000 | ||||||||||
Debt instrument, redemption price, percentage | 105.50% | ||||||||||
Debt instrument maturity date | Apr. 3, 2022 | ||||||||||
Debt instrument frequency of periodic payment | semi-annually | ||||||||||
Debt instrument payment terms | semi-annually each April 15 and October 15 | ||||||||||
Senior Notes | 11.00% Second-Priority Notes – due April 2022 | Maximum | |||||||||||
Debt Instrument [Line Items] | |||||||||||
Debt instrument, redemption price, percentage | 102.75% | ||||||||||
Senior Notes | 11.00% Second-Priority Notes – due April 2022 | Minimum | |||||||||||
Debt Instrument [Line Items] | |||||||||||
Debt instrument, redemption price, percentage | 100.00% | ||||||||||
Senior Notes | 7.50% Senior Notes – due May 2022 | |||||||||||
Debt Instrument [Line Items] | |||||||||||
Debt instrument, interest rate, stated percentage | 7.50% | 7.50% | 7.50% | 7.50% | |||||||
Proceeds from Issuance of senior secured notes in exchange of 11% senior secured notes | $ 137,400,000 | ||||||||||
Debt instrument, face amount | $ 81,500,000 | ||||||||||
Debt instrument maturity date | May 31, 2022 | ||||||||||
Debt amount outstanding | $ 6,060,000 | $ 6,060,000 | $ 6,100,000 |
Employee Benefits Plans and S_3
Employee Benefits Plans and Share-Based Compensation - Additional information (Details) - USD ($) $ in Millions | 12 Months Ended | |
Dec. 31, 2019 | Dec. 31, 2018 | |
Minimum | ||
Share Based Compensation Arrangement By Share Based Payment Award [Line Items] | ||
Number of shares of common stock issuable upon vesting, percentage range of target number of PSUs granted | 0.00% | |
Maximum | ||
Share Based Compensation Arrangement By Share Based Payment Award [Line Items] | ||
Number of shares of common stock issuable upon vesting, percentage range of target number of PSUs granted | 200.00% | |
Performance Share Units | ||
Share Based Compensation Arrangement By Share Based Payment Award [Line Items] | ||
Share based compensation grants, vesting period | 3 years | |
Options conversion in common stock shares | 1 | |
Share-based compensation expense recognized period | 1 year 8 months 12 days | |
Share-based compensation expense unrecognized | $ 9.6 | |
Share-based compensation grant date fair value | $ 7.4 | $ 10.4 |
Performance Share Units | Minimum | ||
Share Based Compensation Arrangement By Share Based Payment Award [Line Items] | ||
Number of shares of common stock issuable upon vesting, percentage range of target number of PSUs granted | 0.00% | |
Performance Share Units | Maximum | ||
Share Based Compensation Arrangement By Share Based Payment Award [Line Items] | ||
Number of shares of common stock issuable upon vesting, percentage range of target number of PSUs granted | 200.00% | |
Executive Severance Plan | ||
Share Based Compensation Arrangement By Share Based Payment Award [Line Items] | ||
Termination period | 12 months | |
Plan termination date | Jul. 11, 2019 | |
Executive Severance Plan | General and Administrative Expense | ||
Share Based Compensation Arrangement By Share Based Payment Award [Line Items] | ||
Severance Costs1 | $ 0.2 | $ 7.8 |
Long Term Incentive Plan | ||
Share Based Compensation Arrangement By Share Based Payment Award [Line Items] | ||
Share-Based Compensation authorized to grant | 5,374,340 | |
Long Term Incentive Plan | Employees | Restricted Stock Units | ||
Share Based Compensation Arrangement By Share Based Payment Award [Line Items] | ||
Share based compensation grants, vesting period | 3 years | |
Options conversion in common stock shares | 1 | |
Share-based compensation expense recognized period | 2 years 1 month 6 days | |
Share-based compensation expense unrecognized | $ 12.9 | |
Long Term Incentive Plan | Non-employee Directors | Restricted Stock Units | ||
Share Based Compensation Arrangement By Share Based Payment Award [Line Items] | ||
Share based compensation grants, vesting period | 1 year | |
Options conversion in common stock shares | 1 | |
Share-based compensation expense recognized period | 2 months 12 days | |
Share-based compensation expense unrecognized | $ 0.1 | |
Options conversion percentage in RSUs | 60.00% | |
Options conversion percentage in cash | 40.00% | |
Share-based compensation expense liabilities | $ 0.1 | |
Talos Energy LLC Series B Units | Series A Units | ||
Share Based Compensation Arrangement By Share Based Payment Award [Line Items] | ||
Percentage of compounded annual returns attained covenant | 8.00% | |
Talos Energy LLC Series B Units | Series C Units | ||
Share Based Compensation Arrangement By Share Based Payment Award [Line Items] | ||
Distribution paid | $ 0 | |
Talos Energy LLC Series B Units | Series B Units | ||
Share Based Compensation Arrangement By Share Based Payment Award [Line Items] | ||
Share-based compensation expense recognized period | 1 year 1 month 6 days | |
Share-based compensation expense unrecognized | $ 2.4 | |
Unrecognized compensation expense to be recognized over remainder of requisite service period | $ 0.2 | |
Requisite service period | 4 years | |
Unrecognized compensation expense to be recognized upon reorganization of Series A payout | $ 2.2 | |
New Talos Energy LLC Series B Units | ||
Share Based Compensation Arrangement By Share Based Payment Award [Line Items] | ||
Share-based compensation expense unrecognized | 1 | |
Unrecognized compensation expense to be recognized over remainder of requisite service period | $ 0.1 | |
Requisite service period | 4 years | |
New Talos Energy LLC Series B Units | New Series B Units | ||
Share Based Compensation Arrangement By Share Based Payment Award [Line Items] | ||
Share based compensation grants, vesting period | 4 years | |
Distribution paid | $ 102 | |
Percentage of units to be vested covenant | 80.00% | |
New Talos Energy LLC Series B Units | New Series A Units | ||
Share Based Compensation Arrangement By Share Based Payment Award [Line Items] | ||
Share-based compensation expense recognized period | 7 months 6 days | |
Unrecognized compensation expense to be recognized upon reorganization of Series A payout | $ 1 |
Employee Benefits Plans and S_4
Employee Benefits Plans and Share-Based Compensation - Schedule of Restricted Stock and Performance Share Units Activity (Details) - $ / shares | 12 Months Ended | |
Dec. 31, 2019 | Dec. 31, 2018 | |
Restricted Stock Units | ||
Share Based Compensation Arrangement By Share Based Payment Award [Line Items] | ||
Unvested restricted stock units and award beginning of the period | 138,704 | |
Unvested restricted stock units and award, granted | 732,771 | 139,411 |
Unvested restricted stock units and award, vested | (69,235) | (53) |
Unvested restricted stock units and award, forfeited | (68,463) | (654) |
Unvested restricted stock units and award, end of the period | 733,777 | 138,704 |
Unvested weighted average grant date fair value, beginning of the period | $ 33.85 | |
Unvested weighted average grant date fair value, granted | 24.39 | $ 33.85 |
Unvested weighted average grant date fair value, vested | 33.72 | 32.86 |
Unvested weighted average grant date fair value, forfeited | 25.43 | 32.86 |
Unvested weighted average grant date fair value, end of the period | $ 25.20 | $ 33.85 |
Performance Share Units | ||
Share Based Compensation Arrangement By Share Based Payment Award [Line Items] | ||
Unvested restricted stock units and award beginning of the period | 231,542 | |
Unvested restricted stock units and award, granted | 218,060 | 232,891 |
Unvested restricted stock units and award, forfeited | (31,771) | (1,349) |
Unvested restricted stock units and award, end of the period | 417,831 | 231,542 |
Unvested weighted average grant date fair value, beginning of the period | $ 44.47 | |
Unvested weighted average grant date fair value, granted | 33.96 | $ 44.47 |
Unvested weighted average grant date fair value, forfeited | 40.27 | 42.94 |
Unvested weighted average grant date fair value, end of the period | $ 39.31 | $ 44.47 |
Employee Benefits Plans and S_5
Employee Benefits Plans and Share-Based Compensation - Summary of Assumptions Used to Calculate the Grant Date Fair Value (Details) - Performance Share Units - Simulation | May 16, 2019 | Mar. 05, 2019 | Sep. 28, 2018 | Aug. 29, 2018 |
Share Based Compensation Arrangement By Share Based Payment Award [Line Items] | ||||
Number of simulations | 100,000 | 100,000 | 100,000 | 100,000 |
Expected term (in years) | 2 years 7 months 6 days | 2 years 9 months 18 days | 2 years 7 months 6 days | 2 years 8 months 12 days |
Expected volatility | 44.80% | 46.90% | 47.40% | 50.60% |
Risk-free interest rate | 2.10% | 2.50% | 2.90% | 2.70% |
Employee Benefits Plans and S_6
Employee Benefits Plans and Share-Based Compensation - Schedule of Recognized Share Based Compensation Expense, Net (Details) - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2019 | Dec. 31, 2018 | Dec. 31, 2017 | |
Employee Service Share Based Compensation Allocation Of Recognized Period Costs [Line Items] | |||
Total share-based compensation expense | $ 12,924 | $ 6,509 | $ 1,795 |
Less: amounts capitalized to oil and gas properties | (5,960) | (3,616) | (920) |
Total share-based compensation expense, net | 6,964 | 2,893 | 875 |
Talos Energy Inc. Long Term Incentive Plan | |||
Employee Service Share Based Compensation Allocation Of Recognized Period Costs [Line Items] | |||
Total share-based compensation expense | 12,523 | 2,091 | |
Talos Energy LLC Series B Units | |||
Employee Service Share Based Compensation Allocation Of Recognized Period Costs [Line Items] | |||
Total share-based compensation expense | 256 | 666 | $ 1,795 |
New Talos Energy LLC Series B Units | |||
Employee Service Share Based Compensation Allocation Of Recognized Period Costs [Line Items] | |||
Total share-based compensation expense | $ 145 | $ 3,752 |
Income Taxes - Components of In
Income Taxes - Components of Income Tax Expense (Benefit) (Details) - USD ($) $ in Thousands | 12 Months Ended | |
Dec. 31, 2019 | Dec. 31, 2018 | |
Current income tax expense | ||
United States | $ 437 | |
Mexico | 1,183 | $ 1,345 |
Total current income tax expense | 1,620 | 1,345 |
Deferred income tax expense (benefit) | ||
United States | (37,131) | 1,064 |
Mexico | (630) | 513 |
Total deferred income tax expense (benefit) | (37,761) | 1,577 |
Total income tax expense (benefit) | $ (36,141) | $ 2,922 |
Income Taxes - Summary of Recon
Income Taxes - Summary of Reconciliation of Income Taxes Computed U.S.Federal Statutory Tax Rate To Income Tax Expense (Details) - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2019 | Dec. 31, 2018 | Dec. 31, 2017 | |
Income Tax Disclosure [Abstract] | |||
Income tax expense (benefit) at the federal statutory tax rate | $ 4,744 | $ 47,137 | $ (22,004) |
Earnings not subject to tax | 9,980 | $ 22,004 | |
State income taxes | 1,396 | 11,738 | |
Foreign income taxes | 1,008 | ||
Permanent differences | 340 | ||
Foreign rate differential | (4,948) | 432 | |
Prior year taxes | (1,950) | 417 | |
Other adjustments | 137 | 800 | |
Change in tax status | (35,925) | ||
Legal entity reorganization | 39,336 | ||
Change in valuation allowance | (75,196) | (32,665) | |
Total income tax expense (benefit) | $ (36,141) | $ 2,922 | |
Effective tax rate | (159.99%) | 1.30% |
Income Taxes - Additional Infor
Income Taxes - Additional Information (Details) - USD ($) | 12 Months Ended | ||
Dec. 31, 2019 | Dec. 31, 2018 | Dec. 31, 2017 | |
Income Tax Disclosure [Line Items] | |||
Federal statutory rate | 21.00% | 21.00% | 35.00% |
Deferred tax assets, valuation allowance | $ 19,118,000 | $ 94,085,000 | |
Tax expense represents the non-cash impact from the legal entity conversion | 38,900 | ||
Valuation allowance | $ 19,100,000 | $ 94,100,000 | |
Period of cumulative income position | 3 years | ||
Earliest Tax Year | |||
Income Tax Disclosure [Line Items] | |||
Income tax examination, Year | 2016 | ||
Latest Tax Year | |||
Income Tax Disclosure [Line Items] | |||
Income tax examination, Year | 2018 | ||
Federal and State | |||
Income Tax Disclosure [Line Items] | |||
Deferred tax assets, valuation allowance | $ 80,200,000 | ||
Federal | |||
Income Tax Disclosure [Line Items] | |||
Deferred tax assets, valuation allowance | 75,200,000 | ||
Operating Loss Carryforwards | 597,400,000 | ||
Federal | Section 382 of Internal Revenue Code | |||
Income Tax Disclosure [Line Items] | |||
Operating Loss Carryforwards | 536,500,000 | ||
Foreign | |||
Income Tax Disclosure [Line Items] | |||
Deferred tax assets, valuation allowance | 5,000,000 | ||
Operating Loss Carryforwards | 26,879,000 | ||
Subsidiaries | |||
Income Tax Disclosure [Line Items] | |||
Tax expense related to the reorganization of subsidiaries | $ 39,300,000 |
Income Taxes - Summary of Signi
Income Taxes - Summary of Significant Components of Deferred Tax Assets and Liabilities (Details) - USD ($) $ in Thousands | Dec. 31, 2019 | Dec. 31, 2018 |
Deferred tax assets: | ||
Federal net operating loss | $ 131,204 | $ 117,546 |
Foreign tax loss carryforward | 2,316 | 2,303 |
State net operating loss | 24,270 | 23,542 |
Asset retirement obligations | 89,059 | 95,546 |
Tax credits | 449 | 12 |
Interest | 33,867 | |
Derivatives | 2,794 | |
Other well equipment inventory | 10,014 | 12,901 |
Accrued bonus | 3,753 | 4,042 |
Operating lease liabilities | 2,317 | 2,509 |
Other | 7,004 | |
Total deferred tax assets | 273,180 | 292,268 |
Valuation allowance | (19,118) | (94,085) |
Total deferred tax assets, net | 254,062 | 198,183 |
Deferred tax liabilities: | ||
Oil and gas properties | 211,216 | 179,780 |
Deferred financing | 3,752 | |
Operating lease assets | 1,814 | |
Derivatives | 18,246 | |
Prepaid | 3,419 | 3,371 |
Other | 642 | |
Deferred tax liabilities | 220,201 | 202,039 |
Net deferred tax asset | $ 33,861 | |
Net deferred tax (liability) | $ (3,856) |
Income Taxes - Summary of Net O
Income Taxes - Summary of Net Operating Loss and Tax Credit Carryovers (Details) $ in Thousands | 12 Months Ended |
Dec. 31, 2019USD ($) | |
Federal | |
Operating Loss Carryforwards [Line Items] | |
Net operating losses carryforward, Amount | $ 597,400 |
Net operating losses, Expiration term | Unlimited |
Federal | Minimum | |
Operating Loss Carryforwards [Line Items] | |
Net operating losses, Expiration year | 2035 |
Federal | Maximum | |
Operating Loss Carryforwards [Line Items] | |
Net operating losses, Expiration year | 2037 |
Federal | 2035 - 2038 | |
Operating Loss Carryforwards [Line Items] | |
Net operating losses carryforward, Amount | $ 536,463 |
Federal | Unlimited Expiration Year | |
Operating Loss Carryforwards [Line Items] | |
Net operating losses carryforward, Amount | 60,948 |
Foreign | |
Operating Loss Carryforwards [Line Items] | |
Net operating losses carryforward, Amount | $ 26,879 |
Foreign | Minimum | |
Operating Loss Carryforwards [Line Items] | |
Net operating losses, Expiration year | 2025 |
Foreign | Maximum | |
Operating Loss Carryforwards [Line Items] | |
Net operating losses, Expiration year | 2029 |
State | |
Operating Loss Carryforwards [Line Items] | |
Net operating losses carryforward, Amount | $ 380,609 |
State | Minimum | |
Operating Loss Carryforwards [Line Items] | |
Net operating losses, Expiration year | 2020 |
State | Maximum | |
Operating Loss Carryforwards [Line Items] | |
Net operating losses, Expiration year | 2038 |
Income Taxes - Summary of Balan
Income Taxes - Summary of Balances In Uncertain Tax Positions (Details) - USD ($) $ in Thousands | 12 Months Ended | |
Dec. 31, 2019 | Dec. 31, 2018 | |
Income Tax Disclosure [Abstract] | ||
Total unrecognized tax benefits, beginning balance | $ 360 | |
Tax positions taken during a prior period | 8 | $ 360 |
Tax positions taken during the current period | 423 | |
Total unrecognized tax benefits, ending balance | $ 791 | $ 360 |
Income (Loss) Per Share - Summa
Income (Loss) Per Share - Summary of Computation of Basic and Diluted Income (Loss) Per Share (Details) - USD ($) $ / shares in Units, shares in Thousands, $ in Thousands | 3 Months Ended | 12 Months Ended | |||||||||
Dec. 31, 2019 | Sep. 30, 2019 | Jun. 30, 2019 | Mar. 31, 2019 | Dec. 31, 2018 | Sep. 30, 2018 | Jun. 30, 2018 | Mar. 31, 2018 | Dec. 31, 2019 | Dec. 31, 2018 | Dec. 31, 2017 | |
Earnings Per Share [Abstract] | |||||||||||
Net income (loss) | $ 304 | $ 73,297 | $ 94,764 | $ (109,636) | $ 306,286 | $ 13,109 | $ (74,912) | $ (22,943) | $ 58,729 | $ 221,540 | $ (62,868) |
Weighted average common shares outstanding — basic | 54,203 | 54,200 | 54,178 | 54,156 | 54,156 | 54,156 | 44,336 | 31,244 | 54,185 | 46,058 | 31,244 |
Dilutive effect of securities | 228 | 3 | |||||||||
Weighted average common shares outstanding — diluted | 54,559 | 54,430 | 54,451 | 54,156 | 54,159 | 54,164 | 44,336 | 31,244 | 54,413 | 46,061 | 31,244 |
Basic | $ 0.01 | $ 1.35 | $ 1.75 | $ (2.02) | $ 5.66 | $ 0.24 | $ (1.69) | $ (0.73) | $ 1.08 | $ 4.81 | $ (2.01) |
Diluted | $ 0.01 | $ 1.35 | $ 1.74 | $ (2.02) | $ 5.66 | $ 0.24 | $ (1.69) | $ (0.73) | $ 1.08 | $ 4.81 | $ (2.01) |
Anti-dilutive potentially issuable securities excluded from diluted common shares | 4,220 | 3,538 | 4,282 |
Related Party Transactions - Ad
Related Party Transactions - Additional Information (Details) | Feb. 28, 2020 | Feb. 24, 2020USD ($)$ / sharesshares | Aug. 31, 2018USD ($) | May 10, 2018RegistrationOffering | Aug. 31, 2018USD ($) | Dec. 31, 2019USD ($)$ / shares | Dec. 31, 2018USD ($)$ / shares | Dec. 31, 2017USD ($) | Nov. 21, 2017 |
Related Party Transaction [Line Items] | |||||||||
Preferred stock, par value | $ / shares | $ 0.01 | $ 0.01 | |||||||
Net of cash acquired | $ 37,916,000 | $ (278,409,000) | $ 2,464,000 | ||||||
7.50% Senior Notes – due May 2022 | |||||||||
Related Party Transaction [Line Items] | |||||||||
Debt instrument, interest rate, stated percentage | 7.50% | 7.50% | |||||||
11.00% Second-Priority Senior Secured Notes – due April 2022 | |||||||||
Related Party Transaction [Line Items] | |||||||||
Debt instrument, interest rate, stated percentage | 11.00% | 11.00% | |||||||
Bridge Loans | |||||||||
Related Party Transaction [Line Items] | |||||||||
Debt instrument, interest rate, stated percentage | 11.00% | ||||||||
Senior Notes | 7.50% Senior Notes – due May 2022 | |||||||||
Related Party Transaction [Line Items] | |||||||||
Debt instrument, interest rate, stated percentage | 7.50% | 7.50% | 7.50% | 7.50% | |||||
Senior Notes | 11.00% Second-Priority Senior Secured Notes – due April 2022 | |||||||||
Related Party Transaction [Line Items] | |||||||||
Debt instrument, interest rate, stated percentage | 11.00% | 11.00% | 11.00% | ||||||
Original Equity Registration Rights Agreement | |||||||||
Related Party Transaction [Line Items] | |||||||||
Fees incurred in conjunction with agreement | $ 700,000 | $ 1,800,000 | |||||||
Franklin Advisers, Inc. and MacKay Shields LLC | Registration Rights Agreement | |||||||||
Related Party Transaction [Line Items] | |||||||||
Number of days required to file shelf registration statement | 30 days | ||||||||
Number of demand registrations allowed in any twelve-month period | Registration | 2 | ||||||||
Number of underwritten offerings to demand in any twelve-month period | Offering | 3 | ||||||||
Number of underwritten offerings to demand | Offering | 1 | ||||||||
Percentage of registrable securities owned, underwritten offerings | 5.00% | ||||||||
Threshold percentage of outstanding shares of common stock for termination of agreement | 5.00% | ||||||||
Registration agreement, termination description | The Registration Rights Agreement will terminate with respect to Franklin and MacKay Shields in the event that either Franklin or MacKay Shields ceases to beneficially own 5% or more of the then outstanding shares of the Company’s common stock. The Registration Rights Agreement will otherwise terminate at such time as there are no Registrable Securities outstanding. | ||||||||
Vinson & Elkins L.L.P. | |||||||||
Related Party Transaction [Line Items] | |||||||||
Legal fees incurred | $ 4,200,000 | 4,400,000 | 4,000,000 | ||||||
Legal fees payable | 2,300,000 | 1,100,000 | 4,000,000 | ||||||
Apollo and Riverstone Funds | |||||||||
Related Party Transaction [Line Items] | |||||||||
Work fees to debt holders | 4,100,000 | ||||||||
Apollo and Riverstone Funds | Service Fee Agreement | Shareholder Service | |||||||||
Related Party Transaction [Line Items] | |||||||||
Service fee | 500,000 | $ 500,000 | |||||||
Apollo and Riverstone Funds | Service Fee Agreement | Shareholder Service | Maximum | |||||||||
Related Party Transaction [Line Items] | |||||||||
Service fee | 500,000 | ||||||||
Franklin and McKay Noteholders | |||||||||
Related Party Transaction [Line Items] | |||||||||
Work fees to debt holders | 3,300,000 | ||||||||
Whistler Energy II, LLC | |||||||||
Related Party Transaction [Line Items] | |||||||||
Purchase price | $ 52,600,000 | ||||||||
Available cash acquired | $ 37,800,000 | ||||||||
Whistler Energy II, LLC | Apollo Funds | Whistler Energy II Holdco, LLC | |||||||||
Related Party Transaction [Line Items] | |||||||||
Business acquisition, date of acquisition agreement | Aug. 31, 2018 | ||||||||
Cash acquired | $ 52,600,000 | ||||||||
Net of cash acquired | 14,800,000 | ||||||||
Available cash acquired | $ 37,800,000 | ||||||||
Primary fair values of receivables acquired | $ 1,100,000 | ||||||||
Stone Energy Corporation | |||||||||
Related Party Transaction [Line Items] | |||||||||
Closing date of merger agreement | May 10, 2018 | ||||||||
Work fees to debt holders | $ 9,300,000 | ||||||||
Stone Energy Corporation | 7.50% Senior Notes – due May 2022 | |||||||||
Related Party Transaction [Line Items] | |||||||||
Debt instrument, interest rate, stated percentage | 7.50% | ||||||||
Stone Energy Corporation | 11.00% Second-Priority Senior Secured Notes – due April 2022 | |||||||||
Related Party Transaction [Line Items] | |||||||||
Debt instrument, interest rate, stated percentage | 11.00% | ||||||||
Stone Energy Corporation | Apollo and Riverstone Funds | Service Fee Agreement | Shareholder Service | |||||||||
Related Party Transaction [Line Items] | |||||||||
Closing date of merger agreement | May 10, 2018 | ||||||||
ILX and Castex | |||||||||
Related Party Transaction [Line Items] | |||||||||
Escrow deposit | $ 31,800,000 | ||||||||
Talos Energy LLC Stakeholders | Subsequent Event | ILX and Castex | |||||||||
Related Party Transaction [Line Items] | |||||||||
Purchase price | $ 385,000,000 | ||||||||
Escrow deposit | $ 31,800,000 | ||||||||
Closing date of merger agreement | Jul. 1, 2019 | ||||||||
Talos Energy LLC Stakeholders | Subsequent Event | ILX and Castex | Series A Convertible Preferred Stock | |||||||||
Related Party Transaction [Line Items] | |||||||||
Aggregate shares issued | shares | 110,000 | ||||||||
Preferred stock, par value | $ / shares | $ 0.01 |
Commitments and Contingencies -
Commitments and Contingencies - Additional Information (Details) - USD ($) $ in Thousands | Dec. 31, 2019 | Dec. 31, 2018 |
Loss Contingencies [Line Items] | ||
Performance obligations | $ 89,694 | |
Bank Credit Facility | Letter of Credit | ||
Loss Contingencies [Line Items] | ||
Credit facility | 13,600 | $ 14,700 |
Production Sharing Contracts | Mexico | ||
Loss Contingencies [Line Items] | ||
Performance obligations | $ 637,300 | $ 644,100 |
Commitments and Contingencies_2
Commitments and Contingencies - Summary of Total Minimum Commitments Associated With Long-Term Non-cancelable Operating Lease (Details) $ in Thousands | Dec. 31, 2019USD ($) | |
Contractual Obligation [Line Items] | ||
2020 | $ 89,694 | |
Total | 89,694 | |
Vessel Commitments | ||
Contractual Obligation [Line Items] | ||
2020 | 28,260 | [1] |
Total | 28,260 | [1] |
Committed Purchase Orders | ||
Contractual Obligation [Line Items] | ||
2020 | 61,434 | [2] |
Total | $ 61,434 | [2] |
[1] | ||
[2] |
Condensed Consolidating Finan_3
Condensed Consolidating Financial Information - Additional Information (Details) | 12 Months Ended | |
Dec. 31, 2019 | May 10, 2018 | |
Percentage of equity interest | 100.00% | |
11.00% Second-Priority Senior Secured Notes | ||
Debt instrument interest rate | 11.00% |
Condensed Consolidating Finan_4
Condensed Consolidating Financial Information - Summary of Consolidating Financial Position (Details) - USD ($) $ in Thousands | Dec. 31, 2019 | Jan. 01, 2019 | Dec. 31, 2018 | Dec. 31, 2017 | Dec. 31, 2016 |
Current assets: | |||||
Cash and cash equivalents | $ 87,022 | $ 139,914 | |||
Restricted cash | 1,248 | ||||
Accounts receivable | |||||
Trade, net | 107,842 | 103,025 | |||
Joint interest, net | 16,552 | 20,244 | |||
Other | 6,346 | 19,686 | |||
Assets from price risk management activities | 8,393 | 75,473 | |||
Prepaid assets | 65,877 | 38,911 | |||
Income tax receivable | 116 | 10,701 | |||
Other current assets | 1,836 | 7,644 | |||
Total current assets | 293,984 | 416,846 | |||
Property and equipment: | |||||
Proved properties | 4,066,260 | 3,629,430 | |||
Unproved properties, not subject to amortization | 194,532 | 108,209 | |||
Other property and equipment | 29,843 | 33,191 | |||
Total property and equipment | 4,290,635 | 3,770,830 | |||
Accumulated depreciation, depletion and amortization | (2,065,023) | (1,719,609) | |||
Total property and equipment, net | 2,225,612 | 2,051,221 | |||
Other long-term assets: | |||||
Other well equipment inventory | 7,732 | 9,224 | |||
Operating lease assets | 7,779 | $ 7,300 | |||
Other assets | 54,375 | 2,695 | |||
Total assets | 2,589,482 | 2,479,986 | |||
Current liabilities: | |||||
Accounts payable | 71,357 | 51,019 | |||
Accrued liabilities | 154,816 | 188,650 | |||
Accrued royalties | 31,729 | 38,520 | |||
Current portion of long-term debt | 443 | ||||
Current portion of asset retirement obligations | 61,051 | 68,965 | |||
Liabilities from price risk management activities | 19,476 | 550 | |||
Accrued interest payable | 10,249 | 10,200 | |||
Current portion of operating lease liabilities | 1,594 | ||||
Other current liabilities | 20,180 | 22,071 | |||
Total current liabilities | 370,452 | 380,418 | |||
Long-term liabilities: | |||||
Long-term debt, net of discount and deferred financing costs | 732,981 | 654,861 | |||
Asset retirement obligations | 308,427 | 313,852 | |||
Liabilities from price risk management activities | 511 | ||||
Operating lease liabilities | 17,239 | ||||
Other long-term liabilities | 81,595 | 123,359 | |||
Total liabilities | 1,511,205 | 1,472,490 | |||
Commitments and Contingencies | |||||
Stockholders' equity | 1,078,277 | 1,007,496 | $ (54,087) | $ 6,986 | |
Total liabilities and stockholders' equity | 2,589,482 | 2,479,986 | |||
Parent | |||||
Other long-term assets: | |||||
Investments in subsidiaries | 1,045,886 | 1,011,359 | |||
Other assets | 33,371 | ||||
Total assets | 1,079,257 | 1,011,359 | |||
Current liabilities: | |||||
Accounts payable | 428 | 144 | |||
Other current liabilities | 255 | ||||
Total current liabilities | 683 | 144 | |||
Long-term liabilities: | |||||
Other long-term liabilities | 297 | 3,719 | |||
Total liabilities | 980 | 3,863 | |||
Commitments and Contingencies | |||||
Stockholders' equity | 1,078,277 | 1,007,496 | |||
Total liabilities and stockholders' equity | 1,079,257 | 1,011,359 | |||
Subsidiary Issuer | |||||
Current assets: | |||||
Cash and cash equivalents | 78,780 | 13,541 | |||
Accounts receivable | |||||
Other | 474 | 3,100 | |||
Assets from price risk management activities | 8,393 | 75,473 | |||
Prepaid assets | 33,323 | 1,225 | |||
Total current assets | 120,970 | 93,339 | |||
Property and equipment: | |||||
Other property and equipment | 23,142 | 20,670 | |||
Total property and equipment | 23,142 | 20,670 | |||
Accumulated depreciation, depletion and amortization | (11,001) | (8,310) | |||
Total property and equipment, net | 12,141 | 12,360 | |||
Other long-term assets: | |||||
Operating lease assets | 3,178 | ||||
Investments in subsidiaries | 1,690,362 | 1,560,922 | |||
Other assets | 364 | 364 | |||
Total assets | 1,827,015 | 1,666,985 | |||
Current liabilities: | |||||
Accounts payable | 5,145 | 1,242 | |||
Accrued liabilities | 4,740 | 4,995 | |||
Liabilities from price risk management activities | 19,476 | 550 | |||
Accrued interest payable | 10,211 | 10,162 | |||
Current portion of operating lease liabilities | 196 | ||||
Total current liabilities | 39,768 | 16,949 | |||
Long-term liabilities: | |||||
Long-term debt, net of discount and deferred financing costs | 726,921 | 638,677 | |||
Liabilities from price risk management activities | 511 | ||||
Operating lease liabilities | 13,929 | ||||
Total liabilities | 781,129 | 655,626 | |||
Commitments and Contingencies | |||||
Stockholders' equity | 1,045,886 | 1,011,359 | |||
Total liabilities and stockholders' equity | 1,827,015 | 1,666,985 | |||
Guarantors | |||||
Current assets: | |||||
Cash and cash equivalents | 593 | 100,801 | |||
Restricted cash | 1,248 | ||||
Accounts receivable | |||||
Trade, net | 107,842 | 103,025 | |||
Joint interest, net | 11,567 | 15,870 | |||
Other | 5,555 | 9,566 | |||
Prepaid assets | 32,529 | 37,639 | |||
Income tax receivable | 116 | 10,701 | |||
Other current assets | 1,836 | 7,644 | |||
Total current assets | 160,038 | 286,494 | |||
Property and equipment: | |||||
Proved properties | 4,066,260 | 3,629,430 | |||
Unproved properties, not subject to amortization | 87,618 | 63,104 | |||
Other property and equipment | 6,484 | 12,440 | |||
Total property and equipment | 4,160,362 | 3,704,974 | |||
Accumulated depreciation, depletion and amortization | (2,053,971) | (1,711,288) | |||
Total property and equipment, net | 2,106,391 | 1,993,686 | |||
Other long-term assets: | |||||
Other well equipment inventory | 7,732 | 9,224 | |||
Operating lease assets | 3,224 | ||||
Other assets | 2,136 | 2,258 | |||
Total assets | 2,279,521 | 2,291,662 | |||
Current liabilities: | |||||
Accounts payable | 58,827 | 42,736 | |||
Accrued liabilities | 145,051 | 159,491 | |||
Accrued royalties | 31,729 | 38,520 | |||
Current portion of long-term debt | 443 | ||||
Current portion of asset retirement obligations | 61,051 | 68,965 | |||
Accrued interest payable | 38 | 38 | |||
Current portion of operating lease liabilities | 821 | ||||
Other current liabilities | 19,925 | 22,071 | |||
Total current liabilities | 317,442 | 332,264 | |||
Long-term liabilities: | |||||
Long-term debt, net of discount and deferred financing costs | 6,060 | 16,184 | |||
Asset retirement obligations | 308,427 | 313,852 | |||
Operating lease liabilities | 2,416 | ||||
Other long-term liabilities | 81,298 | 119,432 | |||
Total liabilities | 715,643 | 781,732 | |||
Commitments and Contingencies | |||||
Stockholders' equity | 1,563,878 | 1,509,930 | |||
Total liabilities and stockholders' equity | 2,279,521 | 2,291,662 | |||
Non-Guarantors | |||||
Current assets: | |||||
Cash and cash equivalents | 7,649 | 25,572 | |||
Accounts receivable | |||||
Joint interest, net | 4,985 | 4,374 | |||
Other | 317 | 7,020 | |||
Prepaid assets | 25 | 47 | |||
Total current assets | 12,976 | 37,013 | |||
Property and equipment: | |||||
Unproved properties, not subject to amortization | 106,914 | 45,105 | |||
Other property and equipment | 217 | 81 | |||
Total property and equipment | 107,131 | 45,186 | |||
Accumulated depreciation, depletion and amortization | (51) | (11) | |||
Total property and equipment, net | 107,080 | 45,175 | |||
Other long-term assets: | |||||
Operating lease assets | 1,377 | ||||
Other assets | 18,504 | 73 | |||
Total assets | 139,937 | 82,261 | |||
Current liabilities: | |||||
Accounts payable | 6,957 | 6,897 | |||
Accrued liabilities | 5,025 | 24,164 | |||
Current portion of operating lease liabilities | 577 | ||||
Total current liabilities | 12,559 | 31,061 | |||
Long-term liabilities: | |||||
Operating lease liabilities | 894 | ||||
Other long-term liabilities | 208 | ||||
Total liabilities | 13,453 | 31,269 | |||
Commitments and Contingencies | |||||
Stockholders' equity | 126,484 | 50,992 | |||
Total liabilities and stockholders' equity | 139,937 | 82,261 | |||
Elimination | |||||
Other long-term assets: | |||||
Investments in subsidiaries | (2,736,248) | (2,572,281) | |||
Total assets | (2,736,248) | (2,572,281) | |||
Long-term liabilities: | |||||
Commitments and Contingencies | |||||
Stockholders' equity | (2,736,248) | (2,572,281) | |||
Total liabilities and stockholders' equity | $ (2,736,248) | $ (2,572,281) |
Condensed Consolidating Finan_5
Condensed Consolidating Financial Information - Summary of Consolidating Results Of Operations (Details) - USD ($) $ in Thousands | 3 Months Ended | 12 Months Ended | |||||||||
Dec. 31, 2019 | Sep. 30, 2019 | Jun. 30, 2019 | Mar. 31, 2019 | Dec. 31, 2018 | Sep. 30, 2018 | Jun. 30, 2018 | Mar. 31, 2018 | Dec. 31, 2019 | Dec. 31, 2018 | Dec. 31, 2017 | |
Revenues: | |||||||||||
Total revenue | $ 233,240 | $ 228,857 | $ 286,810 | $ 178,713 | $ 258,664 | $ 282,868 | $ 203,906 | $ 145,850 | $ 927,620 | $ 891,288 | $ 412,828 |
Operating expenses: | |||||||||||
Depreciation, depletion and amortization | 345,931 | 288,719 | 157,352 | ||||||||
Write-down of oil and natural gas properties | 12,221 | ||||||||||
Accretion expense | 34,389 | 35,344 | 19,295 | ||||||||
General and administrative expense | 77,209 | 85,816 | 36,673 | ||||||||
Total operating expenses | 714,526 | 638,159 | 367,528 | ||||||||
Operating income (loss) | 46,970 | 52,883 | 94,872 | 18,369 | 73,973 | 91,361 | 39,211 | 48,584 | 213,094 | 253,129 | 45,300 |
Interest expense | (97,847) | (90,114) | (80,934) | ||||||||
Price risk management activities income (expense) | (59,508) | 43,760 | 29,990 | (109,579) | 256,917 | (53,330) | (91,176) | (51,976) | (95,337) | 60,435 | (27,563) |
Other income (expense) | 2,678 | 1,012 | 329 | ||||||||
Income tax expense (benefit) | 36,141 | (2,922) | |||||||||
Net income (loss) | $ 304 | $ 73,297 | $ 94,764 | $ (109,636) | $ 306,286 | $ 13,109 | $ (74,912) | $ (22,943) | 58,729 | 221,540 | (62,868) |
Parent | |||||||||||
Operating expenses: | |||||||||||
General and administrative expense | 1,107 | 142 | |||||||||
Total operating expenses | 1,107 | 142 | |||||||||
Operating income (loss) | (1,107) | (142) | |||||||||
Interest expense | (7) | ||||||||||
Income tax expense (benefit) | 36,579 | (1,065) | |||||||||
Equity earnings (losses) from subsidiaries | 23,263 | 222,747 | (62,868) | ||||||||
Net income (loss) | 58,728 | 221,540 | (62,868) | ||||||||
Subsidiary Issuer | |||||||||||
Operating expenses: | |||||||||||
Depreciation, depletion and amortization | 2,690 | 1,955 | 1,401 | ||||||||
General and administrative expense | 31,567 | 43,841 | 21,882 | ||||||||
Total operating expenses | 34,257 | 45,796 | 23,283 | ||||||||
Operating income (loss) | (34,257) | (45,796) | (23,283) | ||||||||
Interest expense | (67,582) | (58,172) | (48,236) | ||||||||
Price risk management activities income (expense) | (95,337) | 50,025 | (22,998) | ||||||||
Other income (expense) | 1,060 | (1,563) | 600 | ||||||||
Income tax expense (benefit) | (1) | ||||||||||
Equity earnings (losses) from subsidiaries | 219,380 | 278,253 | 31,049 | ||||||||
Net income (loss) | 23,263 | 222,747 | (62,868) | ||||||||
Guarantors | |||||||||||
Revenues: | |||||||||||
Total revenue | 927,411 | 891,288 | 412,828 | ||||||||
Operating expenses: | |||||||||||
Depreciation, depletion and amortization | 343,201 | 286,760 | 155,947 | ||||||||
Accretion expense | 34,389 | 35,344 | 19,295 | ||||||||
General and administrative expense | 40,863 | 40,035 | 14,172 | ||||||||
Total operating expenses | 663,229 | 590,419 | 343,622 | ||||||||
Operating income (loss) | 264,182 | 300,869 | 69,206 | ||||||||
Interest expense | (29,603) | (30,255) | (30,252) | ||||||||
Price risk management activities income (expense) | 10,410 | (4,565) | |||||||||
Other income (expense) | 1,794 | 874 | (333) | ||||||||
Income tax expense (benefit) | (313) | (360) | |||||||||
Net income (loss) | 236,060 | 281,538 | 34,056 | ||||||||
Non-Guarantors | |||||||||||
Revenues: | |||||||||||
Total revenue | 209 | ||||||||||
Operating expenses: | |||||||||||
Depreciation, depletion and amortization | 40 | 4 | 4 | ||||||||
Write-down of oil and natural gas properties | 12,221 | ||||||||||
General and administrative expense | 3,672 | 1,798 | 619 | ||||||||
Total operating expenses | 15,933 | 1,802 | 623 | ||||||||
Operating income (loss) | (15,724) | (1,802) | (623) | ||||||||
Interest expense | (655) | (1,687) | (2,446) | ||||||||
Other income (expense) | (176) | 1,701 | 62 | ||||||||
Income tax expense (benefit) | (124) | (1,497) | |||||||||
Net income (loss) | (16,679) | (3,285) | (3,007) | ||||||||
Oil Revenue | |||||||||||
Revenues: | |||||||||||
Revenue | 833,118 | 781,815 | 344,781 | ||||||||
Revenue | 833,118 | 781,815 | 344,781 | ||||||||
Oil Revenue | Guarantors | |||||||||||
Revenues: | |||||||||||
Revenue | 832,909 | 781,815 | 344,781 | ||||||||
Revenue | 832,909 | 781,815 | 344,781 | ||||||||
Oil Revenue | Non-Guarantors | |||||||||||
Revenues: | |||||||||||
Revenue | 209 | ||||||||||
Revenue | 209 | ||||||||||
Natural Gas Revenue | |||||||||||
Revenues: | |||||||||||
Revenue | 55,278 | 73,610 | 48,886 | ||||||||
Revenue | 55,278 | 73,610 | 48,886 | ||||||||
Natural Gas Revenue | Guarantors | |||||||||||
Revenues: | |||||||||||
Revenue | 55,278 | 73,610 | 48,886 | ||||||||
Revenue | 55,278 | 73,610 | 48,886 | ||||||||
NGL Revenue | |||||||||||
Revenues: | |||||||||||
Revenue | 19,668 | 35,863 | 16,658 | ||||||||
Revenue | 19,668 | 35,863 | 16,658 | ||||||||
NGL Revenue | Guarantors | |||||||||||
Revenues: | |||||||||||
Revenue | 19,668 | 35,863 | 16,658 | ||||||||
Revenue | 19,668 | 35,863 | 16,658 | ||||||||
Other | |||||||||||
Revenues: | |||||||||||
Revenue | 19,556 | 2,503 | |||||||||
Revenue | 19,556 | 2,503 | |||||||||
Other | Guarantors | |||||||||||
Revenues: | |||||||||||
Revenue | 19,556 | 2,503 | |||||||||
Revenue | 19,556 | 2,503 | |||||||||
Elimination | |||||||||||
Operating expenses: | |||||||||||
Equity earnings (losses) from subsidiaries | (242,643) | (501,000) | 31,819 | ||||||||
Net income (loss) | (242,643) | (501,000) | 31,819 | ||||||||
Oil and Gas Properties | |||||||||||
Operating expenses: | |||||||||||
Lease operating expense | 243,427 | 226,291 | 152,748 | ||||||||
Production taxes | 1,349 | 1,989 | 1,460 | ||||||||
Oil and Gas Properties | Guarantors | |||||||||||
Operating expenses: | |||||||||||
Lease operating expense | 243,427 | 226,291 | 152,748 | ||||||||
Production taxes | $ 1,349 | $ 1,989 | $ 1,460 |
Condensed Consolidating Finan_6
Condensed Consolidating Financial Information - Summary of Consolidating Cash Flows (Details) - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2019 | Dec. 31, 2018 | Dec. 31, 2017 | |
Cash flows from operating activities: | |||
Net cash provided by (used in) operating activities | $ 393,733 | $ 263,445 | $ 176,053 |
Cash flows from investing activities: | |||
Exploration, development, and other capital expenditures | (463,409) | (240,914) | (155,177) |
Cash paid for acquisitions, net of cash acquired | (37,916) | 278,409 | (2,464) |
Proceeds from sale of other property and equipment | 5,369 | ||
Net cash provided by (used in) investing activities | (495,956) | 37,495 | (157,641) |
Cash flows from financing activities: | |||
Redemption of Senior Notes and other long-term debt | (10,567) | (25,257) | (1,000) |
Redemption of 2018 Senior Notes | (1,000) | ||
Proceeds from Bank Credit Facility | 110,000 | 319,000 | 10,000 |
Repayment of Bank Credit Facility | (25,000) | (54,000) | (15,000) |
Deferred financing costs | (1,963) | (17,002) | |
Other deferred payments | (9,921) | ||
Payment of capital lease | (14,133) | (12,952) | (12,412) |
Employee stock transactions | (333) | ||
Net cash provided by (used in) financing activities | 48,083 | (193,211) | (18,412) |
Net increase (decrease) in cash, cash equivalents and restricted cash | (54,140) | 107,729 | |
Cash, cash equivalents and restricted cash: | |||
Balance, beginning of period | 141,162 | 33,433 | 33,433 |
Balance, end of period | 87,022 | 141,162 | 33,433 |
Parent | |||
Cash flows from operating activities: | |||
Net cash provided by (used in) operating activities | (828) | ||
Cash flows from financing activities: | |||
Capital contributions | 828 | ||
Net cash provided by (used in) financing activities | 828 | ||
Subsidiary Issuer | |||
Cash flows from operating activities: | |||
Net cash provided by (used in) operating activities | (95,960) | (193,088) | (30,245) |
Cash flows from investing activities: | |||
Exploration, development, and other capital expenditures | (1,614) | (13,404) | (260) |
Investments in subsidiaries | (1,580,833) | (1,316,588) | (577,055) |
Distributions from subsidiaries | 1,660,609 | 1,694,460 | 611,526 |
Net cash provided by (used in) investing activities | 78,162 | 364,468 | 34,211 |
Cash flows from financing activities: | |||
Redemption of Senior Notes and other long-term debt | (25,152) | ||
Redemption of 2018 Senior Notes | (1,000) | ||
Proceeds from Bank Credit Facility | 110,000 | 319,000 | 10,000 |
Repayment of Bank Credit Facility | (25,000) | (54,000) | (15,000) |
Deferred financing costs | (1,963) | (17,002) | |
Net cash provided by (used in) financing activities | 83,037 | (180,154) | (6,000) |
Net increase (decrease) in cash, cash equivalents and restricted cash | 65,239 | (8,774) | (2,034) |
Cash, cash equivalents and restricted cash: | |||
Balance, beginning of period | 13,541 | 22,315 | 24,349 |
Balance, end of period | 78,780 | 13,541 | 22,315 |
Guarantors | |||
Cash flows from operating activities: | |||
Net cash provided by (used in) operating activities | 512,956 | 442,890 | 204,419 |
Cash flows from investing activities: | |||
Exploration, development, and other capital expenditures | (380,622) | (227,228) | (132,317) |
Cash paid for acquisitions, net of cash acquired | (37,916) | 278,409 | (2,464) |
Proceeds from sale of other property and equipment | 5,369 | ||
Distributions from subsidiaries | 9 | 6,041 | |
Net cash provided by (used in) investing activities | (413,169) | 51,190 | (128,740) |
Cash flows from financing activities: | |||
Redemption of Senior Notes and other long-term debt | (10,567) | (105) | |
Other deferred payments | (9,921) | ||
Payment of capital lease | (14,133) | (12,952) | (12,412) |
Employee stock transactions | (333) | ||
Capital contributions | 1,350,086 | 1,301,876 | 550,555 |
Distributions to Subsidiary Issuer | (1,516,375) | (1,689,898) | (611,526) |
Net cash provided by (used in) financing activities | (201,243) | (401,079) | (73,383) |
Net increase (decrease) in cash, cash equivalents and restricted cash | (101,456) | 93,001 | 2,296 |
Cash, cash equivalents and restricted cash: | |||
Balance, beginning of period | 102,049 | 9,048 | 6,752 |
Balance, end of period | 593 | 102,049 | 9,048 |
Non-Guarantors | |||
Cash flows from operating activities: | |||
Net cash provided by (used in) operating activities | (22,435) | 13,643 | 1,879 |
Cash flows from investing activities: | |||
Exploration, development, and other capital expenditures | (81,173) | (282) | (22,600) |
Net cash provided by (used in) investing activities | (81,173) | (282) | (22,600) |
Cash flows from financing activities: | |||
Capital contributions | 229,919 | 14,712 | 26,500 |
Distributions to Subsidiary Issuer | (144,234) | (4,571) | (6,041) |
Net cash provided by (used in) financing activities | 85,685 | 10,141 | 20,459 |
Net increase (decrease) in cash, cash equivalents and restricted cash | (17,923) | 23,502 | (262) |
Cash, cash equivalents and restricted cash: | |||
Balance, beginning of period | 25,572 | 2,070 | 2,332 |
Balance, end of period | 7,649 | 25,572 | 2,070 |
LLC Bank Credit Facility | |||
Cash flows from financing activities: | |||
Repayment of Bank Credit Facility | (403,000) | (15,000) | |
LLC Bank Credit Facility | Subsidiary Issuer | |||
Cash flows from financing activities: | |||
Repayment of Bank Credit Facility | (403,000) | ||
Elimination | |||
Cash flows from investing activities: | |||
Investments in subsidiaries | 1,580,833 | 1,316,588 | 577,055 |
Distributions from subsidiaries | (1,660,609) | (1,694,469) | (617,567) |
Net cash provided by (used in) investing activities | (79,776) | (377,881) | (40,512) |
Cash flows from financing activities: | |||
Capital contributions | (1,580,833) | (1,316,588) | (577,055) |
Distributions to Subsidiary Issuer | 1,660,609 | 1,694,469 | 617,567 |
Net cash provided by (used in) financing activities | $ 79,776 | $ 377,881 | $ 40,512 |
Selected Quarterly Financial _3
Selected Quarterly Financial Data - Schedule Of Quarterly Financial Data (Details) - USD ($) $ / shares in Units, shares in Thousands, $ in Thousands | 3 Months Ended | 12 Months Ended | |||||||||
Dec. 31, 2019 | Sep. 30, 2019 | Jun. 30, 2019 | Mar. 31, 2019 | Dec. 31, 2018 | Sep. 30, 2018 | Jun. 30, 2018 | Mar. 31, 2018 | Dec. 31, 2019 | Dec. 31, 2018 | Dec. 31, 2017 | |
Quarterly Financial Information Disclosure [Abstract] | |||||||||||
Revenues | $ 233,240 | $ 228,857 | $ 286,810 | $ 178,713 | $ 258,664 | $ 282,868 | $ 203,906 | $ 145,850 | $ 927,620 | $ 891,288 | $ 412,828 |
Operating income | 46,970 | 52,883 | 94,872 | 18,369 | 73,973 | 91,361 | 39,211 | 48,584 | 213,094 | 253,129 | 45,300 |
Price risk management activities income (expense) | (59,508) | 43,760 | 29,990 | (109,579) | 256,917 | (53,330) | (91,176) | (51,976) | (95,337) | 60,435 | (27,563) |
Net income (loss) | $ 304 | $ 73,297 | $ 94,764 | $ (109,636) | $ 306,286 | $ 13,109 | $ (74,912) | $ (22,943) | $ 58,729 | $ 221,540 | $ (62,868) |
Net income (loss) per common share: | |||||||||||
Basic | $ 0.01 | $ 1.35 | $ 1.75 | $ (2.02) | $ 5.66 | $ 0.24 | $ (1.69) | $ (0.73) | $ 1.08 | $ 4.81 | $ (2.01) |
Diluted | $ 0.01 | $ 1.35 | $ 1.74 | $ (2.02) | $ 5.66 | $ 0.24 | $ (1.69) | $ (0.73) | $ 1.08 | $ 4.81 | $ (2.01) |
Weighted average common shares outstanding: | |||||||||||
Basic | 54,203 | 54,200 | 54,178 | 54,156 | 54,156 | 54,156 | 44,336 | 31,244 | 54,185 | 46,058 | 31,244 |
Diluted | 54,559 | 54,430 | 54,451 | 54,156 | 54,159 | 54,164 | 44,336 | 31,244 | 54,413 | 46,061 | 31,244 |
Supplemental Oil and Gas Disc_3
Supplemental Oil and Gas Disclosures - Schedule of Capitalized Costs Related to Oil, Natural Gas and NGL Activities and Related Accumulated Depletion and Amortization (Details) $ in Thousands | Dec. 31, 2019USD ($)$ / MBoe | Dec. 31, 2018USD ($)$ / MBoe |
Extractive Industries [Abstract] | ||
Proved properties | $ 4,066,260 | $ 3,629,430 |
Unproved oil and gas properties, not subject to amortization | 194,532 | 108,209 |
Total oil and gas properties | 4,260,792 | 3,737,639 |
Less: Accumulated depletion | (2,051,856) | (1,709,614) |
Net capitalized costs | $ 2,208,936 | $ 2,028,025 |
Depletion and amortization rate (Per Boe) | $ / MBoe | 18.05 | 17.07 |
Supplemental Oil and Gas Disc_4
Supplemental Oil and Gas Disclosures - Schedule of Capitalized Costs Related to Oil, Natural Gas and NGL Activities and Related Accumulated Depletion and Amortization (Parenthetical) (Details) - USD ($) $ in Thousands | Dec. 31, 2019 | Dec. 31, 2018 |
Capitalized Costs Relating To Oil And Gas Producing Activities By Geographic Area [Line Items] | ||
Unproved properties, not subject to amortization | $ 194,532 | $ 108,209 |
Mexico | ||
Capitalized Costs Relating To Oil And Gas Producing Activities By Geographic Area [Line Items] | ||
Unproved properties, not subject to amortization | $ 106,900 | $ 45,100 |
Supplemental Oil and Gas Disc_5
Supplemental Oil and Gas Disclosures - Additional Information (Details) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2019USD ($)MMBoe | Dec. 31, 2018USD ($)MMBoe | Dec. 31, 2017USD ($)MMBoe | |
Reserve Quantities [Line Items] | |||
Oil and gas asset retirement obligations | $ | $ 369,478 | $ 382,817 | $ 214,733 |
Percentage of proved oil, natural gas and NGL reserves attributable to all of oil and natural gas properties | 100.00% | 100.00% | 100.00% |
Proved reserves decrease | 10 | 51.1 | |
Decrease of production | 19 | 16.7 | 10.5 |
Revision to previous estimates | 9.7 | 5.1 | |
Estimated proved reserves from extensions and discoveries | 15.7 | 5.6 | 12.5 |
Purchases of estimated proved reserves | 62.8 | ||
Prescribed rate of discounted future net cash flows | 10.00% | ||
Gunflint Acquisition | |||
Reserve Quantities [Line Items] | |||
Purchases of estimated proved reserves | 3 | ||
Stone Energy Corporation | |||
Reserve Quantities [Line Items] | |||
Purchases of estimated proved reserves | 59.3 | ||
Whistler Energy II, LLC | |||
Reserve Quantities [Line Items] | |||
Purchases of estimated proved reserves | 3.5 |
Supplemental Oil and Gas Disc_6
Supplemental Oil and Gas Disclosures - Schedule of Costs Incurred in Oil, Natural Gas and NGL Property Acquisition, Exploration and Development Activities (Details) - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2019 | Dec. 31, 2018 | Dec. 31, 2017 | |
Property acquisition costs: | |||
Proved properties | $ 27,660 | $ 850,515 | $ 1,108 |
Unproved properties, not subject to amortization | 16,062 | 65,063 | 5,778 |
Total property acquisition costs | 43,722 | 915,578 | 6,886 |
Exploration costs | 209,161 | 93,780 | 82,887 |
Development costs | 292,547 | 215,467 | 114,846 |
Total costs incurred | $ 545,430 | $ 1,224,825 | $ 204,619 |
Supplemental Oil and Gas Disc_7
Supplemental Oil and Gas Disclosures - Schedule of Costs Incurred in Oil, Natural Gas and NGL Property Acquisition, Exploration and Development Activities (Parenthetical) (Details) - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2019 | Dec. 31, 2018 | Dec. 31, 2017 | |
Costs Incurred Oil And Gas Property Acquisition Exploration And Development Activities [Line Items] | |||
Exploration costs | $ 209,161 | $ 93,780 | $ 82,887 |
Mexico | |||
Costs Incurred Oil And Gas Property Acquisition Exploration And Development Activities [Line Items] | |||
Exploration costs | $ 74,200 | $ 16,900 | $ 22,800 |
Supplemental Oil and Gas Disc_8
Supplemental Oil and Gas Disclosures - Schedule of Estimated Proved Reserves at Net Ownership Interest (Details) | 12 Months Ended | ||
Dec. 31, 2019MBoeMMBoeMBblsMMcf | Dec. 31, 2018MBoeMMBoeMBblsMMcf | Dec. 31, 2017MBoeMMBoeMBblsMMcf | |
Reserve Quantities [Line Items] | |||
Total proved reserves, beginning balance | MMBoe | 51.1 | ||
Revision of previous estimates | MMBoe | (9.7) | (5.1) | |
Production | MMBoe | (19) | (16.7) | (10.5) |
Purchases of reserves | MMBoe | 62.8 | ||
Extensions and discoveries | MMBoe | 15.7 | 5.6 | 12.5 |
Total proved reserves, ending balance | MMBoe | 10 | 51.1 | |
Oil (MBbls) | |||
Reserve Quantities [Line Items] | |||
Total proved reserves, beginning balance | 112,539 | 72,804 | 72,366 |
Revision of previous estimates | (5,553) | 2,595 | (2,673) |
Production | (13,844) | (11,771) | (7,048) |
Purchases of reserves | 2,094 | 44,788 | |
Extensions and discoveries | 11,518 | 4,123 | 10,159 |
Total proved reserves, ending balance | 106,754 | 112,539 | 72,804 |
Total proved developed reserves | 72,016 | 85,530 | 37,460 |
Total proved undeveloped reserves | 34,738 | 27,009 | 35,344 |
Gas (MMcf) | |||
Reserve Quantities [Line Items] | |||
Total proved reserves, beginning balance | MMcf | 171,024 | 127,656 | 150,604 |
Revision of previous estimates | MMcf | (15,898) | (37,933) | (15,860) |
Production | MMcf | (23,306) | (22,771) | (16,308) |
Purchases of reserves | MMcf | 2,626 | 95,661 | |
Extensions and discoveries | MMcf | 21,552 | 8,411 | 9,220 |
Total proved reserves, ending balance | MMcf | 155,998 | 171,024 | 127,656 |
Total proved developed reserves | MMcf | 115,381 | 131,364 | 77,577 |
Total proved undeveloped reserves | MMcf | 40,617 | 39,660 | 50,079 |
NGL (MBbls) | |||
Reserve Quantities [Line Items] | |||
Total proved reserves, beginning balance | 10,696 | 6,547 | 6,236 |
Revision of previous estimates | (1,237) | 3,187 | 250 |
Production | (1,228) | (1,176) | (706) |
Purchases of reserves | 130 | 2,074 | |
Extensions and discoveries | 620 | 64 | 767 |
Total proved reserves, ending balance | 8,981 | 10,696 | 6,547 |
Total proved developed reserves | 6,733 | 8,104 | 3,315 |
Total proved undeveloped reserves | 2,248 | 2,592 | 3,232 |
Oil Equivalent (MBoe) | |||
Reserve Quantities [Line Items] | |||
Total proved reserves, beginning balance | MBoe | 151,739 | 100,625 | 103,702 |
Revision of previous estimates | MBoe | (9,440) | (539) | (5,067) |
Production | MBoe | (18,956) | (16,742) | (10,472) |
Purchases of reserves | MBoe | 2,662 | 62,806 | |
Extensions and discoveries | MBoe | 15,730 | 5,589 | 12,462 |
Total proved reserves, ending balance | MBoe | 141,735 | 151,739 | 100,625 |
Total proved developed reserves | MBoe | 97,979 | 115,528 | 53,704 |
Total proved undeveloped reserves | MBoe | 43,756 | 36,211 | 46,921 |
Supplemental Oil and Gas Disc_9
Supplemental Oil and Gas Disclosures - Schedule of Estimated Proved Reserves at Net Ownership Interest (Parenthetical) (Details) | 12 Months Ended | ||
Dec. 31, 2019MBoeMMBoe | Dec. 31, 2018MMBoe | Dec. 31, 2017MMBoe | |
Reserve Quantities [Line Items] | |||
Production | MMBoe | 19 | 16.7 | 10.5 |
Mexico | |||
Reserve Quantities [Line Items] | |||
Production | MBoe | 3 |
Supplemental Oil and Gas Dis_10
Supplemental Oil and Gas Disclosures (Unaudited) - Schedule of Standardized Measure of Discounted Future Net Cash Flows Related to Interest in Proved Oil, Natural Gas and NGL Reserves (Details) - USD ($) $ in Thousands | Dec. 31, 2019 | Dec. 31, 2018 | Dec. 31, 2017 | Dec. 31, 2016 |
Extractive Industries [Abstract] | ||||
Future cash inflows | $ 7,151,875 | $ 8,654,631 | $ 4,308,863 | |
Future costs: | ||||
Production | (1,633,432) | (1,740,850) | (815,509) | |
Development and abandonment | (1,464,270) | (1,349,005) | (823,164) | |
Future net cash flows before income taxes | 4,054,173 | 5,564,776 | 2,670,190 | |
Future income tax expense | (662,317) | (862,473) | 0 | |
Future net cash flows after income taxes | 3,391,856 | 4,702,303 | 2,670,190 | |
Discount at 10% annual rate | (854,261) | (1,362,057) | (862,521) | |
Standardized measure of discounted future net cash flows | $ 2,537,595 | $ 3,340,246 | $ 1,807,669 | $ 1,336,035 |
Supplemental Oil and Gas Dis_11
Supplemental Oil and Gas Disclosures (Unaudited) - Schedule of Base Prices Used in Determining Standardized Measure (Details) | 12 Months Ended | ||
Dec. 31, 2019$ / bbl$ / Mcf | Dec. 31, 2018$ / bbl$ / Mcf | Dec. 31, 2017$ / bbl$ / Mcf | |
Oil | |||
Discounted Future Net Cash Flows Relating To Proved Oil And Gas Reserves [Line Items] | |||
Base price | 61.01 | 69.42 | 51.36 |
Natural Gas | |||
Discounted Future Net Cash Flows Relating To Proved Oil And Gas Reserves [Line Items] | |||
Base price | $ / Mcf | 2.59 | 3.08 | 3.20 |
NGL | |||
Discounted Future Net Cash Flows Relating To Proved Oil And Gas Reserves [Line Items] | |||
Base price | 26.17 | 29.50 | 24.64 |
Supplemental Oil and Gas Dis_12
Supplemental Oil and Gas Disclosures (Unaudited) - Schedule of Principal Changes in Standardized Measure of Discounted Future Net Cash Flows (Details) - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2019 | Dec. 31, 2018 | Dec. 31, 2017 | |
Extractive Industries [Abstract] | |||
Standardized measure, beginning of year | $ 3,340,246 | $ 1,807,669 | $ 1,336,035 |
Sales and transfers of oil, net gas and NGLs produced during the period | (665,226) | (727,969) | (288,942) |
Net change in prices and production costs | (849,696) | 1,578,330 | 555,100 |
Changes in estimated future development costs | (75,564) | 32,328 | (156,282) |
Previously estimated development costs incurred | 117,049 | 45,937 | 146,687 |
Accretion of discount | 392,526 | 180,767 | 133,603 |
Net change in income taxes | 129,590 | (585,017) | |
Purchases of reserves | 75,009 | 943,519 | |
Extensions and discoveries | 306,515 | 148,068 | 328,565 |
Net change due to revision in quantity estimates | (199,576) | 190,853 | (113,629) |
Changes in production rates (timing) and other | (33,278) | (274,239) | (133,468) |
Standardized measure, end of year | $ 2,537,595 | $ 3,340,246 | $ 1,807,669 |